Listing of the Company s Shares on Oslo Axess

PROSPECTUS Crudecorp ASA Listing of the Company s Shares on Oslo Axess This Prospectus does not constitute an offer to buy, subscribe or sell the securities described herein. This Prospectus serves as a listing prospectus as required by applicable laws and no securities are being offered or sold pursuant to this Prospectus. 13 June 2012 Managed by:

IMPORTANT NOTICE C RUDECORP ASA L ISTING ON O SL O A XESS This prospectus (the Prospectus ) has been prepared by Crudecorp ASA ( Crudecorp or the Company ) in connection with the Listing for the sole purpose of enabling prospective investors to consider the purchase of the Shares described herein. The Prospectus has been prepared to comply with chapter 7 of the Securities Trading Act of the Kingdom of Norway of June 29, 2007 No. 75 (the Securities Trading Act ) and the related regulations, including the European Commission Regulation EC/809/2004. The Prospectus has been reviewed and approved by the Norwegian Financial Supervisory Authority. The Prospectus has been prepared in English language only. The Prospectus has not been passported into any other country in the European Economic Area. The Company is not taking any action to permit a public Listing of the Shares in any jurisdiction outside of Norway. The Shares have not been and will not be registered under the United States Securities Act of 1933 (the US Securities Act ), or any securities laws of any state in the United States. Accordingly, the Shares may not be Listed or sold within the United States, except in transactions exempt from registration under the US Securities Act, or in any other jurisdiction in which it would not be permissible to List the shares. All Listings and sales outside the United States will be made in reliance on Regulation S under the US Securities Act. This Prospectus may not be used for the purpose of, and does not constitute, a Listing to sell or issue, or an invitation to buy or subscribe for, any securities in or into Australia, Canada, Japan, the United States or any other jurisdiction in which it would not be permissible to do so. The information contained herein is only updated as of the date hereof and subject to change, completion or amendment without notice. In accordance with the Securities Trading Act Section 7-15, any new factor, significant error or inaccuracy that might have an effect on the assessment of the Listing and emerges between the date of the Prospectus and the Listing will be included in a supplement to the Prospectus. Neither the publication nor distribution of this Prospectus shall under any circumstances imply that the information herein is correct as of any date subsequent to the date of the Prospectus. All inquiries relating to this Prospectus should be directed to Swedbank First Securities (the Manager ). Copies of this Prospectus can be obtained from the Company or the Manager. The contents of this Prospectus are not to be construed as legal, financial, business or tax advice. Prospective investors should consult their own legal, business and tax advisors as to legal, business and tax matters. In making a decision on an investment in the Company, investors must rely on their own examination of Crudecorp including the merits and risks involved. For a description and discussion of risk factors relevant to an investment in the Company, see Risk factors. Prospective investors should inform themselves of any legal requirements for, and any tax consequences of, the purchase, holding, transfer, redemption or other disposal of the Shares in their country. Neither the Company nor the Manager makes any representation with respect to the legality of any investor s purchase of Shares. Any disputes that might arise regarding this Prospectus or the Listing are subject to Norwegian law and the exclusive jurisdiction of the Norwegian courts. 1

TABLE OF CONTENTS IMPORTANT NOTICE...1 1. Summary...6 1.1 About Crudecorp... 6 1.2 Board, senior management and employees... 8 1.3 Selected consolidated financial information... 9 1.4 Share capital and major shareholders... 12 1.5 Related party transactions... 13 1.6 The Listing... 13 1.7 Reasons for the Listing... 13 1.8 Advisors... 14 1.9 Summary of risk factors... 14 1.10 Expenses... 15 1.11 Documents on display... 15 2. Risk factors...16 2.1 Risks relating to Crudecorp, the general market and the industry in which the Company operates... 16 2.2 Risk factors relating to Crudecorp s financing... 23 2.3 Risk factors relating to the Company s Shares... 23 3. Responsibility for the Prospectus...25 3.1 Statement of responsibility... 25 4. The Listing...26 4.1 Reasons for the listing...26 4.2 The Shares being admitted to listing... 26 4.3 Admission to trading and dealing arrangements... 26 4.4 Additional information... 27 4.5 Interest of natural and legal persons involved... 27 4.6 Expenses... 27 5. Presentation of Crudecorp...28 5.1 Overview... 28 2

5.2 Incorporation and offices... 28 5.3 Historical development... 28 5.4 Organisation... 29 5.5 Vision, goal and strategy... 30 5.6 Business overview... 31 5.7 Operations... 34 5.8 Reserves and resources... 40 5.9 Sources of information... 44 5.10 Development plan...44 5.11 The production process... 46 5.12 Principal markets... 47 5.13 Research and development... 48 5.14 Patents and licenses etc....48 5.15 Material contracts... 48 5.16 Other projects... 48 5.17 Regulatory issues... 48 6. Market overview...50 6.1 Oil market fundamentals Supply vs. demand... 50 6.2 Oil price... 51 6.3 North America - Oil market fundamentals... 54 7. Board of Directors, senior management and corporate governance...58 7.1 Board of Directors... 58 7.2 Management... 59 7.3 Board of Directors and senior management... 60 7.4 Remuneration, benefits, pension, etc.... 62 7.5 Shares and stock options held by members of the Board of Directors and senior management... 63 7.6 Employees... 63 7.7 Corporate governance... 64 7.8 Related Party Transactions... 64 3

8. Financial information...65 8.1 Overview and financial statements Crudecorp... 65 8.2 Historical financial information... 66 8.3 Comments to the historic financial information... 70 8.4 Changes in equity... 72 8.5 Property, plant and equipment... 74 8.6 Investments... 74 8.7 Capital resources, capitalisation and indebtedness... 76 8.8 Significant changes in financial and trading position... 78 8.9 Statutory auditors... 78 9. Share capital and shareholder information...79 9.1 Description of the Shares and share capital... 79 9.2 Notifiable shareholdings... 80 9.3 Differences in voting rights; shareholder agreements... 81 9.4 Shareholders with direct or indirect control... 81 9.5 Arrangements which may cause change in control... 81 9.6 Limitations on the right to own and transfer Shares... 81 9.7 Dividend policy and payment of dividends... 81 9.8 General meetings... 81 9.9 Voting rights... 82 9.10 Additional issuances and preferential rights... 83 9.11 Regulation of dividends... 83 9.12 Minority rights... 84 9.13 Transactions with related parties... 84 9.14 Rights of redemption and repurchase of Shares... 84 9.15 Liability of directors and chief executive officer... 85 9.16 Distribution of assets on liquidation... 85 9.17 Summary of the Company s Articles of Association... 86 9.18 Certain aspects of applicable law... 86 10. Legal and arbitration proceedings...91 4

11. Taxation issues...92 11.1 Tax consequences related to the ownership and realisation of shares - Norwegian Shareholders... 92 11.2 Tax consequences related to the ownership and realisation of shares Foreign Shareholders... 94 12. Additional information...97 12.1 Documents on display... 97 12.2 Third party statements... 97 12.3 Statement regarding expert opinions... 97 12.4 Cross reference list... 97 13. Cautionary note regarding forward-looking statements...99 14. Definitions...100 Appendix 1 Articles of Association...1 Appendix 2 CPR Executive Summary Report...3 Appendix 3 Crudecorp ASA Quarterly Report Q1 2012...17 Appendix 4 Crudecorp ASA Annual Report 2011...24 Appendix 5 Crudecorp ASA Annual Report 2010...53 Appendix 6 Crudecorp ASA Annual Report 2009...83 5

1. Summary The following summary should be read as an introduction to the Prospectus and in conjunction with it, and is qualified in its entirety by the more detailed information appearing elsewhere in this Prospectus and in the appendices to this Prospectus. Any decision to invest in Crudecorp should be based on a consideration of the Prospectus as a whole. The Prospectus has been prepared in the English language only. Where a claim relating to the information contained in the Prospectus is brought before a court, the plaintiff investor might under the applicable legislation have to bear the costs of translating the Prospectus before the legal proceedings are initiated. Civil liability attaches to those persons who have tabled the summary including any translation thereof, and applied for its notification, but only if the summary is misleading, inaccurate or inconsistent when read together with the other parts of this Prospectus. For the definitions of terms used throughout this Prospectus, see Section 14, Definitions. 1.1 About Crudecorp 1.1.1 Overview Crudecorp is a public limited company established under the laws of Norway on 29 January 2007, with registration number 990 904 871. The Company s registered business address is Skagen 27, P.O. Box 896, N-4004 Stavanger, Norway. The Company s telephone number is +47 91 53 23 93 and its website is www.crudecorp.com. The address of the Company s principal place of business in California is 4900 California Avenue, Tower B-210, Bakersfield, California 93309, USA with telephone number +1 661 377 1875. 1.1.2 History The table below sets out the most significant events in Crudecorp s history. Time H2 2005 H1 2007 H1 2007 H1 2008 H2 2008 H2 2008 H2 2010 Event STL Energy LLC was incorporated in the United States The Company was incorporated in Norway as a private limited liability company STL Energy LLC and Crudecorp AS merged Rights to several orphaned wells in Texas and oil and gas leases in Kentucky was acquired Acquired a 75% Working Interest and 58.5% Net Revenue Interest in Chico Martinez. The oil and gas leases in Kentucky were divested Increased to 90% Working Interest and 74% Net Revenue Interest in Chico Martinez Acquired a 15.34% Mineral Interest in Chico Martinez 6

H2 2010 H1 2011 H1 2011 H2 2011 H1 2012 H2-2012 Raised equity of NOK 27 million in a private placement Raised equity of NOK 100 million in a private placement The Company was transformed to a public limited company Raised equity of NOK 70.5 million in a private placement Increased to 17.25% Mineral Interest in Chico Martinez Acquired a 90% interest in the southwest quadrant of Section 27, a property adjacent to the Chico Martinez Field. 1.1.3 Shares and articles of association As at the date of this Prospectus, the registered share capital of the Company is NOK 1,823,033.58, divided on 91,151,679 Shares, each with a par value of NOK 0.02. All Shares are vested with equal shareholder rights in all respects. The Company s Articles of Association do not contain any provisions imposing limitations on the ownership or the tradability of the Shares. 1.1.4 Business Overview Crudecorp is an international independent oil and gas exploration and production company engaged in the acquisition, development and operation of oil and natural gas properties in the United States. The Company aims to develop a business model which can generate significant cash surpluses through acquisitions of producing assets or assets which are close to producing. The Company s exploration activities will primarily be associated with further development of existing assets. 1.1.5 Operations Crudecorp owns a 90% Working Interest in Chico Martinez, located in the San Joaquin valley in California, United States, and is in the process of developing production from the upper reservoir (Etchegoin) and exploring the potential for additional reserves from the lower formations in its properties. The Company has also acquired 17.25% of the Mineral Interests for the lease. Production in Chico Martinez was reportedly started in 1927. According to the California Department of Oil and Gas' (DOGGR) records of production, a total of 599,000 bbl of oil have been produced from the field through 31 October 2011. Therefore, the oil recovery percentage is approximately 1.1% using the most likely Stock Tank Oil Initially In Place (STOIIP) of 50.5 MMBbl. The Group initially plans to develop approx. 28% of the 50.5 MMBbl most likely STOIIP in Chico Martinez through a 3 phased development plan from 2011 through 2014. Following the initial 3 phase development programme, the Group will decide on a development strategy for the remaining STOIIP. Crudecorp engaged Gaffney, Cline & Associates (GCA) to prepare a Competent Person s Report. GCA also reviewed the production profiles and project economics for the first 3 development phases planned. Based on this work, GCA estimated gross field 1P reserves of 3.35 MMBbl and 2P reserves of 4.79 MMBbl, on a 100% basis. These volumes represent incremental increased recovery for the field in the order of 6.6% and 9.5% respectively. 1.1.6 Net R evenue I nter est The Oil and Gas lease or Working Interest (of which the Company owns 90%) acquires a right to 7

explore and produce the oil and gas resources in return for paying a Royalty to the Mineral Rights owners. The Company s Working Interest in Chico Martinez (Section 35 and parts of Section 27) are sub-leases of an original lease, covering Sections 21, 27 and 35. The Royalty structure is therefore as follows; - 16.67% to Mineral Interest owners (The company owns 17.25% of the Mineral Interests) - 5.0% to Original Lease Holder (OLH), less 21.67% of expenses on fuel gas, water and other consumables to generate steam. The Net Royalty paid will in other words vary between 13.79% and 18.79%, depending on how much is spent on fuel and consumables for generating steam. Based on these various input parameters for gas consumption, GCA estimated the Net Revenue Interest to the Company to be 77.2%, which is the basis used in this document. 1.1.7 Per mits The Company holds all permits required for its current operations but will require a number of new permits in order to carry out future infrastructure enhancements and drilling operations. For more details on and the Company s permits, see Section5.7.3. 1.1.8 Legal structure The legal structure of the Group is illustrated in the following figure (all subsidiaries are whollyowned): Crudecorp ASA Norway CMO Inc USA Crudecorp Branch USA CMO AS Norway For more details on the entities of the Group, see Section 5.4.2. 1.2 Board, senior management and employees 1.2.1 Board of Directors The Board of Directors of the Company consists of Sigurd Aase, (Chairman), Espen Fjogstad, Stig M. Herbern, Silje Veen and Sissel K. Hegdal. 1.2.2 Senior management The senior management consists of Gunnar Hviding (CEO), Anniken Landré Bjerke (CFO), Håvard Rød (COO), Jan Terje Lea (CFO - CMO, Inc) and Steven Gregory (Operations Manager, US). 1.2.3 E mployees The Group has nine employees, of which three are located in Norway and six in the United States. 8

1.3 Selected consolidated financial information 1.3.1 Consolidated Income Statement Below is the audited income statement for the Company for the accounting year 2011. The financial information is presented in accordance with IFRS as adopted by EU and is derived from the Company s historical financial statements provided in Section 8.2 of this Prospectus. Limited Review Unaudited Audited Q1 2012 Q1 2011 2011 2010 2009 2009 IFRS IFRS IFRS IFRS IFRS NGAAP Group Group Group Group Group Company US D (NOK) Operating revenues 319 937 196 729 732 868 308 780 89 828 3 651 000 Other revenues 17 276 2 838 12 261 4 963 119 381 749 901 Total revenues 337 213 199 567 745 129 597 158 209 209 4 400 901 Production cost 339 072 159 923 670 990 311 860 34 690 0 Labour cost 352 185 273 208 1 537 095 802 229 747 559 1 499 347 DD&A 493 075 268 985 886 885 63 856 152 292 10 300 Other opex 273 936 366 768 1 331 431 613 276 592 282 2 476 972 Total costs 1 458 268 1 068 884 4 426 401 1 791 221 1 526 823 3 986 619 Operating profit/loss -1 121 055-869 317-3 681 273-1 477 478-1 317 615 414 282 Net financial items -1 732 953-630 444 1 900 071 239 273-203 009 1 668 526 Profit before tax -2 854 008-1 499 761-1 781 202-1 238 205-1 520 624 2 082 808 Income taxes 0 0 0 0 0 0 Profit after tax -2 854 008-1 499 761-1 781 202-1 238 205-1 520 624 2 082 808 Figures in 2009 are from the Annual Report 2010 IFRS with comparative figures for 2009. NGAAP figures provided for 2009 are in NOK. 1.3.2 Consolidated balance sheets - summary Below is the audited balance sheet for the Company for the accounting year 2011. The financial information is presented in accordance with IFRS and is derived from the Company s historical financial statements provided in Section 8.2 of this Prospectus. 9

Limited Review Unaudited Audited Q1 2012 Q1 2011 2011 2010 2009 2009 IFRS IFRS IFRS IFRS IFRS NGAAP Group Group Group Group Group Company USD (NOK) Fixed assets 20 483 711 4 127 705 15 559 364 1 618 527 1 212 7 000 Oilfield production rights 7 924 936 7 998 331 7 464 281 7 457 204 6 989 234 46 513 374 Other non-current assets 1 074 849 253 586 253 586 0 0 8 949 974 Total non-current assets 29 483 496 12 379 622 23 277 231 9 075 731 6 990 445 55 470 348 Other current assets 671 136 385 422 686 424 520 422 104 720 334 568 Cash and cash equivalents 8 574 763 17 053 369 14 757 306 3 510 943 7 088 420 40 517 723 Total current assets 9 245 899 17 438 791 15 443 730 4 031 365 7 193 141 40 852 291 Total assets 38 729 395 29 818 413 38 720 960 13 107 096 14 183 586 93 322 639 Shareholder s equity 35 724 304 27 905 199 36 243 986 11 413 586 8 021 765 54 604 127 Long term debt 1 726 942 1 533 792 1 674 642 1 511 324 6 037 340 0 Other non-current liabilities 0 0 0 0 0 0 Non-current liabilities 1 726 942 1 533 792 1 674 642 1 511 324 6 037 340 41 014 570 Short term debt 1 278 149 379 421 802 331 182 186 124 481 703 942 Other current liabilities 0 0 0 0 0 0 Current liabilities 1 278 149 379 421 802 331 182 186 124 481 703 942 Total equity & liabilities 38 729 395 29 818 413 38 720 960 3 107 096 14 183 586 96 322 639 Figures in 2009 are from the Annual Report 2010 IFRS with comparative figures for 2009. NGAAP figures provided for 2009 are in NOK. 1.3.3 Significant changes and trend information There have not occurred any significant changes in the financial or trading position of the Company since the last audited financial information has been published and until the date of this Prospectus. 1.3.4 Capitalization and indebtedness (unaudited) CAPITALIZATION PER 31 MARCH 2012 (USD) 31 March 2012 Total current debt 1,278,000 Guaranteed 0 Secured 0 Unguaranteed/unsecured 1,278,000 Total Non-current debt ( excluding current portion of long term debt) 1,727,000 Guaranteed (description of the types of guarantees 0 Secured ( description of the assets secured) 0 Unguaranteed/ unsecured 1,727,000 10

Shareholder s equity a Share Capital 320,000 b Legal reserves 42,486,000 c Other reserves 0 Total 42,806,000 A. Cash 8,575,000 B. Cash equivalents (detail) 0 C. Trading securities 0 D. Liquidity (A+B+C) 8,575,000 E. Current financial receivables 671,000 F. Current bank debt 0 G. Current portion of non-current debt 0 H. Other current financial debt 0 I. Current financial debt (F+G+H) 0 J. Net current financial indebtedness (I-E-D) -9,246,000 K. Non-current bank loans 0 L. Bond issues 0 M. Other non-current loans 1,727,000 N. Non-current financial debt (K+L+M) 1,727,000 O. Net financial indebtedness (J+N) -7,519,000 In connection with the overdraft facility from Sandnes Sparebank of NOK 10 million, Sandnes Sparebank has mortgage security in inventory, factoring and operating equipment of NOK 10,000 (ten thousand) each. There have been no significant changes in the Company s capitalization and indebtedness since 31 March 2012. 11

1.3.5 Changes in equity The table below gives a summary of the statement of changes in shareholders equity the past three accounting years and the most recent interim period. Share Capital Share Premium Retained Earnings Sum Equity Equity 1 January 2009 37 049 3 944 876-3 584 332 397 593 This year's result -1 520 624-1 520 624 Translation diffrences 7 028 153 726 31 812 192 566 Transactions with owners IFRS 2 option cost 4 842 4 842 Debt conversion 9 187 1 828 172 1 837 359 Share issue 39 500 7 070 529 7 110 029 Transfer from share premium -3 637 589 3 637 589 - Sum transactions with owners 48 687 5 261 112 3 642 431 8 952 230 Equity 31 December 2009 92 764 9 359 714-1 430 713 8 021 765 This year's result -1 238 205-1 238 205 Translation diffrences -1 750-58 737-32 475-92 962 Transactions with owners IFRS 2 option cost 2 957 2 957 Share Issue 20 978 4 699 054 4 720 032 Transfer from share premium -1 430 713 1 430 713 - Sum transactions with owners 20 978 3 268 341 1 433 670 4 722 989 Equity 31 December 2010 111 992 12 569 318-1 267 723 11 413 586 This year's result - - -1 781 202-1 781 202 Translation diffrences -12 070 810 496-2 710 810-1 912 384 Transactions with owners IFRS 2 option cost 6 899 6 899 Bonus Issue 114 462-114 462 - Share Issue 89 824 29 832 581 29 922 407 Share Issue Cost -1 466 375-1 466 375 Transfer from share premium -1 267 723 1 267 723 - Sum transactions with owners 204 287 26 990 919 1 267 723 28 462 931 Equity 31 December 2011 304 209 40 431 789-4 492 012 36 243 986 Result of Q1 2012-2 854 008-2 854 008 Comprehensive income Q1 2012 263 623 263 623 Translation diffrences 15 998 2 054 703 2 070 701 Equity per 31.03.2012 320 207 42 486 492-7 082 399 35 724 302 1.4 Share capital and major shareholders As of 6 June 2012 the Company had 115 shareholders, of whom 109 (94.8%) were Norwegian and 6 (5.2%) were non-norwegian, registered in the VPS. The 20 largest shareholders and their shareholdings as per 6 June 2012 are listed below: 12

No. of Shares Ownership (%) YMIR ENERGY AS 37 300 792 40,92 % VICTORY LIFE 11 829 201 12,98 % SYNESI AS 7 045 999 7,73 % XFILE AS 4 750 500 5,21 % VEEN EIENDOM A/S 3 160 006 3,47 % PEBRIGA AS 2 999 142 3,29 % CIVES AS 2 951 900 3,24 % TIME TRADER AS 2 827 708 3,10 % SANDNES INVESTERING AS 1 999 950 2,19 % A/S MERITUM 1 401 858 1,54 % RAGNAR ZELOW LUNDQUIST 1 022 600 1,12 % MEPS AS 1 000 000 1,10 % A/S TERMES 981 329 1,08 % REIDAR BRUMER BRATVOLD 728 000 0,80 % SIRIUS AS 700 000 0,77 % SMH MANAGEMENT A/S 605 700 0,66 % ZELOW INVEST AS 523 200 0,57 % KAPITA AS 500 000 0,55 % HÅVARD RØD 422 499 0,46 % KLØVNINGEN AS 400 000 0,44 % Total 20 largest Shareholders 83 150 384 91,22 % Others 8 001 295 8,78 % Total 91 151 679 100,00 % 1.5 Related party transactions Crudecorp has entered into a loan agreement whereby certain shareholders have provided a loan to the Company. See Section 7.8 of this Prospectus. 1.6 The Listing At the date of the Prospectus none of the Company s Shares are listed on any regulated market, and no application for Listing of the Shares on a regulated market has been filed, other than the application for Listing as described herein. On 14 May 2012 the Company filed for Listing on Oslo Axess. Listing of the Shares was approved by the board of directors of Oslo Stock Exchange in its meeting on 13 June 2012. The first day of Listing is expected to be 15 June 2012. The ticker code will be "CRUDE". 1.7 Reasons for the Listing Crudecorp is seeking the Listing to (i) facilitate the potential raising of capital for the Company s future projects; (ii) increase the Company s visibility and credibility in both the financial markets and the industry market; (iii) create a liquid market for the Company s shares which already has seen a significant trade and (vi) provide an exit opportunity for the current shareholders. 13

1.8 Advisors Swedbank First Securities (the Manager ) has acted as financial advisor in connection with the Listing. Schjødt has been engaged by the Company as legal advisor in connection with the Listing. The Company s statutory auditor is PricewaterhouseCoopers AS. 1.9 Summary of risk factors A number of risk factors may have a material adverse effect on Crudecorp, as well as on the trading value of the Shares. Below is a brief summary of the risk factors described in Section 2 (Risk Factors). Neither this summary nor the risks described in Section 2 (Risk Factors) are exhaustive and other risks not discussed herein may also affect Crudecorp. 1.9.1 R isks relating to C rudecor p, the general mar ket and the industr y in which the C ompany oper ates Crudecorp s success is dependent on its ability to appraise, find, acquire, develop and commercially produce oil and gas reserves that are economically recoverable Reserves and resources information represents estimates which may be inaccurate or incorrect Report of reserves and resources Exploration projects do not necessarily result in a profit on the investment or the recovery of costs Crudecorp is subject to risks associated with future decommissioning liabilities Substantial investments will be necessary in the future oil and gas prices may not remain at their current levels Changes in the legislative and fiscal framework may affect profitability Legislative risk related to drilling, steaming and production permits, e.g. drilling moratoriums or withdrawal of permits related to conditions outside the company s control Crudecorp is subject to environmental and HSE risks Risks of equipment breakdown or process upsets The oil and gas industry is highly competitive Risks associated with third party processing and export infrastructure Unexpected shutdowns may occur Crudecorp is dependent on attracting and retaining personnel Production and expected production ramp up is concentrated on one field Risk related to claims from neighbours, farming community or other third parties Risk related to availability of supplier s capacity and availability of manpower, supplies and equipment Risks related to geology, including but not limited to risk of higher operating costs, lower production and underground damage Risks of leakage of steam to surface and resulting accidents or withdrawal of permits as a result of faulty well construction, unknown geological phenomena or operator and planning errors Risks of theft, sabotage or other wilful damage Risk of earthquake Risks associated with labour disputes Risks associated with legal disputes Risk of damaged equipment and insurance policies Potential liability for the acts and omissions of oil field services providers Risks related to debt arrangements 14

Risk associated with water supply. 1.9.2 R isk factor s r elating to C r udecor p s financing Financial liquidity risk Risk associated with exchange rate fluctuations 1.9.3 R isk factor s relating to the C ompany s Shar es Volatility of share price Liquidity of the Shares Dilution Additional risk for holders of Company s Shares that are registered in a nominee account The transfer of Shares is subject to restrictions 1.10 Expenses Cost attributable to the Listing will be borne by the Company. The total costs of the Listing are expected to amount to approximately NOK 4 100 000, which includes costs related to fees to the Manager, Oslo Stock Exchange, printing and distribution of this Prospectus, costs to legal advisors, the Company s auditor, the due diligence lawyers and auditors as well as fees to the Financial Supervisory Authority. 1.11 Documents on display For the life of this Prospectus the following documents (or copies thereof) may be inspected at the offices of the Company at Skagen 27, 4006 Stavanger, Norway. The memorandum and articles of association Crudecorp Q1 2012 report Crudecorp Annual report 2011 Crudecorp Annual report 2010 Crudecorp Annual report 2009 CMO, Inc Annual report for 2010 and 2011 Competent Person s Report on the Oil and Gas Assets of Chico Martinez Field of Crudecorp as at October 31, 2011, by Gaffney, Cline and Associates 15

2. Risk factors When assessing the Company and its business, investors should carefully consider all the information contained in this Prospectus and in particular the following risk factors, which may affect some or all of the Company's activities and the industry in which the Company operates. An investment in the Company is suitable only for investors who understand the risk factors associated with this type of investment and who can afford a loss of all or part of their investment. Before deciding whether or not to invest in the Company, an investor should consider carefully all of the information set forth in this Prospectus and in particular, the specific risk factors set out below. If any of the following risks actually materialise, the Company's business, financial position and operating results could be materially and adversely affected. The order in which risk factors appear is not intended as an indication of the relative weight or importance thereof. 2.1 Risks relating to Crudecorp, the general market and the industry in which the Company operates 2.1.1 Crudecorp s success is dependent on its ability to appraise, find, acquire, develop and commercially produce oil and gas reserves that are economically recoverable Crudecorp s long-term commercial success is dependent on its ability to find, appraise, acquire, develop and commercially produce oil and gas reserves. Crudecorp must continually locate and develop or acquire new reserves to replace its existing reserves that are being depleted by production. Significant expenditure is required to establish the extent of oil and gas reserves through seismic and other surveys, as well as drilling, and there can be no certainty that oil and gas reserves for commercial development will be found. There are many reasons why Crudecorp may not be able to find or acquire oil and gas reserves or develop them for commercially viable production. For example, Crudecorp may be unable to negotiate commercially reasonable terms for its acquisition, exploration, development or production activities. Factors such as adverse weather conditions, natural disasters, equipment or services shortages, procurement delays or difficulties arising from the political, environmental and other conditions in the areas where the reserves are located or through which Crudecorp s products are transported may increase costs and make it uneconomical to develop potential reserves. Moreover, Crudecorp is dependent on the competence and judgment of third-party operators in relation to the development of reserves where it is not itself the operator. 2.1.2 Reserves and resources information represents estimates which may be inaccurate or incorrect The process of estimating oil and gas reserves and the cash flows that may be derived from them is very complex. The reserves data and associated cash flow information relating to the Crudecorp set out in this Prospectus are estimates only. In general, estimates of the quantity and value of economically recoverable oil and gas reserves, and the possible future net cash flows are based upon a number of variable factors and assumptions, such as historic production rates, ultimate reserves recovery, interpretation of geological and geophysical data, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, continuity of current fiscal policies and regulatory regimes, future oil and gas prices, operating costs, development and production costs, export infrastructure access and tariff costs and work over and remedial costs, all of which may vary materially from actual results. Estimates are also to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and gas reserves attributable to a particular group of properties, the 16

classification of such reserves based on risk of recovery and estimates of expected future net revenues prepared by different engineers, or by the same engineers at different times may vary. As a result, the estimates of Crudecorp s reserves may require substantial upward or downward revisions if subsequent drilling, testing and production reveal differences. Any downward adjustment could indicate lower future production and thus adversely and materially affect Crudecorp s financial condition, future prospects and market value. Furthermore, a decline in Crudecorp s reserves may materially affect its ability to raise or access sufficient capital for its future operations. 2.1.3 Report of reserves and resources In this Prospectus, as permitted by the Oslo Stock Exchange (Circular 9/2009), the standards applied by the Petroleum Resources Management System published by the Society of Petroleum Engineers / World Petroleum Council / American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) in March 2007 ( SPE PRMS ), the Norwegian Petroleum Directorate categorization system and Canadian National Instrument 51 101, are applied with respect to estimates of Crudecorp s reserves and resources (see Section 5.8). Under SPE PRMS standards proved reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. Probable reserves are more difficult to determine than proved reserves and involve a greater risk that they are not actually recovered. Under the SPE PRMS standards, probable reserves are those unproved additional reserves that analysis of geological and engineering data suggests are less likely to be recovered than proved reserves, but more certain to be recovered than possible reserves. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserve. There is a greater risk that probable reserves will not actually be recovered as compared to proved reserves. Under SPE PRMS standards, contingent resources are those deposits that are estimated, on a given date, to be potentially recoverable from known accumulations by the application of development projects, but that are not currently considered commercially recoverable due to one or more contingencies. The resources may not be considered commercially recoverable for a variety of reasons, including, but not limited to, the high costs involved in recovering the resources, the price of oil at the time, the availability of resources and other development plans that may be in place. By contrast, prospective resources are those deposits that are estimated, on a given date, to be potentially recoverable from undiscovered accumulations. Estimates of contingent and prospective resources are uncertain and may change materially with time, and there can be no guarantee that Crudecorp will be able to develop these resources commercially. 2.1.4 Exploration projects do not necessarily result in a profit on the investment or the recovery of costs Exploration activities are capital intensive and inherently uncertain in their outcome. Crudecorp s future oil and gas exploration projects may involve unprofitable efforts, either from dry wells or from wells that are productive but do not produce sufficient net revenues to return a profit after development, operating and other costs. Completion of a well does not guarantee a profit on the investment or recovery of the costs associated with that well. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating 17

conditions may adversely and materially affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or adverse geological conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and may adversely and materially affect Crudecorp s revenues and cash. 2.1.5 Crudecorp is subject to risks associated with future decommissioning liabilities Crudecorp has in the past, through its licence interests, assumed certain obligations in respect of the decommissioning of its fields and related infrastructure and is expected to assume additional decommissioning liabilities in the future. These liabilities are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and require Crudecorp to make provisions for and/or underwrite the liabilities relating to such decommissioning. It is difficult to accurately forecast the costs that Crudecorp will incur in satisfying its decommissioning obligations. When its decommissioning liabilities crystallize, Crudecorp will normally be jointly and severally liable for them with other former or current partners in the field. In the event that other partners default on their obligations, Crudecorp will remain liable and its decommissioning liabilities could be magnified significantly through such default. Any significant increase in the actual or estimated decommissioning costs that Crudecorp incurs may adversely affect its financial condition. 2.1.6 Substantial investments will be necessary in the future Crudecorp will be required to make substantial capital expenditures for the acquisition, exploration, development and production of oil and gas reserves in the future. Such capital expenditures could be covered by revenues, new and existing equity or by obtaining new debt. If Crudecorp s revenues decline, if the Company is unable to attract investors to increase the Company s equity, or if new debt arrangements are not accessible (or only on unattractive commercial terms), Crudecorp may experience a limited ability to undertake or complete future exploration programmes, development investments and/or acquisitions. 2.1.7 Oil and gas prices may not remain at their current levels The profitability and cash flow of Crudecorp s operations will be dependent upon the market price of oil and gas from time to time. It is impossible to accurately predict future oil and gas price fluctuations. Accordingly, oil and gas prices may not remain at their current levels. The profitability of producing from some of Crudecorp s wells may change as a result of lower prices, which could result in a material reduction in the volumes of Crudecorp s reserves if some are no longer economically viable to develop. This could result in a material decrease in Crudecorp s net production revenue causing a reduction in its oil and gas acquisition, development and exploration activities have a material adverse effect on its and financial condition. 2.1.8 Changes in the legislative and fiscal framework may affect profitability Changes in the legislative and fiscal framework governing the activities of companies engaged within the oil and gas sector, such as Crudecorp, may have a material impact on exploration and development activity or directly affect Crudecorp s operations. In particular, changes in political regimes will constitute a material risk factor for Crudecorp s operations in foreign countries. Further, Crudecorp is faced with complex tax laws. The amount of taxes Crudecorp pays could increase substantially as a result of changes in, or new interpretations of, such laws, which could have a material adverse effect on its liquidity, results of operations and financial condition. In order to conduct its operations in 18

compliance with applicable laws and regulations, the Crudecorp must obtain licenses and permits from various governmental authorities. There can be no assurance that Crudecorp will be able to obtain all necessary licenses and permits. Furthermore, Crudecorp may incur substantial costs in order to maintain its compliance with existing laws and regulations and significant additional costs if these laws and regulations are revised, or if new laws affecting Crudecorp s operations are passed. 2.1.9 Operational or legislative risk related to drilling, steaming and production permits, e.g. drilling moratoriums or withdrawal of permits related to conditions outside the company s control Failure to comply with requirements set out in permits may have consequences for the Company s operation. Normally, the breach will be pointed out, then there will be a demand given to the Company to rectify and comply, issuance of fines and suspension or withdrawal of permits. Sudden events or events which may constitute an imminent danger of accidents to persons, environment or equipment may escalate the reaction from government bodies. Historically, it has been observed that operators are given time to remediate the situation before fines, suspension of licence or withdrawal of licence has happened in California. However, changing political or regulatory environments may impact policies with respect to permits. In 2011 and 2012, the company experienced a long delay in obtaining steaming permits, as a result of changing regulations and a resulting backlog of applications with DOGGR. Third party incidents may also affect the Company s operation. An example is the accident and blow out in the Gulf of Mexico, which demonstrated that operators can be affected by events happening elsewhere in the industry, in this event a drilling moratorium. Specifically in the area where Chico Martinez is located, there are steaming operations being performed by many operators. Accidents elsewhere may have an impact on rules, regulations and even moratoriums affecting Chico Martinez. 2.1.10 Crudecorp is subject to environmental and HSE risks All phases of the oil and gas business present environmental risks and hazards, and the oil and gas business is subject to environmental regulations pursuant to a variety of international conventions, and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with environmental legislation may require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation, moreover, is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to material liabilities to relevant governments and third parties and may require the Company to incur material costs to remedy such discharge. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely and materially affect the Company s financial condition, results of operations or prospects. Crudecorp s operations and assets are affected by numerous international and national laws and regulations concerning HSE matters including, but not limited to, those relating to the health and safety of employees, discharges of hazardous substances into the environment and the handling and disposal of waste. The technical requirements of these laws and regulations are becoming increasingly complex, stringently enforced and expensive to comply with and this trend is likely to continue. The failure to comply with current HSE laws and regulations has resulted and may 19

in the future result in regulatory action, the imposition of fines or the payment of compensation to third parties which each could in turn have a material adverse effect on the Crudecorp s business, financial condition and results of operations. Certain HSE laws that will apply to Crudecorp s business provide for strict, joint and several liability without regard to negligence or fault for natural resource damages, health and safety, remediation and clean-up costs of spills and other releases of hazardous substances, and such laws may impose material liability for personal injury or property damage as a result of exposure to hazardous substances. Further, such HSE laws and regulations may expose Crudecorp to liability for the conduct of others or for acts that complied with all applicable HSE laws when they were performed. In addition, the enactment of new HSE laws or regulations or stricter enforcement or new interpretations of existing HSE laws or regulations could have a significant impact on Crudecorp s operating costs and require further significant expenditure to modify operations, install pollution control equipment, perform clean-up operations, curtail or cease certain operations, or pay significant fines or make other significant payments for pollution, discharges or other breach of HSE requirements. There can be no assurances that Crudecorp will be able to comply with such HSE laws in the future. The failure to comply with current HSE laws and regulations has resulted, and may in the future result, in regulatory action, imposition of significant fines or payment of significant compensation to third parties. 2.1.11 Risks of equipment breakdown or process upsets Equipment may break down and replacement items may have long lead time. Process upsets may result in extensive flaring whereby the company exceeds its allocated maximum limit for any time period, resulting in shut down. 2.1.12 The oil and gas industry is highly competitive The oil and gas industry is highly competitive in all its phases. There is strong competition for the discovery and acquisition of properties considered to have commercial production potential. The Company competes with other exploration and production companies, many of which include major international oil and gas companies with greater financial resources, staff and facilities than those of Crudecorp. Due to this competitive environment, Crudecorp may be unable to acquire attractive suitable properties or prospects on terms that it considers acceptable. As a result, Crudecorp s revenues may decline over time, thereby materially adversely affecting its results of operations or financial condition. Furthermore, there is strong competition for drilling rigs, and therefore, Crudecorp have entered into, and may also in the future enter into, lease agreements for drilling rigs with significant financial commitments for Crudecorp before Crudecorp s ability to utilize the rig has been finally determined. 2.1.13 Risks associated with third party processing and export infrastructure Crudecorp s development projects rely on access to third party owned and operated infrastructure on reasonable commercial terms. There may be significant competition with other resource owners for access to such infrastructure, which could result in less favorable commercial terms for Crudecorp. Project timings may also be impacted by infrastructure tie in access issues. In addition, Crudecorp has very limited control over how efficiently the processing and export infrastructure may be operated and poor operating efficiency could result in increased production downtime and/or increased transportation and processing costs to Crudecorp. 20

2.1.14 Unexpected shutdowns may occur Mechanical problems, accidents, oil leaks or other events at Crudecorp s producing fields or its pipelines or other infrastructure may cause an unexpected production shutdown at these fields. Any unplanned production shutdown of Crudecorp s facilities could have a material adverse effect on Crudecorp s business, financial condition and results of operations. 2.1.15 Risk related to claims from neighbours, farming community or other third parties related to surface or subsurface claims The area where Chico Martinez is located does not have extensive agriculture, although the surface growth is sometimes used for feed to livestock. Unforeseen events can lead to claims that the Company has destroyed feedstock or livestock. There are no potable water sources or aquifers in the nearby area. Neighbouring operators can make claims if the Company drills too close to neighbouring properties. 2.1.16 Risk related to availability of supplier s capacity and availability of manpower, supplies and equipment The oil service market has been quite active in the region, and the Company experience regularly shortage and long delivery times on services, supplies and equipment. 2.1.17 Risks related to geology, including but not limited to risk of higher operating costs, lower production and underground damage The field is located in an area which has been geologically active. Furthermore, the Company is performing steaming operations which may result in unwanted underground fracking and other reservoir damage. 2.1.18 Risks of leakage of steam to surface Leakage of steam to the surface and resulting accidents or withdrawal of permits as a result of faulty well construction, unknown geological phenomena or operator and planning errors. Accidents in the area has been observed due to failed cement bonding on wells or steam migrating in shallower geological zones. Such accidents will damage equipment and is a serious risk to personnel present and can be catastrophic. 2.1.19 Risks of theft, sabotage or other wilful damage The field is located far from settlements. It is difficult to survey all parts of the field on a continuous 24 hour basis, and unauthorised personnel may gain access. 2.1.20 Risk of earthquake The field is located in an area with many active geological fault systems. 2.1.21 Crudecorp is dependent on attracting and retaining personnel Crudecorp s success depends, to a large extent, on certain of its key personnel. The loss of the services of any key personnel could have a material adverse effect on Crudecorp. There can be no assurance that Crudecorp will be able to continue to attract and retain all personnel necessary for the development and operation of its business. 21

2.1.22 Production and expected production ramp up is concentrated on one field Crudecorp s current production, and the expected production ramp up, of oil and gas is concentrated on one onshore field, Chico Martinez located in the San Joaquin Valley, California US, and its results of operations and financial condition could be adversely and materially affected in the event adverse issues arise on that field. Several less successful attempts have been made to develop the field in the past, and there can be no guarantee that the Company will succeed. See Section 5.7, Operations, for information on the Crudecorp s production and development activities. 2.1.23 Risks associated with labour disputes Crudecorp s contractors or service providers may be limited in their flexibility in dealing with their staff due to the presence of trade unions among their staff. If there is a material disagreement between contractors or service providers and their staff belonging to trade unions, Crudecorp s operations could suffer an interruption or shutdown that could have a material adverse effect on its business, results of operations or financial condition. 2.1.24 Risks associated with legal disputes Crudecorp may from time to time become involved in legal disputes and legal proceedings related to the Group s operations or otherwise. Such legal disputes may have a material adverse effect on Crudecorp s business, financial condition and results of operations. See Section 10, Legal and arbitration proceedings below for information on current legal disputes. The Company has an agreement with Belridge Water District and gets allocated water on a year by year basis. The Company has identified possible alternative sources, but risk interruption of supply, higher associated costs or higher investment costs. 2.1.25 Risk of damaged equipment and insurance policies Oil and gas exploration, development and production operations are inherently risky and hazardous. Risks typically associated with these operations include unexpected formations or pressures, premature decline of reservoirs and the intrusion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on Crudecorp s results of operations, liquidity and financial condition. Hazards typically associated with onshore oil and gas exploration, development and production operations include, but are not limited to, fires, explosions, blowouts, adverse weather conditions, gas leaks and oil spills, each of which could result in substantial damage to oil and gas wells, production facilities, other property and the environment or in personal injury. Oil and gas installations are also known to be likely objects, and targets, of military operations and terrorism. Although Crudecorp obtains, and will obtain in the future, insurance prior to drilling in accordance with industry standards to cover certain of these risks and hazards, insurance is subject to limitations on liability and, as a result, may not be sufficient to cover all of Crudecorp s losses. In addition, the risks or hazards associated with Crudecorp s operations may not in all circumstances be insurable or, in certain circumstances, Crudecorp may elect not to obtain insurance to deal with specific events due to the high premiums associated with such insurance or for other reasons. The occurrence of a significant event against which Crudecorp is not fully insured, or the insolvency of the insurer of such event, could have a material adverse effect on Crudecorp s business, financial condition, results of operations and prospects. 2.1.26 Potential liability for the acts and omissions of oil field services providers Crudecorp may be subject to material liability claims due to the inherent hazardous nature of its 22

business or for act and omissions of sub-contractors and other service providers. C RUDECORP ASA L ISTING ON O SL O A XESS 2.1.27 Risks related to debt arrangements Crudecorp's current and future debt arrangements may include covenants and undertakings of a general, financial and technical nature and such debt arrangements may contain cross-default provisions. Failure by the Company to meet any of the covenants or undertakings could result in all outstanding amounts under the different debt arrangements becoming immediately due for payment. In addition, security rights granted to the lenders could be enforced. If outstanding debts were declared due for immediate payment, there would be no assurances that the Company would be able to meet its obligations, and there are no assurances that the Issuer would be able to obtain alternative financing, either on a timely basis or at all. Any breach of existing covenants and undertakings with a subsequent claim for repayment of all debts outstanding would thus have a material adverse effect on Crudecorp's financial position and is likely to have a material adverse effect on the value of the Shares and the Company s operations and results. 2.1.28 Risk associated with water supply Crudecorp s current production, and the expected production ramp up, of oil is dependent upon water supply and its results of operations and financial condition could be adversely and materially affected in the event that the current agreement for supply of water is cancelled and Crudecorp cannot purchase operations water from another source. 2.2 Risk factors relating to Crudecorp s financing 2.2.1 Financial liquidity risk Crudecorp business requires significant financial liquidity and capital expenditure, and it may, in certain circumstances, need to obtain further external debt and equity financing at a future date. There is no assurance that such additional funding, if required, will be available on acceptable terms at the relevant time and the failure to obtain such financing could have a material adverse effect on the financial condition of Crudecorp. 2.2.2 Risk associated with exchange rate fluctuations Crudecorp has operations which involve cash flows in a variety of currencies. Although Crudecorp may undertake limited hedging activities in an attempt to reduce certain currency fluctuation risks, these activities provide only limited protection against currency-related losses and currency fluctuations could have a material effect on the financial conditions of Crudecorp. 2.3 Risk factors relating to the Company s Shares 2.3.1 Volatility of share price There is currently no public trading market for the Shares and there can be no assurance that an active market will emerge or can be sustained. The market price of the Shares could fluctuate significantly due to a number of factors, some of which are beyond the Company s control, including, but not limited to, the following: (i) actual or anticipated variations in operating results and/or production levels; (ii) fluctuations in oil prices and reserve levels; (iii) changes in financial estimates or recommendations by stock market analysts regarding the Company or its competitors; (iv) announcements by the Company or its competitors of significant acquisitions, strategic partnerships, (v) joint ventures or capital commitments; (vi) sales or purchases of substantial blocks of stock; (vii) additions or departures of key personnel; (viii) future equity or debt offerings by the Company and its announcements of these offerings; (ix) result of drilled wells: and (ix) general market and economic conditions. Moreover, in recent years, the stock market has in general experienced large price 23

fluctuations. These broad market fluctuations may adversely and materially affect the Company s stock price, regardless of its operating results. 2.3.2 Liquidity of the Shares The Company cannot assure any investors that a liquid trading market for the Shares will be created or sustained through the Listing. 2.3.3 Dilution Shareholders not participating in future offerings may be diluted and pre-emptive rights may not be available to shareholders, including, but not limited to shareholders resident in jurisdictions with restrictions having the effect that they will not be granted subscription rights in connection with, or be able to subscribe for new shares in, such offerings. 2.3.4 Additional risk for holders of Company s Shares that are registered in a nominee account Beneficial owners of the Shares that are registered in a nominee account may not be able to exercise voting rights and other shareholder rights as readily as shareholders whose Shares are registered in their own names with the VPS prior to the Company s general meetings. The Company cannot guarantee that beneficial owners of the Shares will receive the notice for a general meeting in time to instruct their nominees to either effect a re-registration of their Shares or otherwise vote for their Shares in the manner desired by such beneficial owners. 2.3.5 The transfer of Shares is subject to restrictions The Company has not registered the Shares under the U.S. Securities Act or the securities laws of jurisdictions other than Norway and the Company does not expect to do so in the future. The Shares may not be offered or sold in the United States or to U.S. persons (as defined in Regulation S under the Securities Act) nor may they be offered or sold in any other jurisdiction in which the registration of the Shares is required but has not taken place, unless an exemption from the applicable registration requirement is available or the offer or sale of the Shares occurs in connection with a transaction that is not subject to these provisions. 24

3. Responsibility for the Prospectus 3.1 Statement of r esponsibility The Board of Directors of Crudecorp accepts responsibility for the information contained in this Prospectus. The members of the Board of Directors of Crudecorp hereby confirm that, having taken all reasonable care to ensure that such is the case, the information contained in this Prospectus is, to the best of their knowledge, in accordance with the facts and contains no omission likely to affect its import. Stavanger, 13 June 2012 Sigurd Aase Chairman Espen Fjogstad Board member Sissel K. Hegdal Board member Stig M. Herbern Board member Silje Veen Board member 25

4. The Listing 4.1 R easons for the listing The purpose of listing the Company s shares on Oslo Axess is to: improve the Company's access to the equity market to allow for the Company s further growth; secure an organised and regulated trade of the Company's shares on a regulated market place; increase the liquidity of the Company shares; and provide an exit opportunity for the current shareholders. The listing will also make the Company more visible to its customers, partners and other stakeholders. 4.2 T he Shar es being admitted to listing The Company has an issued and outstanding share capital of NOK 1,823,033.58 divided into 91,151,679 Shares each with a nominal value of NOK 0.02. All issued Shares in the Company carry equal shareholder rights in all respects and no shares have different voting rights. There is only one class of shares issued and all Shares are freely transferable. All of the Company's Shares are registered in the VPS under ISIN NO 001 036 8475 with DNB ASA acting as registrar. A further description of the Company's shares, their rights and other matters related thereto is provided in Section 9. 4.3 Admission to trading and dealing arrangements 4.3.1 Listing on Oslo Axess The Shares were admitted to listing and trading on Oslo Axess in the meeting of the board of directors of Oslo Stock Exchange on 13 June 2012. The Shares will trade under the trading symbol "CRUDE". The Company s shares have not been previously listed, and the Company has not applied for listing on any other stock exchanges or regulated markets, nor have the Company s shares been registered on the Norwegian OTC list. Information relating to the Company and the listing of its shares will be published on the Oslo Stock Exchange information system (www.newsweb.no) and the Company's website (www.crudecorp.com). All of the Company's shares will be eligible for trading. Shares issued through future share issues will normally be automatically admitted to trading as soon as the relevant share capital increase has been duly registered in the Norwegian Register of Business Enterprises and the shares have been registered in the VPS and, as case may be, when a listing prospectus has been prepared for such new shares. 4.3.2 Lock-up arrangements No shareholders are subject to lock-up arrangements. 26

4.3.3 Stabilization and market-marker arrangements The Company has not entered into any arrangements to provide market stabilization or to provide trading liquidity or other similar arrangements. 4.4 Additional information Swedbank First Securities (Filipstad Brygge 1, 0252 Oslo) has assisted the Company in the preparation of this Prospectus. The Manager has relied on information provided by the Company and will not assume any responsibility for the information provided herein. The Manager, its employees and any affiliate may currently own Shares in the Company. Advokatfirmaet Schjødt AS has acted as the Company's legal adviser in connection with the Listing 4.5 Interest of natural and legal persons involved The Manager will receive a fee in connection with the Listing, see section 4.6 below. The Manager or its affiliates may provide in the future, investment banking services to the Company and its affiliates in the ordinary course of business, for which they may continue to receive customary fees and commissions. 4.6 Expenses Cost attributable to the Listing will be borne by the Company. The total costs of the Listing are expected to amount to approximately NOK4 100 000, which includes costs related to fees to the Manager, Oslo Stock Exchange, printing and distribution of this Prospectus, costs to legal advisors, the Company s auditor, the due diligence lawyers and auditors as well as fees to the Financial Supervisory Authority. 27

5. Presentation of Crudecorp 5.1 Overview Crudecorp is an international oil and gas exploration and production company with assets onshore in the state of California in the United States. The Company s employees have significant worldwide industry experience in the disciplines of geology, geophysics, reservoir modelling, petroleum engineering, operations management, drilling, and completion expertise. Crudecorp targets producing oil assets with low risk exposure in the United States, a region with politically stable regimes and attractive fiscal terms. 5.2 Incorporation and offices Crudecorp is a Norwegian public limited liability company organised under the Companies Act, with registration number 990 904 871. The Company's registered office is at Skagen 27, N-4004, Stavanger, Norway, and its phone number is +47 91 53 23 93. The address of the Company s principal place of business in California is 4900 California Avenue, Tower B-210, Bakersfield, CA 93309, United States with telephone number +1 661 377 1875. The Company is the ultimate parent company of the Group. Its legal and commercial name is Crudecorp ASA. The Company was incorporated on 29 January 2007 as a private limited liability company. 5.3 Historical development Crudecorp was incorporated by two serial entrepreneurs and two experienced subsurface experts. The Company s initial focus was on two areas; possible exploration in mature areas on the Norwegian Continental Shelf and the acquisition of mature/abandoned, land-based petroleum assets where new technology could be applied to maximize recovery. In April 2007, Crudecorp AS merged with STL Energy LCC, a US company focusing on the acquisition and rehabilitation of oil assets that had been abandoned in periods of low oil prices. Following the merger, Crudecorp focused on the Company s efforts on building its activities in the United States through its former, wholly owned, subsidiary Crudecorp, Inc. During 2007-2008, the Company acquired several petroleum assets in Kentucky and Texas, United States. After having drilled more than 40 wells in these properties the Company decided that the assets did not have the required potential for a full development and divested the assets to a local company in 2008. Crudecorp established CMO, Inc. in 2008. In June 2008 Crudecorp acquired a 75% Working Interest and the sole operatorship of Chico Martinez. In September 2010 the Company acquired 15.34% of the Mineral Interest and 2.53% Royalty Interest in Chico Martinez, and in October the same year the Company increased its Working Interest position to 90% through an acquisition. The Company was transformed to a public limited liability company in March 2011 and established another subsidiary, CMO AS, in August 2011. In April 2012, the Company increased its Mineral Interest in Chico Martinez to 17.25% The table below sets out the most significant events in Crudecorp s history. 28

Time H2 2005 H1 2007 H1 2007 H1 2008 H2 2008 H2 2008 H2 2010 H2 2010 H1 2011 H1 2011 H2 2011 H1 2012 H2-2012 Event STL Energy LLC was incorporated in the United States The Company was incorporated in Norway as a private limited liability company STL Energy LLC and Crudecorp AS merged Rights to several orphaned wells in Texas and oil and gas leases in Kentucky was acquired Acquired a 75% Working Interest and 58.5% Net Revenue Interest in Chico Martinez. The oil and gas leases in Kentucky were divested Increased to 90% Working Interest and 74% Net Revenue Interest in Chico Martinez Acquired a 15.34% Mineral Interest Chico Martinez Raised equity of NOK 27 million in a private placement Raised equity of NOK 100 million in a private placement The Company was transformed to a public limited company Raised equity of NOK 70.5 million in a private placement Increased to 17.25% Mineral Interest in Chico Martinez Acquired a 90% interest in the southwest quadrant of Section 27, a property adjacent to the Chico Martinez Field. 5.4 Organisation 5.4.1 Legal structure The following chart depicts the Group's current legal structure: Crudecorp ASA Norway CMO Inc USA Crudecorp Branch USA CMO AS Norway 29

5.4.2 The entities and branches of the Group 5.4.2.1 CMO, Inc. CMO, Inc is owned 100% by Crudecorp. It was incorporated in November 2008 in the state of Nevada under legal entity number E0686332008-9 with legal address 2630 Corporate Circle, Henderson NV 89074-7722, United States, and is permitted to do business in California. The company currently operates under Employer Identification Number 26-3716761 and has 6 employees as of the date of this Prospectus. CMO, Inc operates the oil and gas assets for the Company in the US. Håvard Rød is President and Jan Terje Lea is Chief Financial Officer. 5.4.2.2 CMO AS CMO AS is owned 100% by Crudecorp. It was incorporated in August 2011 as a private limited liability company under the laws of Norway, with registration number 997 235 266 and registered address at Skagen 27, 4006 Stavanger, Norway. The intention for incorporating CMO AS was for it to be the operating entity of the Group, whereas Crudecorp would be the holding company. CMO AS does not hold any assets or liabilities other than the share capital injected at incorporation (NOK 100,000). 5.4.2.3 Crudecorp Branch United States Crudecorp Branch USA, registered in the US under Tax ID Number 98-0568837 was established by operation of US law due to Crudecorp having mineral rights/real estate rights in the United States. As such, a branch was for purposes of US law automatically established. The branch is not a separate legal entity, but is a legal representative of the Company in the United States. 5.5 Vision, goal and strategy Crudecorp is an international independent oil and gas exploration and production company engaged in acquisition, development and operation of onshore oil and gas properties in the United States. Currently, the Company owns a 90% Working Interest in the Chico Martinez oil field in California, and is in the process of developing the upper reservoir of the field. The Company s strategy is to focus on assets near production or producing assets in mature oil basins in areas with low political risk. Crudecorp is of the opinion that producing assets offers an immediate positive cash flow, increased borrowing base and tax benefits through early utilization of tax loss carry forward. The goal is to significantly increase recovery and to raise production rates of old, abandoned resources, through the use of the enhanced oil recovery (EOR) techniques. Furthermore, the goal is to create a company with a strong growth rate and good dividend capacity, which can be a hedge for investors who wish to diversify their portfolio away from increasing inflation risks and who fundamentally believe in a strong demand for energy. The Company's value chain focus is illustrated below. 30

Development Crudecorp Exploration Production 5.6 Business overview 5.6.1 A ssets The Company s principal investment is the 90% Working Interest and 17.25% Mineral Interest in Chico Martinez. At the date of this Prospectus, Chico Martinez is Crudecorp s sole petroleum investment. CHICO MARTINEZ OIL FIELD Location of Chico Martinez field. Source: KSE Energy, November 2005 Chico Martinez is located in the San Joaquin basin and has large producing reservoirs in close vicinity; e.g. South Belridge and Cymric (see figure below). San Joaquin is the most productive basin in California, accounting for 50% of cumulative oil production and 36% of cumulative natural gas production in the state. Over 90 active fields are present, the majority of which are located in western Kern County. Technology is critical to operations in the basin. Although production peaked decades ago, operators are extending the life of the basin s mature fields through advanced thermal recovery techniques. Production is dominated by Chevron, Aera Energy, and Occidental Petroleum. 31

South Belridge: Cum. Prod: 2000 mill bbl (2006) Rem. Reserves: 520 mill bbl Current Prod.: 60,000 bopd Cymric: Cum. Prod: 460 mill bbl Rem. Reserves: 120 mill bbl Current Prod.: 22,000 bopd Chico Martinez and surrounding fields. Source: California Department of Conservation, Division of Oil and Gas. Chico Martinez has a proven oil accumulation in the Etchegoin sands, with potential exploration upside in the several deeper layers, such as Diatiomite and Caraneros formations. Simplified Geological Structure. Source: Crudecorp 5.6.2 History and development of Chico Martinez Chico Martinez is located in the San Joaquin Valley in California, close to the South Belridge and Cymric fields, two of the most productive onshore fields in the United States. Production in Chico Martinez was reportedly started in 1927 with the Max L. Pray #1 well, which is reported to have produced heavy-grade crude oil (12.8 API gravity) at a rate of 11 bopd from a 21 foot thick section found at a depth between 830-851 feet. According to the California Department of Oil and Gas (DOGGR) records of production, a total of 550,000 bbl of oil have been produced from the field, which corresponds to 1.1% of the Company s 32

most likely estimate of 50.5 MMBbl STOIIP (GCA CPR Section 2.1). C RUDECORP ASA L ISTING ON O SL O A XESS Several attempts have been made to develop the field. At the time of discovery, heavy oil was less desirable and drilling in the field was sporadic into the late 1960s. Although development activities were initiated on the property in 1966, attempts to implement an enhanced production program were not undertaken until October 1981, when an insufficient cycle steam injection effort was made. Production peaked in 1983 at a rate of 200 bopd, and later declined to negligible volumes in 1986. The reasons for the decline have not been entirely established, but appear to be related to a breakdown of the fields steam generator, falling oil prices in the period and the operators weak liquidity. An effort to implement a full steam flood (continuous steam injection) was never made. All together, there have been 62 wells drilled in the field before the Company started its operation in 2008. The Company aims to drill a total of 44 production wells and 26 injection wells in phases 1, 2A, 2B and 3. Crudecorp acquired a 75% Working Interest and the sole operatorship of Chico Martinez oil in June 2008. The Company has later acquired 17.25% of the Mineral Interest and 2.87% Royalty Interest in Chico Martinez (September 2010 and April 2012) and increased its Working Interest to 90% (October 2010). 5.6.3 The reservoir The reservoir which is being developed is the Etchegoin sands. Renewed oceanic transgression occurred in the Pliocene, allowing the deposition of the early Pliocene Etchegoin formation. The Etchegoin consists of sands and interbedded shales of shallow marine and locally fluvial/deltaic origin, which are overlain unconformably by late Pliocene mudstones and sands of the San Joaqin Formation. The Etchegoin sands are silty and predominantly fine-grained, sometimes with medium coarse sand grains and scattered pebbles. Diatomaceous debris is likely present, and contributes to the silty appearance of the sediments. The better quality reservoir sands appear to have porosities in the range of 27% to 35%. Permeabilities are variable, ranging from a few millidarcies in non-reservoir rock to 100-800 millidarcies in the average rock with intervals above several thousand millidarcies. The initial average oil saturation is estimated to be 40% pv. The oil is between 12 to 15 API gravity. 5.6.4 Net R evenue I nter est The oil and gas lease or Working Interest (of which the Company owns 90%) acquires a right to explore and produce the oil and gas resources in return for paying a Royalty to the Mineral Rights owners. The Company s Working Interest in Chico Martinez (Section 35 and parts of Section 27) is sub-leases of an original lease, covering Sections 21, 27 and 35. The Royalty structure is therefore as follows; - 16.67% to Mineral Interest owners (The Company owns 17.25% of the Mineral Interests) - 5.0% to Original Lease Holder (OLH), less 21.67% of expenses on fuel gas, water and other consumables to generate steam. The Net Royalty paid will in other words vary between 13.79% and 18.79%, depending on how much is spent on fuel and consumables for generating steam. 33

Based on these various input parameters for gas consumption, GCA estimated the Net Revenue Interest to the Company to be 77.2%, which is the basis used in this document. 5.7 Operations 5.7.1 Legal framework The Oil and Gas Lease for the Company s US property is assigned by legal representative for the owners of land and mineral rights to Whittier Trust under the B. Milo Mitchell Family Trust (Whittier) for Section 27 and 35 in Township 28 South, Range 20 East, MDB&M under what is referred to as the Mitchell lease and the Bacon lease. Whittier has assigned oil and gas sub-leases for Section 35 and southeast quarter of Section 27 to the Company. The Oil and Gas Leases are governed by US Federal and California State Laws. The two main regulatory bodies overseeing the Company s operations are: - the State of California Division of Oil, Gas and Geothermal Resources (DOGGR), primarily concerned with operational and sub-surface regulations - the San Joaquin Valley Air Pollution Control District (APCD), primarily concerned with environmental aspects of the Company s activities. The DOGGR Laws and Regulations are available at Department of Conservation website: http://www.conservation.ca.gov/dog/pubs_stats/pages/law_regulations.aspx The permits issued by the APCD are Clean Air Act permits. The APCD has been delegated authority by the EPA to issue Clean Air Act permits for stationary sources. This authority is enforced via EPA s review and approval of California s State Implementation Plan (SIP) which describes how California will meet the statutory requirements of the Clean Air Act. Environmental regulations are set forth under the San Joaquin Valley Air Pollution Control District Rule 4401, Steam-enhanced Crude Oil Production Wells. Rule 4401 may be viewed at: http://www.valleyair.org/rules/currntrules/r4401%20clean%20rule.pdf The Company works closely with an external expert Bakersfield based Envirotech Consultants, Inc. on regulatory requirements in ensuring compliance. In general, the regulations put in place are set to make sure that operations can be conducted in a safe manner, without harming personnel, equipment or causing underground damage and to ensure a minimal environmental impact to air, water or wildlife. The regulations align with the Company s view of safe and responsible operating practices. 5.7.2 Oil & gas leases The rights to explore for and produce hydrocarbons from Chico Martinez are regulated by the Oil and Gas Lease assigned 100% to Company by legal representative of the original lease owner. The original lease was signed in 1965 between the Mineral Rights Interests (MRIs) and the Original Lease Holder (OLH) being Milo Mitchell, now Whittier Trust and covering the sections 21, 27 and 35, Township 28 South, Range 20 East, M.DB&M, Kern County, California. In 1980 and 1983, the OLH made a separate sub-lease for Section 35, now held by Crudecorp. In 2008, the OLH lifted all depth restrictions on the sub-lease for Section 35. The lease is valid and in force as long as the Company or its assigned representatives produce hydrocarbons in paying quantities from the property as defined by original lease, meaning that any production which the Company makes from Section 35 is sufficient to retain ownership of the Working Interest. 34

In April 2012 the OLH gave the Company an additional sub-lease for 160 acres in the south west corner of Section 27. This lease is valid until 31 December 2015, or as long as the Company or its assigned representatives produce hydrocarbons in paying quantities from this property or Section 35, meaning that any production which the Company makes from Section 27 or 35 is sufficient to retain ownership of the Working Interest. The Company sees little potential in the Etchegoin sands of Section 27, but acquired the property to increase acreage in the event the Company wishes to explore for hydrocarbons in the deeper formations underneath the current Chico Martinez field. Because of the small Etchegoin potential and because the agreement was signed in April 2012, the Section 27 property is not included in the CRP from GCA. Crudecorp Oil and Gas Interests Areas Section Type Leases Gross Area (Acres) WI (%) Est. Effective Average Net Revenue Interest Mitchell and Bacon 35 Term Leases 640 90 77,2 27 Term Leases 160 90 77,2 The total assignment is now for approximately 800 acres with no depth restrictions. 5.7.3 Permits The Company s authority to construct (ATC) and environmental permits are granted by APCD. Drilling steaming permits and water injection permits are granted by DOGGR. These permits are required to carry out the development plan as described in section 5.10 of this Prospectus. In addition, the Company requires Right of Way and construction permits for water pipeline and export oil pipeline if the Company decides to install these. The following paragraphs describe the current process for such permits. Political, legislative or other changes may alter the permit process or renewal process in the future, and the descriptions are only meant to describe the situation today. 5.7.3.1 Permit process and renewal APCD environmental permits Permits issued by APCD are automatically renewed every five years, in accordance with current laws and regulations. The APCD inspects the facilities and records annually to determine compliance with permitted conditions and all current APCD rules and thus there is normally no action required on the part of the facility in order for renewal to take place. In rare cases the operator may be required to perform certain upgrades as a condition of permit renewal. The cost of such an upgrade is difficult to estimate, but not expected to be cost prohibitive. It can take between three and six months before the permits are reissued, during which time the facility continues to operate under the outgoing permit. The purpose of the five year renewal is to update the permits with the latest regulatory conditions and any other changes that have taken place during the interim period. APCD Approval to Construct (ATCs) The ATC application process involves identifying future and potential equipment that is covered by the APCD rules. The application is then filed and the APCD reviews the current rules in order to assign operating conditions to each covered piece of equipment and to assign emission levels. As long as the future equipment can meet the operating requirements set forth by the APCD, then the ATC 35

will be issued. Once the equipment listed on the ATC is constructed, the APCD will inspect the equipment and convert the ATC to a Permit to Operate (PTO). The PTO is valid for 5 years and is automatically renewed. DOGGR Drilling Permits DOGGR Drilling Permits are valid for a period of one year. However other DOGGR permits, such as for waste water well injection and underground steam injection, are typically not time-limited. The DOGGR furthermore requires that all operators are in good standing with regards to areas such as oil and water production reporting and idle well management. DOGGR Steam injection permit DOGGR Steam injection permits are not time limited. DOGGR Waste water disposal permits DOGGR issues permits for surface gravity drainage disposal and injection well disposal. DOGGR Waste water disposal permits are not time limited. Normally, it has been possible to obtain permits in a timely manner, provided application work has been performed properly. However, recent changes in policies have led to a significant back-log in applications and hence delay in processing times for steaming permits from DOGGR thus ending up delaying the project execution. The Company has difficulty assessing if the situation will normalise to historical processing times or whether permits may become more time-consuming to obtain in the future. 5.7.3.2 G r anted per mits The Company diligently maintains records of its permits currently in effect, which set forth, among other things, the renewal dates for such permits in order for the Company to ensure their timely renewal. The Company is unaware of any conditions that presently exist that will prevent the renewal of any such permits. Failure to comply with requirements set out in permits may have consequences for the Company s operation. Normally, the breach will be pointed out and a demand given to the Company to rectify and comply. Failure to rectify the situation can lead to suspension or withdrawal of permits. Costs involved in obtaining and renewing licenses are minimal and relate to employee time taken to administer the process and small fees for issuance of the permit. APCD environmental permits and approvals to construct The Company has a number of environmental permits and approvals to construct in the US granted by the APCD. The table below provides an overview of these permits as of the date of this Prospectus. The steam generator APCD permit is currently valid only for Section 35, but the permit application can be updated to allow for use outside Section 35. All other APCD permits listed are valid for CMO operations in any heavy oil field in the Western Source (as defined by the APCD as heavy oil fields west of Interstate 5 in Kern County), i.e. both Section 35 and 27. 36

CRUDECORP S ENVIRONMENTAL PERMITS Permit # S-3187-1-0 S-3187-3-0 S-3187-4-0 S-3187-12-0 S-3187-14-0 ATC S-3187-15-0 ATC S-3187-16-0 ATC S-3187-17-0 ATC S-3187-18-0 ATC Description Notes Valid to Allowed Emissions SSPE1 (lbs/yr) PTO for old process 2,000 bbl Crude Oil Storage Tank equipment which will 30/04/2017 VOC: 2,327 be removed. PTO for old process 1,000 bbl Crude Oil Storage Tank equipment which will 30/04/2017 VOC: 803 be removed. PTO for old process 1,000 bbl Crude Oil Storage Tank equipment which will 30/04/2017 VOC: 1095 be removed. 420 bbl Wash PTO for old process Tank (Oil/Water equipment which will 30/04/2017 VOC: 657 Separator) be removed. 10 Thermally Enhanced Oil Recovery Wells Issued 17/June/2010 See 5.7.3.1 VOC: 183 w/vapour Control 2,000 bbl Wash Tank with VRU (Vapour Recovery Issued 13/1/2011 See 5.7.3.1 Unit) 1,000 bbl Crude Oil Storage Tank Issued 13/1/2011 See 5.7.3.1 with VRU 1,000 bbl Crude Oil Storage Tank Issued 13/1/2011 See 5.7.3.1 with VRU 250 bbl Drain Tank Issued 13/1/2011 See 5.7.3.1 37

S-3187-19-0 ATC S-3187-20-0 ATC S-3187-21-0 ATC S-3187-22-0 ATC S-3187-24-0 ATC S-3187-25-0 ATC S-3187-26-0 ATC 85 mmbtu/hr Steam Generator 5,000 bbl Wash Tank on VRU 5,000 bbl Crude Oil Storage Tank on VRU 5,000 bbl Crude Oil Storage Tank on VRU 500 MCF/day Flare 50 TEOR Wells connected to CGCS (Casing Gas Collection System) 2,000 bbl Drain Tank (Replaces S-3187-23) Issued 25/8/2011 See 5.7.3.1 VOC:4,095 NOx:6,329 CO: 55,100 PM10:5.659 SOx: 1grain Issued 29/11/2011 See 5.7.3.1 VOC:292 Issued 29/11/2011 See 5.7.3.1 VOC: 37 Issued 29/11/2011 See 5.7.3.1 VOC: 37 VOC:2,835 NOx:3,060 Issued 29/11/2011 See 5.7.3.1 CO: 16,650 PM10:1,170 SOx: 20 grains Issued 29/11/2011 See 5.7.3.1 VOC: 1,059 VOC: 657 See 5.7.3.1 5 bopd/tvp 0.5 The ATCs listed above cover Phase 1 and 2A as defined in Section 5.10 The Environmental Permits require the Company to maintain emissions within certain limits as identified in the below table above. DOGGR Drilling Permits The Company has permits for all wells drilled by the Company to date, 18 vertical production wells and 4 horizontal production wells. After the wells are drilled and inspected by DOGGR, the permit is no longer relevant and there are no renewal requirements. However, the Company needs to issue a new permit application in the event that it plans to make changes to the well which has not been covered by the initial permit, i.e. if the well is converted from a producing well to a steam injection well, or to perforate a new reservoir zone which has not been permitted already. The Company s permit applications generally cover all reservoir zones, and the 38

extent of new permit applications needed for existing wells is believed to be negligible. DOGGR Steam injection permit The Company has a steam injection permit which covers the entire oil field, covered by the lease for Section 35. The permit is valid for all existing and new wells which are drilled or will be drilled in Section 35. As part of the permit from DOGGR, the Company is required to abandon or recomplete certain wells in the area that may be conduits for the entry of steam into non-permitted zones. The Company will also be required to file monthly injection reports, and to conduct annual steam injection surveys to ensure that the steam is being confined to the permitted injection zones. RWQCB Waste water disposal permit The Company has been exempted from certain regulations regarding produced waste water and is thereby permitted to drain produced water into two assigned sumps in the field. As a consequence, the company is currently not in need of a DOGGR injection well permit. Under existing rules and legislation, these exemptions are indefinite. However, these sumps and associated exemption will no longer be required once new infrastructure, such as waste water injection wells, are in place. Discharge of wastewater to the sumps is permitted by the State Regional Water Quality Control Board (RWQCB), by waste discharge requirements. The RWQCB occasionally conducts inspections to ensure that the sumps are covered with netting for the protection of birds and wildlife. An annual wastewater sampling and analysis is required by the RWQCB and the APCD. The amount of oil content permitted in the water disposal sumps is regulated by the APCD. The total VOC content cannot exceed 35 mg/l and this is verified with annual testing. 5.7.3.3 Future permit requirements While the Company believes it has all permits required for its current operations in all material respects, it will require a number of new permits in order to carry out future infrastructure enhancements and drilling operations. APCD Approval to Construct Future field infrastructure will be subject to permit applications to be submitted to the APCD at a time closer to field installation. The ATCs listed above in the table in 5.7.3.1 cover Phase 1 and 2A of the facility expansion as defined in 5.10. Future expansion beyond this will require additional ATCs for all equipment covered by the APCD rules. The ATC application process involves identifying future and potential equipment that is covered by the APCD rules. DOGGR Drilling Permits In order to commence drilling, the Company must apply for drilling permits from DOGGR. The Company is in the process of applying for DOGGR Drilling Permits for the 26 new production wells, 24 new injection wells and 4 delineation wells which are planned to be drilled later this year. For drilling operations, drilling permits issued by the DOGGR specify the blow-out equipment that must be used, the depth and cementing of surface casing to ensure the protection of groundwater resources, and require posting of a bond to cover the cost of well abandonment by the State if necessary. The permit also requires notification of various drilling procedures so that DOGGR inspectors can witness and approve drilling operations to ensure compliance. DOGGR Waste water injection permits 39

A project application is being prepared to permit waste water injection wells. These wells, once approved, will allow the injection of waste water into a permitted zone. Monthly injection reporting and annual mechanical integrity tests will be required. The Company has exemption from this permit but has made this application voluntarily in order to enable it to terminate use of sumps in the future. Future pipeline permits A future water pipeline construction currently considered for bringing water into the field will be subject to permits from State and local County road agencies where the pipeline is located within the road easements. The pipeline may also be subject to permits from the US Army Corps of Engineers (ACE) and the California Department of Fish and Game (CDFG) where it crosses ephemeral stream beds. A biological review of these areas will be conducted and the pipeline will be designed to avoid impacting biological and water resources. The ACE will be consulted and an exemption from permitting will be requested, based on information from ACE this process may take one month. An application for a Streambed Alteration Agreement will be prepared and submitted to the CDFG, feedback from the CDFG indicates that the process of obtaining an Agreement willtake approximately two months. The pipeline also requires Right of Way from property owners where the pipeline crosses. An oil export pipeline may be put in place in the future. This pipeline is normally installed and operated by a third party. The Company is highly dependent upon being awarded applicable California permits in order to operate. 5.7.4 Environment The APCD is the main environmental regulatory body overseeing the Company s operation. The Company has all required environmental permits necessary to operate. See Chapter 5.7.3.2 for an overview of all environmental permits held by the Company. 5.8 Reserves and resources 5.8.1 Competent Person s Report As part of the due diligence process in relation to the Oslo Axess listing, a Competent Person s Report ( CPR ) on reserves and resources for the Etchegoin sands in Section 35 has been prepared by Gaffney, Cline & Associates (GCA), an independent international energy advisory group, entitled Competent Person s Report on the Oil and Gas Assets of Chico Martinez Field of Crudecorp AS as at October 31, 2011 and dated 8 June 2012. The report is based on information compiled by several full-time employees of GCA. For further information relating to these individuals and their qualifications see section 5.9 sources of information. Upon making the report, Crudecorp made available to GCA its well logs, side wall core samples, chemical analysis, production test records, production history (both DOGGR and own records), investment plans and engineering records on sub-surface and surface, previous engineering studies and permits A summary of the CPR is included as Appendix 2 in this Prospectus. The full CPR can be found on the Company s website, please use the following link:http://www.crudecorp.no/getfile.php/filer/competent%20person.pdf. The Company is not aware of any material events to have taken place, which is believed would alter the independent engineer s 40

(GCA s) assessment of the field and its reserves between the time for data cut off 31 October 2011 and to present date.reserves and resources 5.8.2 Resources 5.8.2.1 Definitions In the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers Petroleum Resources Management System, Definitions and Guidelines of March 2007, Prospective Petroleum Resources are defined as Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Contingent Petroleum Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. The Company has in the following included a description of the resources in Section 35 (the Chico Martinez Field) and Section 27, using the three different definitions referenced, in order to give an overview of what resources which may be present in the Company s properties. Engineering reports on the Etchegoin formation Estimated Technically Recoverable Resources, STOIIP (MMBbls) RE (%) Estimated Economically Recoverable Resources, STOIIP (MMBbls) Douglas Petroleum Management Co (1988-92) 55 42 23.2 Walter L.M. Dunbar (1996) 55 42 23.2 W.D von Gonten & Co (2004-05) 63.6 67 42.3 Ralph E. Davis & Associates, Inc (2006) 55 32 17.4 Knowledge Reservoir (2008) 55 42 23.1 5.8.2.2 C ontingent r esour ces Based on GCA s audit of Crudecorp s data, there are no Contingent Oil and Gas Resources estimated to be recovered from its development plan at this initial stage of exploration and development within Section 35. The Company has no independent data which suggest that such Contingent Resources are present in Section 27. 5.8.2.3 Prospective Resources The company is in the process of interpreting geological and seismic data for its properties in Section 27 and 35. Initial studies indicate that several potentially productive formations such as McDonald Shale, Temblor, Kreyenhagen and Caraneros may be present. A new 3D study is now being interpreted, but no conclusions have been reached. The Company assesses that there are no Prospective Resources to report 5.8.2.4 Other r esour ce descr iptions which ar e not par t of Pr ospectus Standar d The United States Geological Survey, which is not in accordance with internationally recognized mineral standards, uses the terms technically and economically recoverable resources when making its petroleum resource assessments. Technically Recoverable Resources represent that proportion of assessed in-place petroleum that may be recoverable using current recovery technology, without 41

regard to cost. Economically Recoverable Resources are technically recoverable petroleum for which the costs of discovery, development, production, and transport, including a return to capital, can be recovered at a given market price. Chico Martinez has a proven oil accumulation in the Etchegoin sands, which for all practical purposes are believed to be in Section 35. Several independent engineering studies have been made on the potential in the Etchegoin formation, within the Section 35 property line, in the period from 1988 to date. Estimated Technically Recoverable Resources in the field vary from 55 to 63.6 MMBbls. Recovery rates (RE) have been estimated between 32 and 67% (100% basis), giving Economically Recoverable Resources between 23.2 and 42.3 MMBbls. These resource estimates are based on old engineering reports, and the various engineers have used different economics, technical judgement and different definitions. A quotation mark is used to indicate that these estimates may not be valid today, or to indicate that the definition used by the engineer may deviate from the definition referred to within this Prospectus. No estimates have been carried out for Section 27, but it is believed that oil accumulations within the Etchegoin sands are negligible on this property. 5.8.3 Reserves The CPR estimates volumetric oil in place (STOIIP) in the Etchegoin formation for Section 35 to range from 27.0 to 65.4 MMBbl, with a most likely STOIIP of 50.5 MMBbl. The Company initially plans to develop approximately 28% of the most likely STOIIP in Chico Martinez through a 3-phased development plan from 2011 through 2014. The Company aims to drill approximately 44 production wells as part of the Pilot Programme described in 5.10.2. Based on this development plan, GCA reviewed the production profiles and project economics for this project (the Pilot Project). GCA estimated gross reserves (on a 100% field basis) for the Pilot Project was 1P reserves of 3.35 MMBbl and 2P reserves of 4.79 MMBbl. These volumes represent incremental increased recovery for the field in the order of 6.6% and 9.5% respectively. Based on the Company s Net Revenue Interest considerations of 77.2%, outlined in Section 5.6.4, the Company s Net Entitlement Oil Reserves is 1P reserves of 2.58 MMBbl and 2P reserves of 3.7 MMBbl. 42

The field life is dependent on how quickly the field is developed, the field s production rates, oil and gas prices and recovery factor. GCA estimated that the current development plan (for 28% of STOIIP) will produce 4.79 MMBbl of oil in a 10 year period, giving a recovery factor of 29% in this period. Crudecorp s aim is to develop the remaining oil resources in the years 2013 2016, and at the same time achieve and demonstrate significantly higher recovery rates, extending the life of each development phase well beyond 10 years or 2026. Based on today s industry expectations, a steam flood project can achieve significant oil recovery, with residual oil saturations as low as 10% (translating to a recovery factor of in excess of 60-70%). If such recovery rates are achieved, the field life may extend beyond 30 years at today s oil prices and production rates. However, before making a definite statement on residual oil saturations and hence recovery rates and field life, the Pilot Project should produce for some time to allow the Company to gather more data on the factors which influence the economic lifetime of the field. 5.8.4 Exploration 5.8.4.1 E tchegion reservoir in Section 35 The central field of the Etchegoin sands are well documented and understood. As a consequence, the Company has constructed a reservoir model and development plan for this part of the field. The Company had drilled one delineation well in the North East corner of the field to better understand the geology and petrophysics in the peripheral parts of the field. The well showed oil-baring sand and helped to map the geology in the area. This autumn, the company aims to drill an additional four delineation wells in the Etchgoin to a depth of around 1,200 feet to better define the geology and petrophysics to allow for a better design of the later development phases. The aim of the delineation drilling in the Etchegoin sands is to reduce uncertainty of resource estimate and to help formulate future development strategies of the field. 5.8.4.2 Exploration potential The Company has evaluated its exploration potential in the lower formations underneath the Etchegoin formation. The evaluations have been based on the local geology, production discoveries in the valley, old well logs and a 3D seismic survey which was performed in 2010. The Company believes there is reason to believe that several sands with production potential may be present in the field s lower formations. Initial studies indicate that several potentially productive formations such as McDonald Shale, Temblor, Kreyenhagen and Caraneros may be present. These potentially productive sands are believed to be located at depths of 4,000 to 12,000 feet. Experience from elsewhere in the valley indicate that oil from such formation is lighter, typically 24 API gravity and lighter. The Company has now received the data form a new 3D seismic survey performed in the autumn of 2011 and the Company is in the process of interpreting the new data. 43

There has not at this time been planned any exploration wells. As a consequence, the Company has not at this stage initiated any permitting work, engineering and equipment or well design related to exploration or production from potential reservoirs below 1,200 feet. 5.9 Sources of information The Competent Person s Report dated 8 June 2012 and resulting reserve estimations was produced by GCA. Staff members who participated in the compilation of this report include Brian Rhodes, Rawdon Seager, Vivian Bust, James Curry, William Lau, Florent Rousset and Elena Poltaraus. All hold degrees in geoscience, petroleum engineering or a related discipline. Mr. Rhodes holds a BSc (Hons) Geology, is a member of the Energy Institute, the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the European Association of Geoscientists and Engineers, and has more than 37 years industry experience. Mr. Seager holds a MSc. (Distinction) in Petroleum Reservoir Engineering, is a member of Society of Petroleum Engineers (Chairman of SPE Oil and Gas Reserves Committee), the Society of Petroleum Evaluation Engineers, the Energy Institute, UK, and the American Association of Petroleum Geologists. Mr. Seager is also a Chartered Petroleum Engineer, UK and a European Engineer, registered with the European Federation of National Engineering Associations, FEANI. Miss Bust holds a Bachelors Degree in Civil Engineering, a Masters Degree in Geology and is a registered Engineer, a certified hydrogeologist and a member of the Society of Petroleum Engineers. Mr. Curry holds a Bachelors Degree in Geology and a Bachelors Degree in Petroleum Engineering and has over 36 years of industry experience and is a member of the Society of Petroleum Engineers. Mr. Lau is a Texas State Registered Geoscientist and holds a Bachelor of Science in Geology and a Masters in Business Administration; he is a certified member of the American Association of Petroleum Geologists (AAPG), Society of Petroleum Engineers (SPE), and has over 41 years of industry experience. Mr. Rousset has a Masters in Management from the Rouen Business School. Mrs. Poltaraus holds Masters Degrees in Technology Project Management and Applied Mathematics, and is also a member of the Society of Petroleum Engineers. 5.10 Development plan 5.10.1 Current activities Crudecorp has during 2010-11 constructed a reservoir model of the field, based on interpretation of old and new well data (logs, side cores, production rates) and general and local knowledge of the geology. Crudecorp has in 2011 through 1H 2012 performed production testing of old and new wells in the field using a small rental steam generator with a capacity of 500 bbl of steam/day. The production testing is related to measurement of cold rates (no steam stimulation) and measurement of hot and declining rates (following cyclic steam stimulation) to determine the reservoir response to steam and verify the business model for the field. 44

The tests have shown very low production rates during cold production, typically 0.5-2 bopd. After steam injection, production has increased significantly, but results vary from each well. During 2011, there has been between 8 and 20 wells producing. The new 18 wells which were drilled came on line in the autumn of 2011 and some old wells were retired. In 2011, a total of 78 209 Bbls of steam was injected with a resulting production of 10,112 Bbls of oil or 27.7 bopd (from cold and hot wells), giving a steam to oil ratio of 7.7 for the field. In Q1 2012, a total of 24-26 wells have been producing, as old wells have been tied back in. For Q1 2012, a total of 30,896 Bbls of steam has been injected and a total of 4,101 Bbls of oil or 45 bopd (from hot and cold wells), giving a steam to oil ratio of 7.5 for the field. 5.10.2 Planned development Crudecorp plans to develop Chico Martinez through at least a 7-phased development plan from 2011 through 2016, whereof 4 phases (also called the Pilot Project) have been sanctioned so far by the Company s board. This project has also been the basis for GCA s review and reserve estimates. Phases 1, 2A, 2B, 3 and 4 The Company aims to drill a total of 44 production wells and 26 injection wells in the phases 1, 2A, 2B, 3 and 4 (see table below). Phase 1 is concluded and a total of 18 production wells have been drilled, and installation of flowlines and tanks is completed. To recover oil from the Etchegoin formation Crudecorp plans initially to stimulate the reservoir through Cyclic Steam Circulation, a technique also known as the Huff and Puff method. Steam is first injected into a well to heat the reservoir, thus reducing the oil viscosity. Following this steam injection, pumping jacks are installed to pump the oil from the well. After production rates have declined to a predefined level, the Huff and Puff cycle is repeated. This development is planned in Phase 2A and is constructed simultaneously with Phase 1. Phase 1 is operational and phase 2A is expected to be operational from July 2012. The Company later intends to establish a permanent steam flood for the reservoir, thus drilling permanent injection wells for steam and leaving oil producing wells to pump continuously. This method is used to increase the recovery from the field even further. The first development in this direction is Phase 2B, which is meant to convert Phase 1 and 2B into a continuous steam flood but drilling new steam injection. Drilling of 8 injection wells in Phase 2B will commence in mid-june to July and the initial steam flood is expected to commence in September 2012. Production in the first quarter 2012 was on average 45 bopd, with an average Huff and Puff steam injection rate of 335 bbl of steam per day. When Phase 2a and later 2B commence, it is anticipated that production will increase from July 2012 with the start-up of a new steam generator, one with a capacity of 5,000 bbl of steam per day. Following the completion of Phase 2B, the Company will continue to drill 26 production wells and 18 injection wells for Phase 3 and 4 will commence in July/August 2012. The Company also intends to drill 4 delineation wells in 2012 to help determine where the expansion phases 5 through 7 should be located. A Phase 3 steam generator with capacity of 5,000 bbl of steam/day is anticipated to be installed in 45

June 2013 and a Phase 4 generator is anticipated to be installed towards the end of 2013, dependent on the requirement for steam. The project, running up to completion of Phase 4 is sanctioned by the Company s board, and is also the scope reviewed by GCA for estimates of recoverable reserves. When Phase 4 is completed, the Company estimates that 28% of the estimates volumetric oil in place (STOIIP) has been developed with production wells. Following the completion of Phase 4, the Company intends to expand the production through development of additional production expansions. Each phase is envisioned consisting of 20 and 24 production wells. 2011-2012 2012-2013 2014-2016 Description Phase 1 Phase 2A Phase 2B Phase 3 Phase 4 Phase 5 Phase 6 Phase 7 Cold production Cyclic Steam of Phase 1 Steam Flood of Phase 1 Wells 18 Prod wells 8 Inj wells Steam Flood Expansion 17 Prod wells, 12 Inj wells Steam Flood Expansion 9 Prod wells, 6 inj wells Steam Flood Expansion 20-24 prod wells, 16 inj wells Steam Flood Expansion 20-24 prod wells, 16 inj wells 20-24 prod wells, 16 inj wells Production facilities and tanks Production facilities and tanks and steam facilities Production facilities and tanks and steam facilities Production facilities and steam facilities Facilities Budget, USD million Wells (GCA report) 5.9 4.2 6.9 4.6 Facilities (GCA report) 12.1 7.2 3.3 19.0 4.0 Investments (used in GCA report) 18.0 7.2 7.5 25.6 8.6 Production facilities and steam facilities Production facilities Production facilities Wells (CC current est) 5.9 4.2 6.9 3.5 10.9 (Est) Facilities (CC current est) 12.1 8.2 3.3 5.9 9.2 13.5 (Est) Investments (CC current estimate) 18.0 8.2 7.5 12.8 12.7 24.4 (Est) Not fully planned and sanctioned by Scope of GCA's CPR Crudecorp Board The budget estimate when GCA carried out its scope was put at USD 67.4 million. The Company has made a new revision of this estimate and believes that some of the investments in the GCA report can be deferred to Phase 5. The Company now believes that the GCA development scope can be achieved with a total investment of USD 59.2 million, without affecting production rates. The equipment deferred is mainly related to water treatment facilities, utilities, oil export and surplus flow lines. The Company has per the date of the Prospectus committed itself to Phase 1 and 2A, completion of construction of the processing plant. The estimated total investment of USD 59.2 million relates to phases 1-4 of the development plan: Phase 1 USD 18 million Phase 2A USD 8.2 million Phase 2B USD 7.5 million Phase 3 USD 12.8 million Phase 4 USD 12.7 million 5.11 T he pr oduction pr ocess The oil in the Etchegoin sands is located at depths of 600 1,200 feet and the oil has high viscocity, 46

API gravity 12.8-14. For more information on the reservoir see 5.6.3. The high oil viscosity leads to low natural production flow rates into the production wells. Production wells are normally completed using a slotted liner but a few wells have perforated casing. The oil is pumped using surface pumps ( Pump Jacks/ Nodding Donkies ). In order to increase production rates, heat in the form of steam is injected to reduce the oil s viscocity from around 3,000 centipoise to around 30-50 centipoise, thereby improving the oils ability to flow into the production well. Steam under pressure (typically 250 700 pounds per square inch pressure) can be injected into the production well to allow the area around the wellbore to be heated. This method is referred to as cyclic steaming or Huff Puff. Alternatively, steam injection wells are drilled in a pattern mixed with production wells and steam injection wells, whereby the entire reservoir is heated and oil flows into the production well. This method is called steamflooding. In order to generate steam, the Company trucks water from a nearby water canal about 10 km distance from the plant. The water is offloaded into a water storage tank and then led to the steam generator. There are two back-up sources for water, located 10 km and 30 km from the plant. When water needs increase as a result of plant expansion a water pipeline is planned to be constructed. Gas to generate steam is taken from an 8 pipeline on Section 35, as well as from the plant s vapor recovery system. The steam generator in current use is a rental unit with a capacity of 500 Bbl of steam per day. For Phase 1, 2A and 2B, the Company has purchased and installed a new steam generator with a capacity of 5,000 Bbls of steam per day. As more wells are drilled and the facilities are expanded, more steam generation capacity is added. Production from the production wells go into a 5,000 Bbls heated separator tank, called Wash Tanks. In this tank, the oil s watercut is reduced to 40% through gravity separation. The oil is then led to one of two new 5,000 Bbls heated separator tank called the Production Tank where the oil s watercut is reduced to 3%. When the Production Tank is full and watercut reduced to 3%, the oil is picked up by a truck. When production is increased, the intention is to have one of the export oil pipeline operators in the area to extend a pipeline branch to the Chico Martinez oil field and export oil through the pipeline system. An oil export measurement system will also be installed. The produced water from the Wash Tank and Production Tanks is moved to a Skim Tank and then a Clarifier Tank, where the produced water is cleaned for oil residuals. The oil is fed back to the Production Tanks and the produced water is disposed of in one of two sumps. As production increase, the Company plans to dispose of produced water through water injection wells or to clean the produced water for dissolved solids in a water cleaning plant and re-use the water for steam generation. Gas from tanks, wells and other equipment is gathered in the vapor recovery system and led to a separator tank (or knock out drum). Gas is recompressed using a gas compressor and fed back into the steam generator. In the event that the generator is non-operational, the gas will be sent to a flare stack. Oil condensate is pumped back to the Production Tank. 5.12 Principal markets The Company operates in an area with a long history of significant oil and gas production and there are readily available markets accommodating sale of oil production. Plains Marketing is currently the buyer of the Company s oil production. There are several refineries and transportation pipelines 47

relatively near the field however Company pays $1.77 to Plains for each bbl of oil transported out of Chico Martinez to Plains facility in trucks Plains currently transports the majority of Chico Martinez oil in a pipeline to a terminal in greater Los Angeles Area. Shell Oil Company is an alternative buyer of the Company s oil. The Company may elect in the future to construct a pipeline for its production which would tie in with existing nearby pipelines. The price received for sold production volumes is based on the average monthly price quoted Plains Marketing Price Bulletin, closely tied to the Midway Sunset price: http://www.paalp.com/fw/main/default.asp?docid=1363. The Company receives payment for oil sold on or about the 20 th day of the month after oil was sold. 5.13 R esearch and development The company has not classified any of its expenses as research and development. When the Company in 2008 acquired its initial 75% (and later 90% in 2010) working interest in Chico Martinez the oil deposit was well documented by several independent studies. The initial valuation of the field was USD 10 million on a 100% basis. The working interest is valid indefinitely as long as the field is producing. Following the acquisition of Chico Martinez, the Company has performed its own modeling of the field geology and petrophysics in 2010 through 2012. The Company has also drilled one delineation well in 2011. However, these expenses have been treated as operational expenses. The Company is in the process of interpreting 3D seismic, which may result in exploratory drilling. 5.14 Patents and licenses etc. The Company is highly dependent upon being awarded a number of environmental permits and government licenses etc. in order to operate as further set out in section 5.7 of the prospectus. Besides, contracts for supply of water are of material importance for the Company's business. Should the Company not be awarded such permits and licenses or commercial contracts, the Company would have to adjust its business accordingly which could adversely effect the Company's profitability. 5.15 Material contracts Neither the Company nor any of the companies in the Group have entered into any material contracts outside the ordinary course of business during the last two years. 5.16 Other projects The interests in Chico Martinez, as described in this Prospectus, are the Company s only assets. The Company does not therefore have any other projects in progress or in development as of the date of the Prospectus. 5.16.1 T rend information The Company has not experienced any changes or trends that are significant to the Company since the end of the last financial period, and as of the date of this Prospectus. 5.17 R egulator y issues 5.17.1 Environmental considerations and HSE policy The Company is subject to the environmental regulations determined under the San Joaquin Valley 48

Air Pollution Control District Rule 4401, see section 5.7, and has been granted environmental permits for its operations as described in section 5.7.1 of this Prospectus. To ensure the safety and health of our employees we are enrolled in a California workers compensation program which verifies weekly safety meetings, employee payroll records, maintains accident reports and recommends guidelines to maintain a safe and healthy environment for our employees. To further ensure the safety of our employees, CMO, Inc holds a safety meeting each week to introduce new procedures and plans to maintain a safe environment. 5.17.2 Taxation Upstream operations in California are conducted under concessionary fiscal systems, with the terms dependent on land ownership. Income from production is subject to royalties. There are no production taxes in California and Royalty rates vary by lease. A landowner generally owns what is known as a fee interest that comprises both the surface and sub-surface (or mineral) rights. Over time, the ownership of surface rights and sub-surface rights have been divided and sold to different owners, conducting different exploitation of the land (e.g. farming and oil production). Sub-surface rights have preference over surface rights, meaning that for example agriculture can not block mineral exploitation. The landowner can sell any part of the sub-surface land (or minerals) under the terms of a lease agreement, which usually provides for a cash consideration (or bonus) and a royalty to be paid to the landowner. The fee royalty is defined by the lease agreement. 5.17.3 Overview California tax regime: - Federal Income Tax (FIT) o Federal Income Tax is graduated and increases to 35% which is the marginal rate - State Income Tax (SIT) o State Income Tax for California is set to 8.84% o The California SIT is deductable for Federal income tax - Current tax rates o Simulations on net income before income tax below USD 10 million gives a combined effective income tax rate of 39.28% o Simulations on net income before income tax above USD 10 million gives a combined effective tax rate of 40.28% - State Ad Valorem (Property) Tax o Oil producing states leave an ad valorem tax on the value of equipment or property used in the extraction and processing of hydrocarbons. o In California, ad valorem tax rates vary by county, in Kern County tax is set to be 1.01% - Depreciation and tax (for FCF only) o Depreciation calculated as 75% of capex first year, the remaining 25% of capex depreciated over 7 years. Typical Lease and well equipment investments (exploration equipment, storage facilities, etc.) 49

6. Market overview Market data and certain industry forecasts used in this Prospectus have been obtained from internal surveys, reports and studies, as well as market research, publicly available information and industry publications. Industry publications generally state that the information they contain has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed and that the projections they contain are based on a number of significant assumptions. Crudecorp has not independently verified such information and therefore cannot guarantee its accuracy and completeness. The information in this Prospectus that has been sourced from third parties has been accurately reproduced and, as far as the Company is aware and able to ascertain from the information published by that third party, no facts have been omitted that would render the reproduced information inaccurate or misleading. In this Prospectus, Crudecorp makes some statements regarding its own competitive and market position. While the management believes that its internal surveys, estimates and market research are reliable, the Company has not independently verified this information. 6.1 Oil market fundamentals Supply vs. demand Fossil fuels remain the dominant sources of primary energy worldwide, accounting for 77% of the demand increase in the period 2007 to 2030, according to the IEA s Reference Scenario. Oil is expected to remain the single largest fuel in the primary fuel mix, despite a drop in share from the current rate of 34% to 30% in 2030. Demand for oil (excluding biofuels) is projected to grow by 1% per year on average over the projection period, from 85 million barrels per day in 2008 to 105 million barrels per day in 2030. This growth comes in its entirety from non-oecd countries, with demand from OECD countries expected to fall. The transport sector accounts for 97% of the increase in oil usage. As conventional oil production in non-opec countries is expected to peak around 2010, most of the increase in output would need to come from OPEC countries which hold the bulk of the remaining recoverable conventional oil resources. PRIMARY OIL DEMAND BY REGION (MB/D) 120 100 OECD E. Europe/Eurasia Asia Middle East 90,9 92,4 94,4 86,6 96,9 99,4 80 60 64,2 40 20 0 1980 2010 2015 2020 2025 2030 2035 Source: IEA World Energy Outlook, November 2009, Reference Scenario 50

The IEA expects oil production to rise from 83.1 mb/d in 2008 to 86.6 mb/d in 2015 and 103 mb/d in 2030. Most of the projected increase in output comes from members of OPEC, which hold the bulk of remaining proven oil reserves and ultimately recoverable resources PRODUCTION AND SUPPLY BY OPEC / NON-OPEC 120 100 OPEC production 85,7 92,4 99,4 80 60 63,8 40 20 0 1980 2010 2020 2035 Source: IEA World Energy Outlook, November 2009, Reference Scenario OIL 6.2 Oil price 6.2.1 Oil price development As of the date of this Prospectus the oil price is around USD 112 per barrel Brent Blend, almost 70% higher than the average nominal price over the last ten years. The oil price started to increase in 2002 from ~20 USD/barrel and was driven by strong global demand in combination with limited supply due to lack of real spare capacity. In 2008, the oil price peaked at ~140 USD/barrel despite the fact that the market seemed well-supplied with crude and stock levels were high. The emergence of oil as a financial asset class may have caused non-fundamental factors to trigger the extreme price level and volatility. The recent financial crisis, which turned into a real economic crisis worldwide, was regarded as one of the main reasons for the setback in the oil price during the second half of 2008. Since then the oil price has rebounded sharply on back of contango trade whereby oil has been bought and held in storage and sold at higher forward prices (effectively taking oil supply off the market) in addition to the very effective cuts in OPEC production. This coupled with a rebound in economic activity and continued growth in China are believed to be the main reasons for oil prices moving up to its current level around USD 112 per barrel. The current forward curve suggests a long term oil price in the range USD 90-100 per barrel. 51

OIL PRICE DEVELOPMENT SINCE JANUARY 2000 Source: EcoWin database, 7 May 2012 In the beginning of 2011, the oil price was significantly impacted by political unrest in Libya as well as in other North African and Middle Eastern countries, which led to the highest crude oil prices since 2008. The political situation in Libya increased the oil market uncertainty because much of the country s 1.8 mmboepd total liquids production capacity had been shut in and it was unclear how long this situation would continue, and whether the unrest in the Middle Eastern region could continue to spread to additional countries. The past year the oil production in Libya has revered much faster than most experts has anticipated, implying high global oil supply and probably somewhat downside risk to the oil price. The oil price is affected by a number of factors, including changes in supply and demand, OPEC regulations, weather conditions, regulations from domestic and foreign authorities, political and economic conditions and the price of substitutes. It should be noted that the oil market is dynamic and that the demand for oil to some extent is inversely linked to the price. Longer periods of high oil prices can therefore lead to increased use of alternative energy sources at the cost of oil demand. 6.2.2 OPEC s role and oil market fundamentals OPEC is an international organization of twelve countries, which are heavily reliant on oil revenues as their main source of income. Membership is open to any country which is a substantial net exporter of oil and shares the ideals of the organization. The current members are Algeria, Angola, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates and Venezuela. Twice a year, or more frequently if required, the Oil and Energy Ministers of the OPEC countries meet to decide on the organization s output level and consider whether any action to adjust output is necessary in the light of recent and anticipated oil market developments. During the period in 2005-2008, with strongly increasing energy prices, it was questioned whether OPEC had control over the price setting in the oil market. 52

The spare capacity enables important volumes of additional supplies to be made available in times of shortage, thereby stabilising the market. As displayed in the figure above, periods with low spare capacity contribute to sow the seeds of unstable markets and price spikes. The global spare capacity has grown over the past year and OPEC expects this to increase further in the next year or two. Exploration and production spending increased more than 10% per year from 2004 to 2008. This led to increased capacity utilization in most oil service segments and record price high utilizations levels. The global spending level declined significantly in 2009, but is set to increase as the global economy recovers going forward. GLOBAL SPARE PRODUCTION CAPACITY 110 100 90 80 70 60 50 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 25 % 20 % 15 % 10 % 5 % 0 % Spare capacity (% of demand, RHS) Global capacity Global demand Source: IEA, CERA, BP Statistical Review, Swedbank First Securities Demand factors support high petroleum prices going forward. Over the past 10 years (1998-2008) the average growth in global oil demand has been ~1.8%, while the average global GDP growth has been ~3.8%, the two showing a strong correlation. Swedbank First Securities expects the global GDP growth to remain strong in the short term, expecting growth to be above 3.2% in 2012 and 4.2% in 2013. Global oil demand growth declined during 2000-2002, mainly because of turmoil in the global economy. Economic recovery combined with increasingly strong demand from Asia drove the demand growth up to 2.3% and 3.4% in 2003 and 2004, respectively. In the period 2005 to 2007, oil demand growth was in the range 1.3% to 1.9%. 2008 resulted in a marginal negative growth and the 2009 estimates are approx. -1.5%. For 2012, Swedbank First Securities expects global oil demand to increase by 0.5%, up to 89.5 mmboe/day. 53

GROWTH IN GLOBAL OIL DEMAND AND WORLD GDP 6 % World oil demand growth 5 % 4 % 3 % 2 % 1 % 0 % -1 % -2 % -3 % 1976 1977 1978 2004 1986 1988 1996 2003 1997 1999 1987 1995 2005 2010E 2007 1991 1979 2001 1998 1992 2002 1989 1984 2006 1994 1993 1990 2000 1985 1975 2008 1983 2009E 1982 1981-1,0% 0,0% 1,0% 2,0% 3,0% 4,0% 5,0% Growth in world GDP Source: BP Statistical Review of World Energy 6.3 North America - Oil market fundamentals 6.3.1 North America - Oil demand and supply Oil product demand in North America is expected to fall by 0.2% per year on average between 2009 and 2015, from 23.3 mb/d to 22.9 mb/d. This outlook stems from structural declines in oil usage for heating and power generation outweighing modest rises in transportation fuel and petrochemical feedstock demand. The United States continues to dominate oil consumption, accounting for over 80% of regional demand in 2015. The regional economic outlook envisages real GDP growth returning to levels seen before the economic crisis, with 2011-2015 annual growth averaging 2.7%, similar to the 2002-2006 average. This would seem to suggest a stronger return to oil demand growth, particularly in the more economically sensitive transportation sector. Yet gasoline consumption should actually decline over the forecasted period, owing to improved fuel economy and high oil prices. 54

25,0 23,5 23,3 23,3 23,3 23,2 23,2 20,0 mb/d 15,0 10,0 5,0 14,5 15,2 14,9 15,2 15,9 16,5 0,0 2011 2012 2013 2014 2015 2016 Own Supply Imports Source: BP Statistical Review of World Energy According to IEA, the North America region as a whole is projected to see a total supply increase by 110kb/d by 2015, with strong growth in Canada offset by hefty decline in the United States and Mexico. Total US supply is expected to fall by 480kb/d to 6.9 mb/d in 2015 6.3.2 California Production and reserves California is a mature operating area that continues to produce large volumes of oil and gas. So far, approximately 28.7 billion barrels of crude oil has been produced, with remaining 2P reserves of ~5 billion boe (~3.3 billion barrels of oil). Distribution of 2P reserves by type: Heavy Oil (49%), Oil (25%), Gas (20%), NGLs (4%), Shale Oil (1%) and Condensate (1%). 55

California contains five large hydrocarbon producing sedimentary basins, the Sacramento, San Joaquin, Santa Maria, Ventura, and Los Angeles basins. Two sub-basins, the Cuyama and Salinas basins, are also being actively developed. Most acreage with proven reserves is held by a small group of operators, primarily large independents and supermajors. Crudecorp is of the opinion that the region offers low-risk opportunities with potential to generate steady cash flows. Source: "The National Atlas of the United States of America. General Reference", compiled by U.S. Geological Survey 2001 Crudecorp s main asset, Chico Martinez in is located in the San Joaquin basin in Bakersfield, California. According to Wood Mackenzie, the San Joaquin basin is the most prospective in the region. The majority of reserves lie in the San Joaquin basin, where the bulk of oil and gas is produced. CALIFORNIA REMAINING 2P RESERVES BY BASIN (AT 01/01/2011) Source: Wood Mackenzie database 6.3.3 California Drilling activity The US Senate and House of Representatives have passed a tax incentive bill to help small oil and gas producers. This bill provides a tax credit of up to USD 9 per well per day for marginal wells. As a consequence of attractive terms and high oil price levels during 2006-2008, the drilling activity boosted. The San Joaquin basin is the most extensively developed area in California, and continues to be the most heavily drilled part of the state. In 2010, 87% of new wells drilled in California were drilled in the San Joaquin basin. 56