NOTES TO THE HISTORICAL FINANCIAL INFORMATION 1. NATURE OF OPERATIONS Ithaca Oil and Gas Limited (“IOG”) was incorporated in England on 20 February 1981 and is incorporated and domiciled in England. IOG is involved in the development and production of oil and gas in the North Sea. The IOG’s registered office is 1 Park Row Leeds LS1 5AB. On 29 May 2019, IEUK entered into a sale and purchase agreement with Chevron North Sea Holdings Limited to acquire the entire share capital of Ithaca Oil and Gas Limited (previously known as Chevron North Sea Limited). The acquisition was completed on 8 November 2019. 2. BASIS OF PREPARATION The Ithaca Oil and Gas Limited Historical Financial Information (“HFI”), which has been prepared specifically for the purposes of this document, sets out the Statement of Financial Position as at 31 December 2019 and the results of operations and cash flows for the year then ended and does not constitute statutory accounts within the meaning of section 434(3) of the Companies Act 2006. This historical financial information has been prepared in accordance with the requirements of the Registration Document Directive Regulation, the Listing Rules, and on a basis consistent with the accounting policies adopted in the historical financial information of the Ithaca Group (or Ithaca Energy Limited/PLC), included elsewhere in this document, which were prepared in accordance with UK-adopted International Accounting Standards (“UK-adopted IAS”), except as noted below. This Historical Financial Information presents only the business that was acquired by Ithaca Group and reflects the assets, liabilities, revenues and expenses of IOG directly attributed to the business acquired. The HFI does not include certain assets, liabilities, revenues and expenses related to the following (the “Carved-out operations”): • Sale by IOG of its interests in the Rosebank field to Equinor, which completed in January 2019 • Transfer of interests in the following fields and/or former subsidiaries to other Chevron group companies prior to completion of the acquisition of IOG by the Ithaca Group: • Clair Licence • Ninian pipeline system • SIRGE pipeline system • Sullom Voe terminal • Chevron Europe Limited • Chevron Britain Limited • Texaco Ireland Limited • Oil Spill Response Limited • Paloak Limited UK-adopted IAS does not explicitly provide guidance for the preparation of carve-out historical financial information and therefore certain accounting conventions permitted for the preparation of historical financial information for inclusion in investment circulars, as described in the Standards for Investment Reporting Annexure (“the Annexure” to SIR 2000 (Investment Reporting Standard applicable to public reporting engagements on historical financial information) issued by the Financial Reporting Council, have been applied where UK- adopted IAS does not provide specific accounting treatments. The HFI has carved out the operations referred to above and therefore does not comply with the requirements of IFRS 10 ‘Consolidated Financial Statements’. However, the HFI has been prepared on a basis applying the aggregation principles underlying the consolidation procedures of IFRS 10 to the business acquired by the Ithaca Group. The Prospectus Directive Regulation does not require financial information to be included in this document for any period commencing before 1 January 2019. Accordingly, the directors of 302
Ithaca Energy Limited have elected not to present comparative information which results in a departure from UK-adopted IAS. Opening 1 January 2019 and 31 December 2019 Statement of Financial Position 1 January 2019 31 December 2019 £’000 £’000 Assets Current assets Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . — 4,401 Trade and other receivables . . . . . . . . . . . . . . . . . . . . . . . . . 81,441 23,027 Amounts receivable from related parties . . . . . . . . . . . . . . . . . 111,356 2,005,938 Deposits, prepaid expenses and other receivables . . . . . . . . . . 3,518 665 Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72,346 6,980 268,661 2,041,011 Non current assets Long-term receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 445 Exploration and evaluation assets . . . . . . . . . . . . . . . . . . . . . — 920 Property, plant & equipment . . . . . . . . . . . . . . . . . . . . . . . . . 1,329,916 74,452 Deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 88,493 1,329,926 164,310 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,598,587 2,205,321 Liabilities And Equity Current liabilities Trade and other payables . . . . . . . . . . . . . . . . . . . . . . . . . . . (132,579) (68,996) Decommissioning liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . (7,494) (9,237) Bank overdrafts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (54) — (140,127) (78,233) Non current liabilities Decommissioning liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . (888,088) (290,450) Deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (184,555) — Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . (16,552) (10,404) (1,089,195) (300,854) Net Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 369,265 1,826,234 Shareholders’ equity Share capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221,000 221,000 Share premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119,245 119,245 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29,020 1,485,989 Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 369,265 1,826,234 2.1 Changes in accounting pronouncements International Financial Reporting Standards in issue but not yet effective. At the date of authorisation of the historical financial information, the IASB and IFRS Interpretations Committee have issued standards, interpretations and amendments which are applicable to IOG. For the next reporting period, applicable IFRS will be those endorsed by the UK Endorsement Board (UKEB). Whilst these standards and interpretations are not effective for, and have not been applied in the preparation of, this historical financial information, the following could potentially have a material impact on IOG’s historical financial information going forward. The directors are assessing the effect of these standards on IOG’s historical financial information. All the new standards effective as at 1 January 2023: • Classification of Liabilities as Current or Non-current—Amendments to IAS 1 • Definition of Accounting Estimates—Amendments to IAS 8 303
• Disclosure of Accounting Policies—Amendments to IAS 1 and IFRS Practice Statement 2 • Deferred Tax related to Assets and Liabilities arising from a Single Transaction—Amendments to IAS 12 Standards adopted as at 1 January 2019: IFRS 16 IOG assessed all contracts existing at 1 January 2019 to determine whether a contract contains a lease based upon the conditions in place as at 1 January 2019. Lease liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate at 1 January 2019. Right-of-use assets were measured at the amount equal to the lease liabilities, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognised in the statement of financial position immediately before 1 January 2019. The lease payments associated with leases for which the lease term ends within 12 months of the date of transition to IFRS and leases for which the underlying asset is of low value have been recognised as an expense on either a straight-line basis over the lease term or another systematic basis. 3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY Basis of measurement This HFI has been prepared on a going concern basis using the historical cost convention. Historical cost is generally based on the fair value consideration given in exchange for the assets. Going Concern Subsequent to the acquisition of IOG by IEUK, as per the Ithaca Group policy, IOG is under the Ithaca Group’s centralised treasury management arrangement and shares banking arrangements with the Ithaca Group of companies and therefore IOG’s ability to continue as a going concern is dependent on access to the Ithaca Group’s resources. The Ithaca Group directors consider the preparation of the Historical Financial Information on a going concern basis to be appropriate. This is due to the following key factors: • Commodity market performance. Brent has averaged over $105/bbl and UK Natural Gas has averaged over 211p/therm since 31 December 2021. Oil and gas prices are forecast to remain at high levels through the rest of 2022 and throughout 2023; • Liquidity headroom. As at 30 June 2022 the Ithaca Group held liquidity of US$335million (US$175 million available to be drawn upon within the Reserves Based Lending (“RBL”) facility, plus US$160 million cash) and as at 7 October 2022, the Ithaca Group maintains liquidity of US$447 million (US$275 million available to be drawn upon within the RBL facility, plus US$172 million cash); • Operational performance and a diversified portfolio, which has been further strengthened by the acquisitions of Siccar Point Group and Summit E&P as at 30 June 2022; and • Hedge positions, reducing price uncertainty. As at 7 October 2022, 46% of total budgeted Ithaca Group production for Q4 2022 was hedged, and 35 % of total budgeted Ithaca Group production was hedged for the full year 2023. The Ithaca Group directors closely monitor the funding position of the Ithaca Group throughout the year, including monitoring continued compliance with covenants and available facilities to ensure sufficient headroom to fund operations. The Ithaca Group directors have considered a number of risks applicable to the Ithaca Group that may have an impact on its ability to continue as a going concern. Short-term and long-term cash forecasts are produced on a weekly and quarterly basis respectively along with any related sensitivity analysis. This allows proactive management of any business risks, including liquidity risk discussed below. The Ithaca Group directors have reviewed the Ithaca Group’s forecasts and projections for the period to 31 December 2023, including forecast covenant compliance. Owing to fluctuations in commodity demand and price volatility, management prepared sensitivity analyses to the 304
forecasts and applied a number of downside plausible scenarios and stress tests for the whole Ithaca Group, including decreases in production, reduced sales prices, increases in operating and capital expenditure assumptions and exchange rate fluctuations. Management aggregated these scenarios to create a reasonable combined worst-case scenario. The sensitivity analysis showed that there was no reasonably possible scenario that would result in the business being unable to meet its obligations as they fall due. The Ithaca Group would still continue to have sufficient cash headroom throughout the period to 31 December 2023 (the ‘going concern period’) and still have the necessary liquidity to continue trading. The Ithaca Group directors have a number of mitigating actions within their control, including the further drawdown on its available funds from the RBL facility, the reduction in uncommitted capital expenditure, and the cancellation or deferral of future dividends. IOG has also obtained a letter of support from both Ithaca Energy (E&P) Limited and Ithaca Energy Limited (being intermediate parent companies of IOG) to provide financial support for the period up to and including 31 December 2023. Based on the assessment of the Ithaca Group’s financial position for the period to 31 December 2023 and the confirmation of continued parental support, the Ithaca Energy Limited directors are satisfied that they have a reasonable basis upon which to conclude that IOG is able to continue as a going concern throughout the going concern period. Accordingly, they continue to adopt the going concern basis of accounting in preparing the consolidated Historical Financial Information. Interest in joint operations IOG’s interest in joint operations (e.g. exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation, its share of revenue from the sale of output by the joint operation and its expenses (including its share of any expenses incurred jointly). Revenue The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for products in the normal course of business, net of discounts, customs duties and sales taxes. Foreign currency translation Items included in this financial information are measured using the currency of the primary economic environment in which IOG operates (the ‘functional currency'). The financial information is presented in Great British Pounds, which is IOG’s functional and presentation currency. Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of income. Financial instruments All financial instruments are initially recognised at fair value on the statement of financial position. IOG’s financial instruments consist of cash, trade and other receivables, deposits, amounts receivable from related parties, accounts payable and accrued liabilities. Under IFRS 9 all financial instruments will be recorded at amortised cost based on an analysis of the business model and terms of financial assets. There is no change to the classification of financial liabilities. All financial instruments are required to be measured at fair value on initial 305
recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. IFRS 9 classifications: Cash and cash equivalents are classified at amortised cost which equates to its fair value. Trade and other receivables and long term receivables are classified and carried at amortised cost as they have a business model of held to collect and the terms meet the solely payments of principal and interest criteria. Accounts payable, accrued liabilities and certain other long- term liabilities are classified as other financial liabilities. Cash and cash equivalents For the purpose of the statement of cash flow, cash and cash equivalents include investments with an original maturity of three months or less. Inventories—hydrocarbon and materials Inventories of materials and hydrocarbon inventory supplies are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is determined on the first-in, first-out method. Current hydrocarbon inventories are stated at net realisable value, which is based on estimated selling price less any further costs expected to be incurred to completion and disposal/sale. Non-current oil and gas inventories are stated at historic cost. Lifting or offtake arrangements for oil and gas produced in certain of IOG’s oil and gas properties are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative volume sold less inventory is an “underlift” or “overlift” and is measured at fair value. Movements during an accounting period are adjusted through cost of sales in the statement of income. Trade receivables Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts. For trade receivables, IOG applies a simplified approach in calculating expected credit losses “ECLs”. Therefore, IOG does not track changes in credit risk, but instead, recognises a loss allowance based on lifetime ECLs at each reporting date. IOG considers a financial asset in default when contractual payments are 90 days past due. However, in certain cases, IOG may also consider a financial asset to be in default when internal or external information indicates that IOG is unlikely to receive the outstanding contractual amounts in full before taking into account any credit enhancements held by IOG. A financial asset is written off when there is no reasonable expectation of recovering the contractual cash flows. Financial liabilities measured at amortised cost All other financial liabilities are initially recognised at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing. After initial recognition, other financial liabilities are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised in interest and other income and finance costs respectively. This category of financial liabilities includes trade and other payables and finance debt. 306
Derecognition of financial liabilities IOG derecognises financial liabilities when, and only when, IOG’s obligations are discharged, cancelled or have expired. The difference between the carrying amount of the financial liability derecognised and the consideration paid and payable is recognised in profit or loss. Property, plant and equipment Oil and gas expenditure—exploration and evaluation assets Capitalisation Pre-acquisition costs on oil and gas assets are recognised in the statement of income when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical and administrative expenses are capitalised as intangible exploration and evaluation (“E&E”) assets. E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following approved development sanction, the carrying value of the E&E asset is reclassified as a development and production (“D&P”) asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. In addition where the E&E asset forms part of an existing development and production CGU, such E&E activity is included in the carrying value of IOG’s D&P assets. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if IOG decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration and evaluation are written off to the statement of income in the period the relevant events occur. Oil and gas expenditure—development and production assets Capitalisation Costs of bringing a field into production, including the cost of facilities, wells and subsea equipment, direct costs including staff costs together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset. Depreciation All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate would be charged. Impairment For impairment review purposes IOG’s oil and gas assets are analysed into cash-generating units (“CGUs”) as identified in accordance with IAS 36. Individual assets are grouped into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. This grouping is based on a number of factors which include the infrastructure required to operate the asset, management operating plans (including consideration of hub strategies), internal management reporting, geographic location and operating licences. CGUs are identified consistently from period to period, unless a change is justified. A review is carried out each reporting date for any indicators that the carrying value of IOG’s assets may be impaired or previously impaired assets (excluding goodwill) where a reversal of a previous impairment may 307
arise. For assets where there are such indicators, an impairment test is carried out on the CGU. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. If the recoverable amount of an asset is estimated to be less that its carrying amount, the carrying amount of the asset is reduced to the recoverable amount. The resulting impairment losses are written off to the statement of income. Previously impaired assets (excluding goodwill) are reviewed for possible reversal of previous impairment at each reporting date. No impairment indicators were identified in the review performed by management for the year ended 31 December 2019. Therefore, no impairment test was performed. A previously recognised impairment loss is only reversed if there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognised. If this is the case, the carrying amount is increased to the recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation had no impairment loss been recognised in previous years. Non oil and natural gas operations Non oil and gas assets are initially recorded at cost and depreciated over their estimated useful lives on a straight line basis as follows— Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 years Computer and office equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 years Furniture and fittings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 years Decommissioning liabilities IOG records the present value of legal obligations associated with the retirement of long-term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long-term asset. Liabilities for decommissioning are recognised when IOG has an obligation to plug & abandon a well, dismantle and remove a facility or an item of plant and restore the site on which it is located, and when a reliable estimate can be made. Where an obligation exists for a new facility or well, such as oil & gas production or transportation facilities. The obligation arises when the asset is installed or the ground/environment is disturbed at the field location the amount recognised is the present value of the estimated future expenditure determined in accordance with the local regulations and requirements. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred. Taxation Current income tax Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date. Deferred income tax Deferred tax is recognised for all deductible temporary differences and the carry-forward of unused tax losses. Deferred tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in rates is included in earnings in the period of the enactment date. Deferred tax assets are recorded in the financial information if realisation is considered more likely than not. 308
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction. Leases IOG assesses at contract inception all arrangements to determine whether it is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. IOG is not a lessor in any transactions, it is only a lessee. IOG applies a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. IOG recognises lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. The right-of-use asset is depreciated over the useful life of the asset. IOG’s right-of-use assets are included in Property, Plant and Equipment (Note 11). At the commencement date of the lease, IOG recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, IOG uses its incremental borrowing rate at the lease commencement date because the interest rate implicit in the lease is generally not readily determinable. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset. IOG’s lease liabilities are included in Net finance costs and Other liabilities (Notes 7 and 14). Significant accounting judgements and estimation uncertainties The management of IOG has to make estimates and judgements when preparing the financial information of IOG. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and IOG’s result. The most important estimates and judgements in relation thereto are: Estimates in oil and gas reserves The business of IOG is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves requires critical judgement, factors such as the availability of geological and engineering data, reservoir performance data, and drilling of new wells all impact on the determination of IOG’s estimates of its oil and gas reserves and result in different future production profiles affecting prospectively the discounted cash flows used in impairment testing. These are based on an annual third party expert’s view and these volumes are used in the calculations for impairment tests and accounting for depletion and decommissioning. Changes in estimates of oil and gas reserves resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning and the depletion charges in accordance with the unit of production method. For the purposes of depletion and decommissioning estimates IOG use proved and probable reserves and for the purposes of the impairment tests performed, IOG considers the same probable and proved reserves as well as risked resource volumes. These risking adjustments are reflective of IOG’s progress of the overall field development and are reflective of a market participant view. 309
Estimates in impairment of oil and gas assets Determination of whether oil and gas assets have suffered any impairment requires an estimation of the fair value less costs to dispose of the CGU to which oil and gas assets have been allocated. When performing impairment tests of oil and gas assets, this assessment is performed on a post-tax basis. This includes a review of previously impaired assets for possible reversal of a previous impairment. The calculation requires IOG to estimate the future cash flows expected to arise from the CGU using discounted cash flow models comprising asset-by-asset life of field projections. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on internal view of forward curve prices that are considered to be a best estimate of what a market participant would use; discount rates which reflect management’s estimate of a market participant post-tax weighted average cost of capital; and commercial reserves. As the production and related cash flows can be estimated from IOG’s experience, management believes that the estimated cash flows expected to be generated over the life of each field is the appropriate basis upon which to assess individual assets for impairment or an impairment reversal. Furthermore, there is also uncertainty due to climate change and the speed of the energy transition and the likely impact this will have on both oil and gas demand for forecast prices. IOG have considered climate adjusted price curves in their assessment of forecast commodity prices. Decommissioning provision estimates Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements, technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis. The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. While IOG uses its best estimates and judgement, actual results could differ from these estimates. Expected timing of expenditure can also change, for example in response to changes in laws & regulations or their interpretation, and/or due to changes in commodity prices. The payment dates are uncertain and depend on the production life of the respective fields. A nominal discount rate of 4% is used to discount the estimated costs. Initial recognition of amounts receivables from related parties To assess the initial measurement of its interest-free and repayable on demand loans to related parties, IOG uses its best estimates and judgement to determine that the right to receive payments are substantive at the inception of the transaction and there are no differences between the face value and fair value of the loan, and take it to account factors like the capacity of the guarantor to repay the loan and the amount of time it would take. Impairment of financial assets measured at amortised cost If the credit risk on the financial asset has increased significantly since initial recognition, the loss allowance for the financial asset is measured at an amount equal to the lifetime expected credit losses. In other instances, the loss allowance for the financial asset is measured at an amount equal to the twelve month expected credit losses (ECLs). Changes in loss allowances are recognised in profit and loss. IOG assesses current economic environment and future credit risk outlook to monitor changes in expected credit losses on financial assets measured at amortised cost and no significant impact was determined. Taxation judgement IOG’s operations are subject to a number of specific tax rules which apply to exploration, development and production. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of estimates and judgements including those required in calculating the effective tax rate. IOG recognises deferred tax assets on unused tax losses 310
where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised. 4. SEGMENTAL REPORTING IOG operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area presently being the North Sea. All material revenue from external customers and non-current assets are attributed to/located in the UK, IOG’s country of domicile. 5. REVENUE Revenue with external customers 2019 £’000 Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 635,248 Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155,289 Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,862 794,399 Before the acquisition by Ithaca Energy Limited, IOG’s largest customers were other entities in the Chevron Corporation—Chevron Products Company (£331m) and Chevron Natural Gas Europe (£112m). The other customer contributing more than 10% of revenue in the year was BP Oil International Limited (£109m). 6. COST OF SALES 2019 £’000 Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275,476 Movement in oil and gas inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,549) Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131,911 403,838 7. NET FINANCE COSTS 2019 £’000 Bank interest and charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,154 Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13,960) Unwinding of decommissioning discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,925 13,119 8. TRADE AND OTHER RECEIVABLES Current 2019 £’000 Trade debtors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 692 Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,335 23,027 IOG applies the simplified approach for trade receivables and applies a provision matrix taking into account history of default and forward looking factors. There is no history of defaults and no forward looking factors that imply a risk for credit loss, therefore no expected credit loss has been recognised. Included within other assets are a receivable for reclaimed VAT (£6m) and the partner share of expenditures in joint operations (£10m). 311
9. INVENTORY Current 2019 £’000 Hydrocarbon inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,229 Materials inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,751 6,980 10. EXPLORATION AND EVALUATION ASSETS £’000 At 1 January 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 920 At 31 December 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 920 11. PROPERTY, PLANT AND EQUIPMENT Right of use operating assets Development & Producing assets Total £’000 £’000 £’000 Cost At 1 January 2019 . . . . . . . . . . . . . . . . . . . . . 7,265 5,266,428 5,273,693 Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 115,204 115,204 Revision to decommissioning liability (Note 13) . . . — (35,891) 35,891 Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (4,769,397) (4,769,397) At 31 December 2019 . . . . . . . . . . . . . . . . . . . 7,265 576,344 583,609 DD&A and Impairment At 1 January 2019 . . . . . . . . . . . . . . . . . . . . . — 3,943,777 3,943,777 Disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,566,531) (3,566,531) DD&A charge for the period . . . . . . . . . . . . . . . 2,564 129,347 131,911 At 31 December 2019 . . . . . . . . . . . . . . . . . . . 2,564 506,593 509,157 NBV at 1 January 2019 . . . . . . . . . . . . . . . . . . 7,265 1,322,651 1,329,916 NBV at 31 December 2019 . . . . . . . . . . . . . . . . 4,701 69,751 74,452 Equity interests in nine of IOG’s assets were transferred to other entities within the Ithaca Group effective 17 December 2019. These assets were transferred through a loan mechanism at fair market value. The aggregate value of the net assets disposed of was approximately £160 million and the non-cash consideration was approximately £1.124 billion, resulting in a gain on sale of £964 million and an associated intercompany receivable balance. The assets transferred were Captain, Erskine, Britannia and satellite fields, Elgin-Franklin and Jade. Alba remains within IOG along with the decommissioning liabilities for Heather and Strathspey. Security provided against related party facilities The assets of Ithaca Oil and Gas Limited are included withing the guarantor group for the Reserves Based Lending (RBL) facility of Ithaca Energy (UK) Limited. The RBL availability is approximately $1.225 billion with a maturity to April 2026. 12. TRADE AND OTHER PAYABLES 2019 £’000 Trade payables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 687 Current tax payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52,253 Lease liabilities (Note 14) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,573 Accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,483 68,996 312
13. DECOMMISSIONING LIABILITIES 2019 £’000 Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 895,582 Unwinding of discount on provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,925 Ithaca group balance transfers on restructure . . . . . . . . . . . . . . . . . . . . . . . . (580,723) Utilisation of provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,206) Revision to estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (35,891) Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 299,687 The total future decommissioning liability was calculated based on net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. IOG used a risk free rate of 4.0 percent and an inflation rate of 2.0 percent over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 12 years. The economic life and the timing of the obligations are dependent on commodity price and the future production profiles of the respective production and development facilities and Government legislation. As described in Note 11, interests in nine assets were transferred to other Ithaca group entities effective 17 December 2019. Chevron Corporation have the obligation to provide the security and remain financially responsible for the decommissioning obligations of IOG’s interest in the Strathspey field and the resulting decommissioning reimbursement is retained by Ithaca Energy Limited. 14. OTHER NON CURRENT LIABILITIES Other non-current liabilities 2019 £’000 Lease liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,264 Other creditors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,140 10,404 On 1 January 2019, IOG adopted IFRS 16, which resulted in the recognition of a right of use asset and associated lease liability. The note below shows the movement in the recognised lease liability throughout 2019. IOG’s interest expense related to lease liabilities are included in Net finance costs and the lease liabilities are included in Trade and Other Payables and Other non-current liabilities (Notes 12 and 14). Other creditors relates to a contingent payable due to Canadian Natural Resources pursuant to IOG’s acquisition of their interest in the Strathspey field in 2013, relating to the decommissioning cost, this amount is in addition to the decommissioning liability for Strathspey included in Note 13. Lease liability 2019 £’000 At 1 January . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,265 Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 360 Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,788) At 31 December . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,837 Current (Note 12) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,573 Non-current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,264 4,837 The lease liabilities at 31 December 2019 relate to the office lease. The incremental borrowing rate applied to these leases is 5.83%. 313
Deferred income tax at 31 December 2019 relates to the following: 2019 £’000 Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (20,893) Deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,386 Net deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88,493 The gross movement on the deferred income tax account is as follows: At 1 January . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (184,555) Income statement credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273,048 At 31 December . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88,493 Deferred tax liability Other Accelerated tax depr’n Total £’000 £’000 £’000 At 1 January 2019 . . . . . . . . . . . . . . . . . . . . . . . . . 18,619 524,169 542,788 Movement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (16,448) — (16,448) Origination and reversal of temporary differences . . . . — (505,447) (505,447) At 31 December 2019 . . . . . . . . . . . . . . . . . . . . . . 2,171 18,722 20,893 Deferred tax assets Tax Losses Total £’000 £’000 At 1 January 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 358,233 358,233 Origination and reversal of temporary differences . . . . . . . . . . . . . (248,847) (248,847) At 31 December 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,386 109,386 Deferred income tax assets are recognised for the carry-forward of unused tax losses and unused tax credits to the extent that it is probable under current tax legislation and using enacted tax rates that taxable profits will be available in the future against which the unused tax losses/credits can be utilised. The carrying value of the net deferred tax asset at 31 December 2019 of $88 million is supported by estimates of IOG’s future taxable income. 17. COMMITMENT Capital commitments 2019 £’000 Capital commitments incurred jointly with other ventures (Ithaca Energy’s share) . . . 3,500 18. FINANCIAL INSTRUMENTS IOG has identified that it is exposed principally to these areas of market risk. Commodity Risk Commodity price risk related to crude oil prices is IOG’s most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as Opec actions, political events and supply and demand fundamentals. IOG is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. IOG’s expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. Foreign Exchange Rate Risk IOG is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in GB Pounds. Since time passes between the recording of a receivable or payable transaction and its collection or payment, IOG is exposed to gains or 315
losses on non-GBP amounts and on balance sheet translation of monetary accounts denominated in non-GBP amounts upon spot rate fluctuations from quarter to quarter. Credit Risk IOG’s accounts receivable with customers in the oil and gas industry are subject to normal industry credit risks and are unsecured. Prior to the acquisition by IEUK in December 2019, oil production was sold to BP Oil International and gas was sold to Chevron Limited. From December 2019 oil production was sold to BP Oil International and gas production to BP Gas Marketing. IOG assesses partners’ credit worthiness before entering into farm-in or joint venture agreements. In the past, IOG has not experienced credit loss in the collection of accounts receivable. As IOG’s exploration, drilling and development activities expand with existing and new joint venture partners, IOG will assess and continuously update its management of associated credit risk and related procedures. IOG applies the simplified approach for trade receivables and applies a provision matrix taking into account history of default and forward-looking factors. There is no history of defaults and no forward-looking factors that imply a risk for credit loss, therefore no expected credit loss has been recognised. IOG regularly monitors all customer receivable balances outstanding in excess of 90 days. As at 31 December 2019, substantially all accounts receivables are current, being defined as less than 90 days. For balances due from related parties IOG applies the simplified approach and considers the lifetime expected credit loss at each reporting date. Taking account of currently available information and that the related parties have on parental support and forward-looking data it has been assessed that the companies are profit generating and/or in a net asset position supporting the value of the related party balances. IOG also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values. Liquidity Risk Liquidity risk includes the risk that as a result of its operational liquidity requirements IOG will not have sufficient funds to settle a transaction on the due date. IOG manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. IOG considers the maturity profiles of its financial assets and liabilities. As at 31 December 2019 substantially all accounts payable were current. The following table shows the timing of cash outflows relating to trade and other payables as at 31 December 2019: Within 1 year 1 to 5 years £’000 £’000 Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . 14,170 — Lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,788 2,323 Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,140 19. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES Financial instruments of IOG consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in the historical financial information. At 31 December, the classification of financial instruments and the carrying amounts reported on the balance sheet and their estimated fair values are as follows: Classification Carrying Amount 2019 £’000 Fair Value Amounts receivable from related parties . . . . . . . . . . . . . . . . . . . 2,005,938 2,005,938 316
20. RELATED PARTY TRANSACTIONS IOG’s immediate parent undertaking is IEUK, and the ultimate parent Company is Delek Group Limited, a company incorporated in Israel. IOG’s ultimate controlling party is Mr. Yitzhak (Sharon) Tshuva. The following table provides the loan balances with related parties as at 31 December: Amounts receivable from related parties 2019 £’000 Ithaca Energy UK Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,741,576 Ithaca Minerals (North Sea) Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204,456 Ithaca Alpha (NI) Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,617 Ithaca GSA Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,417 Ithaca Energy Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,269 Ithaca Gamma Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,603 2,005,938 Prior to the acquisition of IOG by IEUK, the remuneration of key management personnel was as follows— 2019 £’000 Remuneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,018 Long term incentive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 363 4,381 No compensation was payable in respect of loss of office during the financial year. Following the acquisition by Ithaca Energy (UK) Limited, remuneration to key management personnel was paid by another company in the group, IEUK. It is not practicable to perform an allocation of remuneration between the respective group companies as such amounts are earned in respect of the director’s services to the group of companies as a whole. All relevant disclosures are made within the Historical Financial Information of Ithaca Energy Limited. 21. SUBSEQUENT EVENTS Given the twin challenges that arose in Q1-2020 of Covid-19 and the dramatic fall in oil prices, the main focus of IOG’s response to these issues was centered on maintaining the health of the workforce and reducing the risk of spreading the virus, whilst at the same time preserving the operational and financial resilience of the business. To minimise the risks to personnel presented by Covid-19 and simultaneously preserve operational continuity, IOG reduced the number of personnel on each of its operated offshore facilities in March 2020 to the minimum level required to safely maintain production and execute any critical maintenance work scopes. The planned 2020 investment programme announced at the start of the year involved investments in a range of infill drilling and subsea satellite developments designed to enhance production and reserves over the coming years including on the Alba asset. As a consequence of managing the Covid-19 situation and proactively preserving the liquidity and cash flow resilience of the business in the face of significantly lower commodity prices, various activities in the 2020 capital programme have been stopped and deferred until a more suitable time. This includes the Alba infill drilling campaign that commenced at the end of 2019 and the Fotla exploration well. The majority of the amended and deferred capital investment programmes are not specifically centred on activities that are scheduled to materially impact 2020 production. In the short term the reductions in production arising from the deferred infill drilling activities are expected to be largely offset by shorter than originally forecast planned maintenance shutdowns on the platforms and infrastructure serving the producing asset portfolio. The reduced durations are a natural consequence of the measures that need to be taken to manage the prevailing Covid-19 related personnel and equipment restrictions. Though the maintenance activities that had been planned for completion this year will ultimately need to be rescheduled for 2021 and beyond. The exact impact of this on forecast production in future years is being assessed as part of the 317
on-going work being undertaken by IOG and the wider industry to optimise forward work programmes. As a consequence of the oil price decline, the Alba asset was impaired by $32.9 million in 2020. An impairment review was carried out at the end of both 2Q and 3Q 2021 driven by the higher forward curve for both oil and gas prices resulting in reversals of $10.8m on Alba. In addition to these impairment reviews performed an annual review of all oil and gas assets at 4Q21 resulting in a further reversal of $18m on Alba. An agreement to acquire 13.3% additional interest in the Alba field from Mitsui E&P UK Limited was signed on 17 September 2021. At completion this took IOG’s interest in the Alba field to 36.7%. On 27 February 2022, a conflict broke out between Russia and Ukraine. Following this, numerous governments around the world have implemented sanctions against Russia and Belarus. The Directors have considered the implications of the ongoing conflict on key assumptions and judgments. This consideration has been made on the recognition and measurement of accounting estimates and the related financial statements disclosure. The assessment included specific review of the supply chain; funding sources; customer; credit risk and cyber security. The Directors do not consider there to be any significant impact on IOG at this stage. On 14 July 2022 the UK Government enacted a temporary windfall tax of 25% on the profits of oil and gas companies called the Energy Profits Levy (“EPL” or “the Levy”). The Levy is charged upon oil and gas profits calculated on the same basis as Ring Fence Corporation Tax (“RFCT”) however excludes relief for decommissioning and finance costs. RFCT losses and Investment Allowance are not available to offset the EPL. At the date of this historical financial information the Directors are still assessing the impact for IOG. 318
PART 14—PROFIT FORECASTS 1. CURRENT YEAR PROFIT FORECAST In the Delek Group Q1 Announcement, the Delek Group made the following EBITDAX forecast for the Company in relation to the current financial year: • “To Ithaca’s estimation, subject to the closing of the transaction, considering its production quantities and forecast oil and gas prices, Ithaca’s EBITDAX in 2022 is expected to reach a sum of approx. $2 billion.” As at the date of this Registration Document, the Directors have replaced the guidance as a result of their current view on production quantities for the remainder of the year together with the ongoing volatility in oil and gas prices and, their current expectation for the year ending 31 December 2022, is that Adjusted EBITDAX of Ithaca Energy is expected to be between $1.7 billion to $2.3 billion. The statement that the Company is expected to reach an Adjusted EBITDAX for the financial year ended 31 December 2022 constitutes a profit forecast for the purpose of the Prospectus Regulation Rules (the “Current Year Profit Forecast”). The Directors confirm that the Current Year Profit Forecast is valid as at the date of this document. Basis of preparation The Current Year Profit Forecast has been properly compiled on the basis of the assumptions stated below and on a basis consistent with the accounting policies used in Ithaca Energy’s annual report for the year ending 31 December 2021, which are prepared in accordance with IFRS and which are those expected by Ithaca Energy to be applicable for the year ending 31 December 2022. The Directors prepared the Current Year Profit Forecast on the basis of: (i) the audited interim financial statements of the Group for the six months ended 30 June 2022; (ii) the unaudited income statement to Adjusted EBITDAX of Ithaca Energy for the six months ended 30 June 2022; and (iii) the projected financial performance of Ithaca Energy for the remaining six months of the year ending 31 December 2022. “Adjusted EBITDAX”, as used in the Current Year Profit Forecast, consists of profit for the period before income tax, net finance costs, put premiums on oil derivative instruments, put premiums on gas derivative instruments, revaluation of forex forward contracts, revaluation of commodity hedges, depletion, depreciation and amortisation, impairment (charge) / reversal, exploration and evaluation expenses, fair value gain / (losses) on contingent consideration, gain on bargain purchase, transaction costs and employee voluntary redundancy programme. Transaction costs and employee voluntary redundancy programme include costs that are not considered to be representative of underlying operations. The Current Year Profit Forecast is expressed in terms of Adjusted EBITDAX rather than profit / (loss) after tax, as the Directors believe this metric is more useful to investors for the following reasons: (i) it is used by management for planning and internal reporting purposes; and (ii) it is in line with peer companies and expectations of the investor community, supporting easier comparison of Ithaca Energy’s performance with its peers. Assumptions The principal assumptions on which the Current Year Profit Forecast was based, which are outside the influence or control of the Directors are: (i) there will be no material change to the existing prevailing macroeconomic or political conditions in the regions in which the Group operates, including the global governmental responses to COVID-19 being materially in line with the level assumed in the Current Year Profit Forecast; (ii) there will be no material change to the range of oil and gas prices realised by the Group currently assumed in the Current Year Profit Forecast; (iii) there will be no material change to the range of production volumes delivered across the Group’s portfolio of oil and gas assets currently assumed in the Current Year Profit Forecast; (iv) there will be no material change to the tariffs received relating to third party usage of the Group’s owned infrastructure; 319
(v) there will be no counterparty default in relation to the hedging contracts that the Group has entered into; (vi) there will be no deterioration in the Group’s customer relationships, contractual terms and no customer default which is material in the context of the Group; (vii) there will be no material unplanned operating expenditure related to oil and gas infrastructure and assets of the Group; (viii) there will be no material movements in foreign currency exchange rates compared with the range of foreign currency exchange rates assumed in the Current Year Profit Forecast; (ix) there will be no material change in legislation or regulatory requirements that impact the Group’s operations or its accounting policies; (x) there will be no material change in inflation, interest, or tax rates in the Group’s principal regions it operates in compared with the Current Year Profit Forecast; (xi) there will be no business disruptions that materially affect the Group, its customers, or operations, including unplanned shutdowns of producing assets and infrastructure, cyber-attacks, technological issues, and natural disasters; and (xii) there will be no litigation, contractual dispute, regulatory action or industrial action which is material in the context of the Current Year Profit Forecast. The principal assumptions on which the Current Year Profit Forecast was based, which are within the influence or control of the Directors are: (i) there will be no material change to the Group’s existing operational structure and strategy; (ii) there will be no material change to the Group’s production licences; (iii) there will be no material change to the hedging profile currently assumed in the Current Year Profit Forecast; (iv) there will be no material change in the current key management of the Group; and (v) there will be no material asset acquisitions or disposals. 2. LONG TERM FINANCIAL FORECAST In accordance with applicable disclosure requirements under Israeli law and the rules of the Tel Aviv Stock Exchange, in its annual report for the year ended 31 December 2021, DGL included a valuation report in connection with impairment testing of the Group under IAS 36 prepared by Kroll Advisory Ltd (the “Kroll Report”). The Kroll Report was dated 28 March 2022 and was prepared based on a valuation date of 31 December 2021. The Kroll Report included certain financial projections for the Group, including projected EBITDA for each of the years ending 31 December 2022 to 31 December 2042 (the “Projected EDITDA Information”). The Company considers the Projected EBITDA Information in the Kroll Report to constitute in its entirety an outstanding but no longer valid profit forecast in respect of the Group for the following reasons: (i) the Kroll Report was prepared on a valuation date as at 31 December 2021 and was dated 28 March 2022, therefore the Kroll Report was prepared before IEUK entered into the agreement to acquire SPEHL on 7 April 2022. The SPEHL acquisition was therefore not in contemplation when the Projected EBITDA Information was prepared and the Projected EBITDA Information therefore does not reflect production of oil by SPEHL or any of the costs and benefits to the Group arising from the SPEHL acquisition, which completed on 30 June 2022; and (ii) the Projected EDITDA Information is based on assumptions around forecast Brent oil price and inflation rates as at the 31 December 2021 valuation date. The Kroll Report acknowledges that events subsequent to the 31 December 2021 valuation date, and in particular the Russia-Ukraine conflict, have affected the global economy and the energy sector and resulted in a substantial increase in crude oil and gas prices. The Kroll report explicitly states that the impact of these subsequent events was not reflected in the Kroll Report’s analysis, and that the analysis and valuation would likely have varied materially had such impact been considered. 320
The Company considers that, in light of the factors described in (i) and (ii) above, such factors have materially impacted the Projected EBITDA Information for the year ending 31 December 2022, and consequently the longer-term Projected EBITDA Information for the years ending 31 December 2023 to 31 December 2042 are subject to even greater impact. As a result, the Company considers the Projected EDITDA Information to no longer be valid in its entirety. 321
PART 15—ADDITIONAL INFORMATION 1. RESPONSIBILITY 1.1 The Company and the Directors, whose names appear in Part 6 (Directors, Senior Managers and Corporate Governance), accept responsibility for the information contained in this Registration Document. To the best of the knowledge of the Directors and the Company, the information contained in this Registration Document is in accordance with the facts and this Registration Document makes no omissions likely to affect its import. 1.2 The Competent Person accepts responsibility for the NSAI CPR contained in Part 18 (Competent Person’s Report). To the best of the knowledge of the Competent Person, the information contained in the NSAI CPR, including the estimates of reserves section contained therein, is in accordance with the facts and makes no omissions likely to affect its import. 2. THE COMPANY 2.1 The Company was incorporated and registered in England and Wales on 15 October 2019 under the 2006 Act as a private company limited by shares under the name “Delek North Sea Limited” with company number 12263719. It changed its name to Ithaca Energy Limited on 7 October 2022. The Company’s LEI is 21380057TNFLXPXBIP34. 2.2 The principal activity of the Company is to act as the holding company of the Group. The principal activity of the Group is the appraisal, development of, and production from, UK North Sea oil and gas properties. The principal legislation under which the Company operates, and under which the Ordinary Shares have been created, is the 2006 Act and regulations made thereunder. The Company is operating in conformity with its constitution. 2.3 The Company is domiciled in the United Kingdom with its registered office at 23 College Hill, London, EC4R 2RP and its telephone number is +44 (0) 1224 334 000. The Registrar of the Company is Computershare Investor Services plc. 2.4 The Company’s accounting reference date is 31 December. For the period covered by the historical financial information contained in Part 13 (Historical Financial Information), the Group’s auditor for (i) the year ended 31 December 2021 (and the six months ended 30 June 2022) was Deloitte LLP of 1 New Street Square, London, United Kingdom, EC4A 3HQ; and (ii) the years ended 31 December 2019 and 31 December 2020 was Ernst & Young LLP of 1 More London Place, London, SE1 2AF. Both Deloitte LLP and Ernst & Young LLP are registered to carry out audit work by the Institute of Chartered Accountants in England and Wales. 2.5 The Company’s website address is www.ithacaenergy.com. The information on the website does not form part of this Registration Document unless that information is incorporated by reference into this Registration Document. 3. ORGANISATIONAL STRUCTURE 3.1 The Company is the principal holding company of the Group and a wholly owned subsidiary of DKL Energy. DKL Energy is a wholly owned subsidiary of DKL Investments, which is in turn a wholly owned subsidiary of DGL. DGL’s shares are traded on the Tel Aviv Stock Exchange (TASE: DLEKG). The controlling shareholder in DGL is Mr. Yitzhak Sharon Tshuva who, as at the Latest Practicable Date, held 50.2% of the voting rights in DGL. Further details of the share capital structure are set out in Part 7 (Principal Shareholders and Related Party Transactions) and paragraph 4 (Share Capital of the Company) of this Part 15 (Additional Information). 322
3.2 The diagram below sets out the simplified Group structure as at the date of this Registration Document. Delek Group Ltd. Israel TASE Listed Ithaca Energy Holdings (UK) Limited Scotland Ithaca Energy (UK) Limited Scotland Ithaca Energy (Holdings) Limited Bermuda Ithaca Energy (North Sea) Plc Scotland Ithaca Energy Limited England & Wales Ithaca Energy (E&P) Limited Jersey Additional Wholly Owned Ithaca Energy Subsidiaries DKL Energy Limited Jersey 100% Indirect Ownership 3.3 The following table shows details of the Company’s significant subsidiaries, all of which are held 100% (directly or indirectly) by the Company: Name Country of Incorporation or Residence Principal Activity Ithaca Energy (E&P) Limited . . . Jersey Holding company Ithaca Energy (North Sea) Plc . . Scotland Raising of and holding a $625 million Bond listed on The International Stock Exchange Ithaca Energy (UK) Limited . . . . Scotland Oil and gas appraisal, development and production and intermediate holding company Ithaca Minerals (North Sea) Limited . . . . . . . . . . . . . . . . Scotland Oil and gas appraisal, development and production Ithaca GSA Holdings Limited . . . Jersey Intermediate holding company 323
Name Country of Incorporation or Residence Principal Activity Ithaca Energy Developments UK Limited . . . . . . . . . . . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca GSA Limited . . . . . . . . . . Jersey Oil and gas appraisal, development and production Ithaca Oil and Gas Limited . . . . . England & Wales Oil and gas appraisal, development and production Ithaca Exploration Limited . . . . . England & Wales Dormant Ithaca MA Limited . . . . . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca MA(NS) Limited . . . . . . . England & Wales Dormant Ithaca SP UK Limited . . . . . . . . England & Wales Dormant Ithaca Dorset Limited . . . . . . . . England & Wales Dormant Ithaca SP (Holdings) Limited . . . England & Wales Intermediate holding company Ithaca SP Finance Limited . . . . . England & Wales Financing vehicle Ithaca SPE Limited . . . . . . . . . . England & Wales Intermediate holding company Ithaca SP (O&G) Limited . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca SP (E&P) Limited . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca SP Bonds plc . . . . . . . . . England & Wales Raising of and holding a $200 million Bond listed on Nordic ABM Ithaca Zeta Limited . . . . . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca Energy (Holdings) Limited . . . . . . . . . . . . . . . . Bermuda Intermediate holding company FPF1 Limited . . . . . . . . . . . . . . Jersey Dormant Ithaca Energy Holdings (UK) Limited . . . . . . . . . . . . . . . . Scotland Intermediate holding company Ithaca Petroleum Limited . . . . . . England & Wales Intermediate holding company Ithaca Gamma Limited . . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca Alpha (N.I.) Limited . . . . . Northern Ireland Oil and gas appraisal, development and production Ithaca Epsilon Limited . . . . . . . . England & Wales Oil and gas appraisal, development and production Ithaca Causeway Limited . . . . . . England & Wales Dormant Ithaca Petroleum EHF . . . . . . . . Iceland Dormant 4. SHARE CAPITAL OF THE COMPANY 4.1 Issued share capital of the Company As at the date of this Registration Document, the issued share capital of the Company is 1,201 comprising 1,001 A Ordinary Shares, 100 B1 Ordinary Shares and 100 B2 Ordinary Shares, all of which are fully paid. 324
The Company has no convertible securities, exchangeable securities or securities with warrants in issue. 4.2 History of the Share Capital On 15 October 2019, the Company was incorporated as a private limited company with an issued share capital of 1,000 ordinary shares of $1 each held by DKL Energy. On 17 October 2019, one additional ordinary share of $1 was issued to DKL Energy. On 29 September 2022, in connection with the MEP (further details of which are set out in paragraph 8.4 (Management Equity Plan) of this Part 15 (Additional Information): • the 1,001 ordinary shares of $1 each in the capital of the Company were reclassified as “A ordinary shares” of $1 each in the capital of the Company (the “A Ordinary Shares”); • 100 B1 Ordinary Shares were issued to Gilad Myerson; • 100 B2 Ordinary Shares were issued to Gilad Myerson; and • the Company adopted new articles of association. 4.3 Share Capital Reorganisation In connection with the expected admission to the London Stock Exchange, the Group intends to implement a share capital reorganisation to take effect prior to the expected date of admission (the “Share Capital Reorganisation”) in order to ensure that the share capital structure is appropriate for a public company. 4.4 Share Capital confirmations As at the date of this Registration Document and save as otherwise disclosed in this Part 15 (Additional Information): 4.4.1 no share or loan capital of the Company has, since its incorporation, been issued or agreed to be issued, or is now proposed to be issued, fully or partly paid, either for cash or for a consideration other than cash, to any person; 4.4.2 there has been no change in the amount of the issued share or loan capital of the Company since its incorporation; 4.4.3 no commissions, discounts, brokerages or other special terms have been granted by the Company in connection with the issue or sale of any share or loan capital of the Company, since its incorporation; 4.4.4 no share or loan capital of the Company is under option or agreed, conditionally or unconditionally, to be put under option; and 4.4.5 the Company holds no treasury shares (as defined in the 2006 Act). 4.5 Authorisations relating to the share capital of the Company In connection with the expected admission to the London Stock Exchange, the Company is expected to obtain shareholder approvals to effect the Share Capital Reorganisation referred to paragraph 4.3 (Share Capital Reorganisation) of this Part 15 (Additional Information). In addition, the Company expects to obtain shareholder approvals which are customary for a listed company and which will remain in place until the Company’s first annual general meeting following expected admission. 5. SUMMARY OF THE ARTICLES 5.1 The following description of certain provisions of the Articles, which were adopted on 29 September 2022, does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of the Articles. The Articles are articles suitable for a private limited company incorporated in England and Wales. Should the Group proceed with a public listing on the London Stock Exchange, the Company intends to adopt a set of articles of association (the “PLC Articles”) suitable for a public company incorporated in England and Wales. 325
These Articles were adopted as part of the Management Equity Plan further details of which are set out in paragraph 8.4 of this Part 15 (Additional Information), and the rights attaching to the shares issued pursuant to the current Articles are modified pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted. The Articles of the Company include provisions to the following effect: Objects The Articles contain no restriction on the objects of the Company. Accordingly, pursuant to section 31 of the 2006 Act, the Company’s objects are unrestricted. Capital structure The share capital of the Company is comprised of A Ordinary Shares, B1 Ordinary Shares and B2 Ordinary Shares having the rights described in the Articles. Voting rights Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, each holder of an A Ordinary Share is entitled to receive notice of and to attend and speak at any general meetings of the Company and each holder of an A Ordinary Share shall be entitled to vote on each A Ordinary Share that they hold. Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, the B1 Ordinary Shares and the B2 Ordinary Shares do not confer on the holders of such shares any right to receive notice of, or to attend, speak or vote at, any general meeting of the Company. Dividends and distributions Subject to the 2006 Act and as set out in the Articles, the Company may by ordinary resolution declare dividends but no dividend shall exceed the amount recommended by the Board. No dividend may be paid otherwise than in accordance with the 2006 Act. The Board may at any time declare and pay such interim dividends as appears to be justified by the position of the Company. Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, each holder of an A Ordinary Share is entitled to be paid pro rata according to the number of issued A Ordinary Shares held by them, any profits of the Company which the directors lawfully determine to distribute in respect of the relevant financial year. Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, the B1 Ordinary Shares and the B2 Ordinary Shares do not confer on the holders of such shares any rights to profits of the Company which the directors lawfully determine to distribute in respect of the relevant financial year. Any dividend or other moneys payable in respect of a share may be paid: • by cheque sent by post to the address in the register of members of the Company of the person entitled to the moneys; • by bank transfer to such account as the person or persons entitled to the moneys may in writing direct; or • by such other method of payment approved by the Board as the person or persons entitled to the moneys may in writing agree to. Capital rights—Exit events Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, on the occurrence of: (i) a 326
change of control of the Company; (ii) a sale of at least 75% of the business and assets of the Group; (iii) a sale of 75% or more of the issued share capital of any immediate subsidiary or subsidiaries of the Company to the extent that it or they comprises 75% of the value of the Group; (iv) the sale or other disposal of 60% or more of the issued share capital of the Company, IEEPL, or any intermediate holding company that owns each of IEUK, Ithaca Energy Holdings Limited and Ithaca Energy Holdings (UK) Limited; or (v) a liquidation of the Company (an “Exit”), then net value of any equity proceeds paid to shareholders following the occurrence of such event (the “Proceeds”) fall to be distributed as follows: • firstly, the holders of the A Ordinary Shares shall receive an amount equal to $2.5 billion (plus the aggregate amount of any sums realised by the Company in connection with any subscription for, or issue of, shares (but excluding any proceeds raised from the issue of shares in relation to admission where such proceeds are used to settle any intercompany debt between members of the Group) and less the value of the distributions made by the Company) and less $1million (being the amount of one-off payment referred to in paragraph 7.6 of Part 15 (Additional Information)) (the “Hurdle Amount”) pro rata to the number of A Ordinary Shares held by each of them; • secondly, the holders of the B1 Ordinary Shares shall receive an amount equal to 1% of the Proceeds above the Hurdle Amount pro rata to the number of B1 Ordinary Shares held by each of them; • thirdly, but only if the Exit takes place on or after 1 October 2024, the holders of the B2 Ordinary Shares shall receive an amount equal to 0.3% of the Proceeds above the Hurdle Amount pro rata to the number of B2 Ordinary Shares held by each of them; and • fourthly, the holders of the A Ordinary Shares shall receive the balance of the Proceeds above the Hurdle Amount pro rata to the number of A Ordinary Shares held by each of them. For the avoidance of doubt, in the event that the Proceeds are equal to or less than the Hurdle Amount, the B1 Ordinary Shares and the B2 Ordinary Shares shall not carry any rights to receive any share of such Proceeds. Capital rights—Listing Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, on the occurrence of a listing of any member of the Group’s securities on a stock exchange (such as admission), then the market value of the entire issued share capital of the Company (as determined by reference to the price per share at which shares are to be offered for sale, placed or otherwise marketed pursuant to such listing) (the “Listing Value”) will fall to be divided between the holders of the A Ordinary Shares, B1 Ordinary Shares and B2 Ordinary Shares on the same basis as the division of Proceeds in connection with an Exit, save that the holders of the B2 Ordinary Shares shall receive an amount equal to 0.3% of the Listing Value above the Hurdle Amount regardless of when the listing occurs. For the avoidance of doubt, in the event that the Listing Value is equal to or less than the Hurdle Amount, the B1 Ordinary Shares and the B2 Ordinary Shares shall not carry any rights to receive any share of such Listing Value. On or shortly prior to the occurrence of a listing (such as admission), the A Ordinary Shares, B1 Ordinary Shares and B2 Ordinary Shares shall be converted into such number of ordinary shares of the Company as is equal to the relevant shareholder’s proportionate share of the Listing Value that each class of shares is entitled to receive. Redemption Subject to the provisions of the 2006 Act and the Articles, the Company can issue shares which are required to be redeemed and shares which may be redeemed at the option of the Company or the relevant member. 327
Issue of shares Subject to the provisions of the 2006 Act and without prejudice to any rights attaching to any existing shares, shares may be issued with such rights or restrictions as the Company may, by ordinary resolution, determine or in the absence of such determination, or as far as any such resolution does not make specific provision, as the Board may determine. Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, in no case may new B1 Ordinary Shares or B2 Ordinary Shares be issued without the consent of the holders of all the B1 Ordinary Shares and the B2 Ordinary Shares. Form and transfer of shares The Board may issue shares as certificated or uncertificated shares, subject to any restrictions on transfers described below. A share held in certificated form may be transferred by an instrument of transfer in any usual form or in any other form which the Board may approve, which shall be executed by or on behalf of the transferor and, unless the share is fully paid, by or on behalf of the transferee. A share held in uncertificated form may be transferred by means of a relevant system. The transferor shall be deemed to remain the holder of the share until the transferee is entered on the register as its holder. Pursuant to the Management Incentive Agreement entered into between the shareholders of the Company at the time that the current Articles were adopted, the holder of any B1 Ordinary Shares or B2 Ordinary Shares may not transfer, assign, mortgage or charge any such B1 Ordinary Shares or B2 Ordinary Shares (or any interest in the B1 Ordinary Shares or B2 Ordinary Shares that such person holds), or otherwise create or permit to subsist any encumbrance over or in respect of the B1 Ordinary Shares or B2 Ordinary Shares. Calls Subject to the terms of allotment, the directors may make calls upon the members in respect of any moneys unpaid on their shares including any premium and each member shall (subject to being given at least 14 clear days’ notice specifying where and when payment is to be made) pay to the Company the specified amount called on his shares. If any sum called in respect of a share is not paid before or on the day appointed for payment thereof, the person from whom it is due and payable shall pay interest on the amount unpaid from the day it became due and payable until it is paid. Interest shall be paid at a rate fixed by the terms of allotment of the share or in the notice of the call; or if no rate is fixed, at the appropriate rate per annum from the day appointed for the payment thereof to the time of the actual payment. Directors may at their discretion waive payment of any such interest in whole or in part. Forfeiture If a member fails to pay any call or instalment of a call on the day appointed for payment of such call or instalment, the directors may serve a notice on him requiring payment of so much of the amount unpaid together with any interest which may have accrued and any expenses which have been incurred by the Company due to the default. The notice shall name the place where payment is to be made and shall state that if the notice is not complied with the shares in respect of which the call was made will be liable to be forfeited. A forfeited share may be sold, re-allotted or otherwise disposed of on such terms and in such manner as the Board determine and at any time before a sale or disposition the forfeiture may be cancelled on such terms as the directors think fit. A person whose shares have been forfeited shall cease to be a member in respect of the forfeited shares, but shall, notwithstanding such forfeiture, remain liable to pay to the Company all moneys which at the date of forfeiture were payable by him to the Company in respect of the shares, together with all expenses and interest from the date of forfeiture or surrender until payment, but his liability shall cease if and when the Company receives payment in full of the unpaid amount. 328
Directors Unless otherwise determined by the Board, the number of directors of the Company shall not be subject to any maximum but shall not be less than one. The general rule about-decision-making by directors is that any decision must be either a majority decision at a meeting or a unanimous decision. The directors may be paid all reasonable expenses as they may incur in connection with their attendance at meetings of the Board or of committees of the Board or general meetings or separate meetings of the holders of any class of shares or debentures of the Company or otherwise in connection with the discharge of their duties. Any director may be removed from office by ordinary resolution of the Company. The directors are not subject to a mandatory retirement age. Directors’ interests A director who to his knowledge is in any way directly or indirectly interested in a contract or arrangement or proposed contract or arrangement with the Company shall disclose the nature of his interest by a general notice to the directors. A director may vote in respect of any resolution of the directors or committee of the directors concerning a matter in which he has, directly or indirectly, an interest or duty. The director shall be counted in the quorum present at a meeting when any such resolution is under consideration and if he votes his vote shall be counted. Disclosure of interests Subject to the provisions of the 2006 Act, and provided that he has disclosed to the Board the nature and extent of any interest of his in accordance with the Articles, a director notwithstanding his office: • may be a party to or otherwise interested in any transaction or arrangement with the Company or in which the Company is otherwise interested; • may be a director or other officer of, or employed by or party to any transaction or arrangement with, or otherwise interested in any body corporate promoted by the Company or in which the Company is otherwise interested; and • shall not be, by reason of his office, accountable to the Company for any benefits derived from any such office or employment or from any transaction or arrangement or from any interest in any such body corporate and no such transaction or arrangement shall be liable to be avoided on the grounds of any such interest or benefit. Authorisation of interests The directors may authorise, to the fullest extent permitted by law, any matter proposed to them which would otherwise result in a director infringing his duty under the 2006 Act to avoid a situation in which he has, or can have, a direct or indirect interest that conflicts, or possibly may conflict, with the interests of the Company and which may reasonably be regarded as likely to give rise to a conflict of interest. Authorisation of a matter is effective only if: (i) the matter has been proposed to the directors at a meeting of the directors or for the authorisation of the directors by resolution in writing and in accordance with the Board’s normal procedures or in such other manner as the Board may approve; (ii) any requirement as to quorum at the meeting of the directors at which the matter is considered is met without counting the director in question and any other interested director; and (iii) the matter has been agreed to without the director in question and any other interested Director voting or would have been agreed to if their votes had not been counted. General Meetings A person is able to exercise the right to vote at a general meeting when that person is able to vote, during the meeting, on resolutions put to the vote at the meeting, and that person’s vote can be taken into account in determining whether or not such resolutions are passed at the 329
same time as the votes of all the other persons attending the meeting. The directors may make whatever arrangements they consider appropriate to enable those attending a general meeting to exercise their rights to speak or vote at it. Directors may attend and speak at general meetings, whether or not they are shareholders. No business other than the appointment of the chairman of the meeting is to be transacted at a general meeting if the persons attending it do not constitute a quorum. A resolution put to the vote of a general meeting must be decided on a show of hands unless a poll is duly demanded in accordance with the Articles Every member entitled to attend and vote is entitled to appoint one or more proxies to attend, vote and speak instead of him and that proxy need not be a member. 5.2 The summary in this paragraph 5.2 relates to the PLC Articles. The PLC Articles of the Company shall include provisions to the following effect: Objects The PLC Articles contain no restriction on the objects of the Company. Accordingly, pursuant to section 31 of the 2006 Act, the Company’s objects are unrestricted. Capital structure The share capital of the Company is represented by an unlimited number of Ordinary Shares having the rights described in the PLC Articles. Voting rights Subject to any rights or restrictions attached to any shares, on a show of hands every member who (being an individual) is present in person or by proxy or (being a corporation) is present by a duly authorised representative, not being himself a member entitled to vote, shall have one vote, and on a poll every member shall have one vote for every share of which he is the holder. Votes may be given personally or by proxy. Dividends Subject to the 2006 Act and as set out in the PLC Articles, the Company may by ordinary resolution declare dividends but no dividend shall exceed the amount recommended by the Board. No dividend may be paid otherwise than in accordance with the 2006 Act. The Board may at any time declare and pay such interim dividends as appears to be justified by the position of the Company. Except as otherwise provided by the rights attached to the shares, all dividends shall be declared and paid according to the amounts paid up on the nominal amount of the shares on which the dividend is paid but no amount paid on a share in advance of calls shall be treated as paid on the share. All dividends shall be apportioned and paid proportionately to the amounts paid up on the nominal amount of the shares during any portion or portions of the period in respect of which the dividend is paid; but, if any share is issued on terms providing that it shall rank for dividend as from a particular date, that share shall rank for dividend accordingly. Any dividend or other moneys payable in respect of a share may be paid: • in cash; • by cheque or warrant sent by post to the address in the register of members of the Company of the person entitled to the moneys or, if two or more persons are the holders of the share or are jointly entitled to it by reason of the death or bankruptcy of the holder or otherwise by operation of law, to the address in the register of that one of those persons who is first named in the register in respect of the joint holding or to such person and to such address as the person or persons entitled to the moneys may in writing direct. Every such cheque or warrant shall be made payable to the person or persons entitled to the moneys or to such other person as the person or persons so entitled may in writing direct 330
and shall be sent at the risk of the person or persons so entitled. Any such cheque or warrant may be crossed ‘account payee’ although the Company shall not be obliged to do so; • by bank transfer to such account (of a type approved by the Board) as the person or persons entitled to the moneys may in writing direct; or • by such other method of payment approved by the Board as the person or persons entitled to the moneys may in writing agree. Redemption Subject to the provisions of the 2006 Act and the PLC Articles, the Company can issue shares which are required to be redeemed and shares which may be redeemed at the option of the Company or the relevant member. Variation of class rights Whenever the capital of the Company is divided into different classes of shares, the rights attached to any class of the shares in issue may from time to time be varied or abrogated, whether or not the Company is being wound up, with the sanction of a special resolution passed at a separate meeting of holders of the issued shares of the class held in accordance with the PLC Articles (but not otherwise). The special rights conferred on the holders of any shares or class of shares shall, unless otherwise provided by the PLC Articles or the terms of issue of the shares concerned, be deemed to be varied by a reduction of capital paid up on those shares but shall be deemed not to be varied by the creation or issue of further shares ranking pari passu with them or subsequent to them. The rights conferred on the holders of shares shall be deemed not to be varied by the creation or issue of any further shares ranking in priority to them nor shall any consent or sanction of the holders of shares be required to any variation or abrogation effected by a resolution on which only the holders of shares are entitled to vote. Issue of shares Subject to the provisions of the 2006 Act and without prejudice to any rights attaching to any existing shares, shares may be issued with such rights or restrictions as the Company may, by ordinary resolution, determine or in the absence of such determination, or as far as any such resolution does not make specific provision, as the Board may determine. Form and transfer of shares The Board may issue shares as certificated or uncertificated shares, subject to any restrictions on transfers described below. A share held in certificated form may be transferred by an instrument of transfer in any usual form or in any other form which the Board may approve, which shall be executed by or on behalf of the transferor and, unless the share is fully paid, by or on behalf of the transferee. A share held in uncertificated form may be transferred by means of a relevant system. The transferor shall be deemed to remain the holder of the share until the transferee is entered on the register as its holder. Every member (other than a person who is not entitled to a certificate under the 2006 Act) is entitled, on becoming a holder of any shares in certificated form and without payment, to a certificate for all shares of each class held by him in certificated form. If a share certificate is worn out, defaced, lost, destroyed or stolen it may be renewed without fee but on such terms as to evidence and indemnity as the Board requires. In the case of loss, theft, or destruction, the person to whom the new certificate is issued may be required to pay any exceptional out of pocket expenses incidental to the investigation of evidence of loss, theft or destruction and the preparation of an appropriate form of indemnity. Every share certificate is sent at the risk of the person entitled thereto. The Board may, in the case of shares held in certificated form, in its absolute discretion refuse to register the transfer of a share which is not fully paid provided that such discretion may not 331
be exercised in such a way as to prevent dealings in the shares of that class from taking place on an open and proper basis. The Board may also refuse to register a transfer of any shares held in certificated form unless the instrument of transfer is: • duly stamped or duly certified or otherwise shown to the satisfaction of the Board to be exempt from stamp duty, lodged at the transfer office or at such other place as the Board may appoint and (save in the case of a transfer by a person to whom no certificate was issued in respect of the shares in question) accompanied by the certificate for the shares to which it relates, and such other evidence as the Board may reasonably require to show the right of the transferor to make the transfer and, if the instrument of transfer is executed by some other person on his behalf, the authority of that person so to do; • in respect of only one class of shares; and • in favour of not more than four transferees. If the Board refuses to register a transfer of shares held in certificated form, it shall (except in the case of suspected fraud) as soon as practicable and in any event within two months after the date on which the transfer was lodged with the Company send to the transferee notice of the refusal together with its reasons for the refusal. No fee shall be charged for the registration of any instrument of transfer or other document relating to or affecting the title to any share or for making any entry in the register affecting the title to any share. The Company shall be entitled to retain any instrument of transfer which is registered, but (except in the case of suspected fraud) any instrument of transfer which the Board refuses to register shall be returned to the person lodging it when notice of the refusal is given. For all purposes of the PLC Articles relating to the registration of transfers of shares, the renunciation of the allotment of any shares by the allottee in favour of some other person shall be deemed to be a transfer and the Board shall have the same powers of refusing to give effect to such a renunciation as if it were a transfer. If a member dies the survivor or survivors where he was a joint holder, and his personal representatives where he was a sole holder or the only survivor of joint holders, shall be the only persons recognised by the Company as having any title to his interest; but nothing contained in the PLC Articles shall release the estate of a deceased member from any liability in respect of any share which had been held (whether solely or jointly) by him. Calls Subject to the terms of allotment, the directors may from time to time make calls upon the members in respect of any moneys unpaid on their shares including any premium and each member shall (subject to being given at least 14 clear days’ notice specifying where and when payment is to be made) pay to the Company the specified amount called on his shares. If any sum called in respect of a share is not paid before or on the day appointed for payment thereof, the person from whom it is due and payable shall pay interest on the amount unpaid from the day it became due and payable until it is paid. Interest shall be paid at a rate fixed by the terms of allotment of the share or in the notice of the call; or if no rate is fixed, at the appropriate rate per annum from the day appointed for the payment thereof to the time of the actual payment. Directors may at their discretion waive payment of any such interest in whole or in part. Forfeiture If a member fails to pay any call or instalment of a call on the day appointed for payment of such call or instalment, the directors may serve a notice on him requiring payment of so much of the amount unpaid together with any interest which may have accrued and any expenses which have been incurred by the Company due to the default. The notice shall name the place where payment is to be made and shall state that if the notice is not complied with the shares in respect of which the call was made will be liable to be forfeited. 332
A forfeited share may be sold, re-allotted or otherwise disposed of on such terms and in such manner as the Board determine and at any time before a sale or disposition the forfeiture may be cancelled on such terms as the directors think fit. A person whose shares have been forfeited shall cease to be a member in respect of the forfeited shares, but shall, notwithstanding such forfeiture, remain liable to pay to the Company all moneys which at the date of forfeiture were payable by him to the Company in respect of the shares, together with all expenses and interest from the date of forfeiture or surrender until payment, but his liability shall cease if and when the Company receives payment in full of the unpaid amount. A statutory declaration in writing that the declarant is a director or the secretary of the Company, and that the particular share of the Company has been duly forfeited on a date stated in the declaration, shall be conclusive evidence of the facts therein stated as against all persons claiming to be entitled to the forfeited share. Disclosure of interests The Company may give notice to any member or any person whom the Company knows or has reasonable cause to believe (a) to be interested in the Company’s shares or (b) to have been so interested at any time in the three years immediately preceding the date on which the notice is issued. The notice may require the person (a) to confirm that fact or (as the case may be) to state whether or not it is the case and (b) if he holds, or has during that time held, any such interest, to give such further information as may be required in accordance with section 793 of the 2006 Act (including particulars of the interest (present or past) and the identity of the persons interested in the shares in question). If the Company has served a disclosure notice on a member or any other person appearing to be interested in shares referred to in the disclosure notice, and the Company has not received the information required in the disclosure notice within 14 days after service of the disclosure notice, the directors may determine that the member holding the specified shares shall be subject to restrictions in respect of those shares (including restrictions as to voting, right to transfer the shares and right to receive dividends). Directors Unless otherwise determined by the Board, the number of directors of the Company shall be not less than two. The directors may be paid all travelling, hotel and other expenses as they may incur in connection with their attendance at meetings of the Board or of committees of the Board or general meetings or separate meetings of the holders of any class of shares or debentures of the Company or otherwise in connection with the discharge of their duties. The Board may provide benefits, whether by the payment of gratuities or pensions or by insurance or otherwise, for any director, employee or former employee who has held but no longer holds any office or employment with the Company or with any body corporate which is or has been a subsidiary undertaking or a predecessor in business of the Company or of any subsidiary undertaking, and for any member of his family (including a spouse and a former spouse) or any person who is or was dependent on him and may (as well before as after he ceases to hold such office or employment) contribute to any fund and pay premiums for the purchase or provision of any such benefit. The power conferred by the 2006 Act to make provision for the benefit of persons employed or formerly employed by the Company or any of its subsidiaries (other than a director or former director or shadow director), in connection with the cessation or the transfer to any person of the whole or party of the undertaking of the Company or any subsidiary, shall be exercised by the Board. At each annual general meeting all of the directors shall stand for re-election. Any director may be removed from office by ordinary resolution of the Company. The directors are not subject to a mandatory retirement age. 333
Directors’ interests A director who to his knowledge is in any way directly or indirectly interested in a contract or arrangement or proposed contract or arrangement with the Company shall disclose the nature of his interest at a meeting of the Board. A director may not vote (or be counted in the quorum) in respect of any resolution of the directors or committee of the directors concerning a contract, arrangement, transaction or proposal to which the Company is or is to be a party and in which he has an interest which (together with any interest of any person connected with him) is, to his knowledge, a material interest (otherwise than by his interest in shares or debentures or other securities of or otherwise in or through the Company). This is subject to certain exceptions including (i) where the contract, arrangements, transaction or proposal concerns general employee privileges or insurance policies for the benefit of directors or (ii) in circumstances where a director acts in a personal capacity in the giving of a guarantee, security or indemnity for the benefit of the Company or any of its subsidiary undertakings. Any director may act by himself or his firm in a professional capacity for the Company, other than as auditor, and he or his firm shall be entitled to remuneration for professional services as if he were not a director. Disclosure of interests Subject to the provisions of the 2006 Act, and provided that he has disclosed to the Board the nature and extent of any interest of his in accordance with the PLC Articles, a director notwithstanding his office: • may be a party to or otherwise interested in any transaction or arrangement with the Company or in which the Company is otherwise interested; • may be a director or other officer of, or employed by or party to any transaction or arrangement with, or otherwise interested in any body corporate promoted by the Company or in which the Company is otherwise interested; and • shall not be, by reason of his office, accountable to the Company for any benefits derived from any such office or employment or from any transaction or arrangement or from any interest in any such body corporate and no such transaction or arrangement shall be liable to be avoided on the grounds of any such interest or benefit. Authorisation of interests The directors may authorise, to the fullest extent permitted by law, any matter proposed to them which would otherwise result in a director infringing his duty under the 2006 Act to avoid a situation in which he has, or can have, a direct or indirect interest that conflicts, or possibly may conflict, with the interests of the Company and which may reasonably be regarded as likely to give rise to a conflict of interest. Authorisation of a matter is effective only if: (i) the matter has been proposed to the directors at a meeting of the directors or for the authorisation of the directors by resolution in writing and in accordance with the Board’s normal procedures or in such other manner as the Board may approve; (ii) any requirement as to quorum at the meeting of the directors at which the matter is considered is met without counting the director in question and any other interested director; and (iii) the matter has been agreed to without the director in question and any other interested Director voting or would have been agreed to if their votes had not been counted. An interest of a person connected with a director shall be treated as an interest of the director. Section 252 of the 2006 Act shall determine whether a person is connected with a director. Borrowing powers The directors may exercise all the powers of the Company to borrow money and to give guarantees, hypothecate, mortgage, charge or pledge the assets, property and undertaking of the Company or any part thereof and to issue debentures and other securities whether outright or as collateral security for any debt, liability or obligation of the Company or of any third party. 334
Annual General Meetings and General Meetings An annual general meeting shall be held at such time and place as the Board may determine. The Board may call general meetings and, on the requisition of members pursuant to the provisions of the 2006 Act, shall forthwith convene a general meeting. If there are not sufficient directors capable of acting to call a general meeting, any director may call a general meeting. If there is no director able to act, any two members may call a general meeting for the purpose of appointing directors. No business shall be transacted at any general meeting unless a quorum is present when the meeting proceeds to business. A quorum is two members present in person or by proxy and entitled to vote upon the business to be transacted at the meeting. An annual general meeting shall be called by at least 21 days’ clear notice in writing. A meeting of the Company other than an annual general meeting shall be called by not less than 14 days’ clear notice. The notice shall specify the place, the day and the time of the meeting and the general nature of that business. A notice calling an annual general meeting shall specify the meeting as such and a notice for the passing of a special resolution shall specify the intention to propose the resolution as a special resolution and the terms of the resolution. Every member entitled to attend and vote is entitled to appoint one or more proxies to attend, vote and speak instead of him and that proxy need not be a member. The accidental omission to give notice of a meeting, or to send an instrument of proxy or invitation to appoint a proxy as provided by the PLC Articles, to any person entitled to receive notice, or the non-receipt of notice of a meeting or instrument of proxy or invitation to appoint a proxy by such a person, shall not invalidate the proceedings at that meeting. Every notice of meeting shall state with reasonable prominence that a member entitled to attend and vote is entitled to appoint one or more proxies to attend, vote and speak instead of him and that a proxy need not be a member. Annual Accounts and Financial Statements Save as provided in the PLC Articles, a copy of the annual accounts of the Company together with a copy of the auditors’ report and the directors’ report thereon and any other documents required to accompany or to be annexed to them shall, not less than 21 clear days before the date of the general meeting at which copies of those documents are to be laid, be sent to every member and to every debenture holder of the Company and to every other person who is entitled to receive notices from the Company of general meetings. Copies of the documents referred to in the PLC Articles need not be sent to: (a) a person who is not entitled to receive notices of general meetings or of whose address the Company is unaware; or (b) more than one of the joint holders of shares or debentures in respect of those shares or debentures, provided that any member or debenture holder to whom a copy of such documents has not been sent shall be entitled to receive a copy free of charge on application at the registered office. The Company may send a summary financial statement to any of the persons otherwise entitled to be sent copies of the documents referred to in the PLC Articles instead of or in addition to those documents and, where it does so, the statement shall be delivered or sent to such person not less than 21 clear days before the general meeting at which copies of those documents are to be laid. Winding up If the Company is wound up, the liquidator may, with the sanction of a special resolution of the Company and any other sanction required by the 2006 Act, divide among the members in specie the whole or any part of the assets of the Company and may, for that purpose, value any assets and determine how the division shall be carried out as between the members or different classes of members. The liquidator may, with the applicable sanction, vest the whole or any part of the assets in trustees upon such trusts for the benefit of the members as he with the applicable sanction determines, but no member shall be compelled to accept any assets upon which there is a liability. 335
Untraceable shareholders The Company shall be entitled to sell at the best price reasonably obtainable any member’s shares or the shares to which a person is entitled by virtue of transmission on death or bankruptcy or otherwise by operation of law if: • for a period of twelve years, no cash dividend payable in respect of the shares has been claimed, no cheque or warrant sent by the Company through the post in a pre-paid envelope addressed to the member or to the person entitled to the shares at his address on the register or (if different) the last known address given by the member or the person so entitled to which cheques and warrants are to be sent has been paid, each attempt to make a payment in respect of the shares by means of bank transfer or other method for the payment of dividends or other moneys in respect of shares has failed and no communication has been received by the Company from the member or the person so entitled (in his capacity as member or person entitled); • in such period of twelve years at least three dividends (whether interim or final) have become payable on the shares; • the Company has at the expiration of the said period of twelve years by advertisement in both a national newspaper and in a newspaper circulating in the area in which the address referred to in the PLC Articles is located given notice of its intention to sell such shares; and • during the period of three months following the publication of the said advertisements the Company has received no communication in respect of such share from such member or person entitled. If at any time during or after the said period of twelve years further shares have been issued in right of those held at the commencement of that period or of any issued in right during that period and, since the date of issue, the requirements of the PLC Articles have been satisfied in respect of such further shares, the Company may also sell the further shares. To give effect to such a sale the Board may authorise any person to execute an instrument of transfer or otherwise effect the transfer of the shares to be sold. If the shares concerned are in uncertificated form, in accordance with the CREST Regulations, the Company may issue a written notification to the operator requiring conversion of the shares into certificated form. The purchaser shall not be bound to see to the application of the purchase moneys and the title of the transferee to the shares shall not be affected by any irregularity in or invalidity of the proceedings relating to the sale. The net proceeds of sale shall belong to the Company which shall be obliged to account to the former member or other person previously entitled to the shares for an amount equal to the net proceeds, which shall be a debt of the Company, and shall enter the name of such former member or other person in the books of the Company as a creditor for such amount. No trust shall be created and no interest shall be payable in respect of the debt, and the Company shall not be required to account for any money earned on the net proceeds, which may be employed in the business of the Company or invested in such investments for the benefit of the Company as the Board may from time to time determine. 6. DIRECTORS’ AND SENIOR MANAGERS’ INTERESTS 6.1 Directorships and partnerships outside the Group The details of those companies and partnerships outside the Group of which the Directors and Senior Managers are currently directors, partners or members of any administrative, management or supervisory body, or have been directors, partners or members of any administrative, management or supervisory body at any time in the five years immediately preceding the date of this Registration Document are as follows: Name Current directorships and partnerships Previous directorships and partnerships Directors Gilad Myerson . . . . . . DKL Investments Limited (1) DKL Energy Limited (1) Alan Bruce . . . . . . . . . N/A N/A 336
Name Current directorships and partnerships Previous directorships and partnerships Iain Lewis . . . . . . . . . N/A N/A Idan Wallace . . . . . . . Delek Group Ltd. NewMed Energy Management Ltd Delek Energy Systems Ltd Wallace Consulting Ltd Wallace Investments (2018) Ltd Keshet Broadcasting Ltd Israeli Television News Company Tashluz Investments & Holdings Ltd Proposed Directors John Mogford . . . . . . . BHP Group (Aus) Limited Sutton Energy Consultants Limited Mogford Albion Limited BHP Group (UK) Ltd ERM Worldwide Group Limited Weir Group Plc (The) DOF Subsea AS Deborah Gudgeon . . . . 5 Wolseley Road Limited Petra Diamonds Limited Conan Limited Evraz Plc Barrick TZ Limited Highland Gold Mining Limited Lynne Clow . . . . . . . . Highlands and Islands Airports Limited Dundee Airports Limited Scottish Prison Scheme N/A Assaf Ginzburg . . . . . . Alon USA Energy Inc Ormat Technologies Inc Delek Logistics Partners LP Delek Logistics GP LLC 1 Senior Managers John Horsburgh . . . . . N/A N/A Julie McAteer . . . . . . . N/A Premier Oil UK Limited Premier Oil E&P UK Limited Premier Oil E&P UK EU Limited Premier Oil Aberdeen Services Limited Premier Oil E&P UK Energy Trading Limited Rachel Stanley . . . . . . N/A N/A Brian Winton . . . . . . . . BJK Winton Properties Limited B J Winton Consultants Limited N/A Craig Matthew . . . . . . N/A N/A (1) Mr Myerson will resign from his position as a director of these entities immediately prior to any admission. 6.2 Interests in the ordinary share capital of the Company As at the Latest Practicable Date, no Director or Senior Manager holds, directly or indirectly, any voting rights in respect of the Company or any of its Subsidiaries. On 29 September 2022, Gilad Myerson waived his voting rights on the 100 B1 Ordinary Shares and the 100 B2 Ordinary Shares held by him. 6.3 Conflicts of Interest There are the following potential conflicts of interest between the duties of a Director of the Company and his private interests and/or other duties. These conflicts have been authorised by the Board. 1 Delek Group sold its substantial shareholding (7.5%) in Delek Logistics Partners LP and Delek US Holdings, Inc in 2014 and all remaining shares were sold by the Delek Group in 2017. Delek Logistics Partners LP and Delek US Holdings, Inc. are no longer affiliates of the Delek Group. 337
Idan Wallace . . . . . . . Mr Wallace was appointed by and represents Delek on the Board of the Company. Gilad Myerson . . . . . . Mr Myerson is a director of both DKL Investments and DKL Energy. Each of the Directors has a duty under the Articles to avoid conflicts of interest with the Company and to disclose the nature and extent of any such interest to the Board. Under the Articles, and as permitted by the 2006 Act, the Board may authorise any matter which would otherwise involve a Director breaching this duty to avoid conflicts of interest and may attach to any such authorisation such conditions and/or restrictions as the Board deem appropriate (including in respect of the receipt of information or restrictions on participation at certain Board meetings), in accordance with the Articles. Save as set out above there are no actual or potential conflicts of interest between the duties owed by the Directors, the Senior Managers, or members of any administrative, management or supervisory body of the Company to the Group, and the private interests and/or other duties that they may also have. 6.4 Directors and Senior Managers’ confirmations Save as disclosed below in relation to the class action law suits against Idan Wallace, as at the date of this Registration Document, no Director or Senior Manager has during the last five years: 6.4.1 any convictions in relation to fraudulent offences; 6.4.2 been associated with any bankruptcy, receivership or liquidation, or any company being put into administration, while acting in the capacity of a member of the administrative, management or supervisory body or as senior manager of any company; 6.4.3 been subject to any official public incrimination and/or sanctions by any statutory or regulatory authority (including any designated professional bodies); or 6.4.4 been disqualified by a court from acting as a member of the administrative, management or supervisory bodies of a company or from acting in the management or conduct of the affairs of any company. There are no family relationships between any of the Directors and/or Senior Managers. There are no outstanding loans or guarantees granted or provided by any member of the Group for the benefit of any of the Directors, Senior Managers or members of any administrative, management or supervisory body of the Company. Idan Wallace, a non-executive director of the Company and chief executive officer of the Delek Group, is party to a number of class action lawsuits filed with the Tel Aviv District Court. On 16 April 2020, a motion for a certification of a class action was filed against Delek, its board of directors and its present and former chief executive officer, alleging a failure to disclose to investors material information about certain terms under a loan agreement. On 16 April 2020, a separate motion for a certification of a class action was filed against Delek, its board of directors and its present and former chief executive officer, alleging a failure to disclose to investors material information about changes to the scope and terms of certain price hedging transactions made by IEEPL. On 23 April 2020, a claim and motion for its certification as a class action was filed against NewMed Energy, its general partner, the board of directors of such general partner, Delek and the controlling shareholder of Delek. On 18 May 2020, a motion was filed against Delek, its board of directors, its chief executive officer and its chief financial officer, alleging misleading information and non-disclosure of material details about Delek’s affairs and finances. The claims remain ongoing. Given the uncertainty of litigation, the preliminary stage of the cases, and the legal standards that must be met for, among other things, class certification and success on the merits, the reasonably possible loss or range of loss that may result from these actions cannot be estimated. 338
7. DIRECTORS AND SENIOR MANAGERS’ SERVICE AGREEMENTS / LETTERS OF APPOINTMENT AND REMUNERATION 7.1 Existing Service Agreements—Executive Directors and Senior Managers The Executive Directors and Senior Managers are currently employed on the following terms: Executive Directors Gilad Myerson On 19 April 2021, Gilad Myerson entered into a service agreement with IEUK for the position of Executive Chairman. At that stage he was, and still remains, also employed by DKL Investments as Chief Executive Officer, with his employment with DKL Investments Limited having commenced on 11 November 2019. In the event of expected admission to the London Stock Exchange, Mr. Myerson’s employment with DKL Investments will terminate prior to such admission. Accordingly, only his terms with IEUK are reported on here. Mr. Myerson is entitled to combined annual leave entitlement of 30 days (inclusive of 5 public holidays) and 6 other fixed days’ paid holiday per annum. Mr. Myerson is entitled to a number of benefits including 26 weeks of sick pay in aggregate in any rolling 12-month period, lunch expenses and a car allowance of £9,300 per annum and, in certain circumstances, severance pay of up to 52 weeks' pay depending on age and service. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable pay from both of his employments (IEUK and DKL Investments Limited) and he is eligible to participate in the company’s discretionary annual bonus based on company and employee performance up to £250,000 based on company and employee performance. The agreement also entitles Mr. Myerson to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Mr. Myerson is entitled to receive an annual salary of £450,000 per annum. Pursuant to the terms of the agreement with IEUK, the agreement is terminable by either him or the company on not less than six-month prior written notice. Alan Bruce On 16 August 2021, Alan Bruce entered into a service agreement with IEUK for the position of Chief Executive Officer (one of the terms of which included him acting as a Director of Ithaca Energy Limited). Mr. Bruce is entitled to 30 days (inclusive of 5 public holidays) and 6 additional fixed days’ paid holiday per annum. The agreement entitles Mr. Bruce to a number of benefits including full and half sick pay for a certain period depending on years of service, an annual lunch allowance, and a car allowance of £9,300 per annum. In event of listing, change of control, disposal, re-organisation or sale. within 3 years of the start of his employment and where as a result, employment is terminated within a period of 9 months from the date of such event, he is entitled to payment equal to 3 times base annual salary for loss of employment subject to signing a settlement agreement. Where the foregoing does not apply, in certain circumstances, he is entitled to severance pay of up to 52 weeks’ pay depending on age and service. Pursuant to the agreement, IEUK will pay pension contributions equal to an amount of 15% of pensionable salary and he is eligible to participate in the company’s discretionary bonus scheme up to 50% of annual base salary based on company and employee performance. In addition, Mr. Bruce has the ability to earn a further extraordinary bonus which is in lieu of shares offered under a LTIP following the listing of relevant shares on a public market and/or recognised investment exchange. The agreement also entitles Mr. Bruce to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Mr Bruce is entitled to receive an annual salary of £400,000 per annum. The agreement is terminable by either him or the company on not less than three months’ prior written notice. Iain Lewis On 25 July 2022, (and amended on 11 October 2022) Iain Lewis entered into a service agreement with IEUK for the position of Chief Financial Officer. Mr. Lewis is entitled to 339
216 hours (inclusive of public holidays) pro-rated to reflect 4 days per week. Mr. Lewis is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £7,440 per annum. Pursuant to this agreement, IEUK will pay pension contributions equal to an amount of 15% of pensionable salary (and either into a pension scheme or by way of a cash alternative) and he is eligible to participate in the company’s discretionary annual bonus scheme based on company and employee performance payable in March each year. The agreement entitles Mr. Lewis to a payment equivalent of 12 months basic pay if the company terminates the employment within 2 years of commencement (subject to the reason relating to poor performance/conduct or signing a settlement agreement). Where the foregoing does not apply, in certain circumstances, he is entitled to severance pay of up to 52 weeks’ pay depending on age and service. The agreement also entitles Mr. Lewis to participate in Life Assurance, Group Income Protection, private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Mr. Lewis is entitled to receive an annual salary of £300,000 per annum. The agreement is terminable by either him or the company not less than three months’ prior written notice. Senior Managers Rachel Stanley On 8 November 2019, Rachel Stanley TUPE transferred from Chevron to IEUK employed for the position of General Manager NOVJ, Energy Transition. Ms. Stanley is entitled to 33 days (inclusive of public holidays) and 6 other fixed days’ paid holiday per annum. Ms. Stanley is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £9,300 per annum, an Offshore allowance and an Erskine allowance. Ms. Stanley is in certain circumstances entitled to a severance pay benefit and a savings allowance which is payable to transferring employees who were enrolled in Chevron Share Incentive Plan and which is payable up until the IPO is complete in which case the interim payment scheme will cease. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable salary and she is eligible for a discretionary annual bonus. The agreement also entitles Ms. Stanley to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Ms. Stanley is entitled to receive an annual salary of £197,884 per annum. The agreement is terminable by either her or the company not less than 12 weeks prior written notice depending on year of service. Julie McAteer On 24 February 2020, Julie McAteer entered into a service agreement with IEUK for the position of General Manager, Legal & Business Affairs. Mrs. McAteer is entitled to 30 days (inclusive of 5 public holidays) and 6 other fixed days’ paid holiday per annum. Mrs. McAteer is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £9,300 per annum, and in certain circumstances, severance pay of up to 52 weeks’ pay depending on age and service. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable salary. In addition, Mrs. McAteer is entitled to an IPO bonus, an annual bonus and a discretionary bonus. The agreement also entitles Mrs. McAteer to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Mrs. McAteer is entitled to receive an annual salary of £225,000 per annum. The agreement is terminable by her or the company not less than three months’ prior written notice. 340
John Horsburgh On 12 May 2008, John Horsburgh entered into a service agreement with IEUK for the position of Development Geophysicists, before being promoted to a Reserves Co-ordinator and Stella Subsurface Manager and then General Manager, Subsurface and Wells. Mr. Horsburgh is entitled to 30 days (inclusive of 5 public holidays) and 6 other fixed days’ paid holiday per annum. Mr. Horsburgh is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £9,300 per annum, and, in certain circumstances, severance pay of up to 52 weeks’ pay depending on age and service. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable salary. In addition, he is eligible to a discretionary annual bonus and an IPO bonus. The agreement also entitles Mr. Horsburgh to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan and a Healthcare cash plan. Mr. Horsburgh is entitled to receive an annual salary of £250,000 per annum. The agreement is terminable by him or the company not less than three months’ prior written notice. Brian Winton On 1 January 2021, Brian Winton entered into a service agreement with IEUK for the position of General Manager, Operations, Projects & Decommissioning. Mr. Winton is entitled to 30 days (inclusive of 5 public holidays) and 6 other fixed days’ paid holiday per annum. Mr. Winton is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £9,300 per annum, and in certain circumstances, severance pay of up to 52 weeks’ pay depending on age and service. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable salary and he is eligible for an annual bonus of up to 50% of annual base salary, as well as a discretionary annual bonus based on company and employee performance payable in March each year. The agreement also entitles Mr. Winton to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan, and a Healthcare cash plan. Mr. Winton is entitled to receive an annual salary of £250,000 per annum. The agreement is terminable by him or the company not less than three months’ prior written notice, save for during his probationary period when it is two weeks. Craig Matthew On 16 August 2021, Craig Matthew entered into a service agreement with IEUK and on 1 August 2022, he was promoted to the position of General Manager, Greenfield Projects. Mr. Matthew is entitled to 30 days (inclusive of 5 public holidays) and 6 other fixed days’ paid holiday per annum. Mr. Matthew is entitled to a number of benefits including full and half sick pay for a certain period of time depending on years of service, an annual lunch allowance, a car allowance of £9,300 per annum, and, in certain circumstances, severance pay of up to 52 weeks’ pay depending on age and service. Pursuant to this agreement, IEUK will pay contributions equal to an amount of 15% of pensionable salary and he is eligible for an annual bonus of up to 50% of annual base salary, as well as a discretionary annual bonus based on company and employee performance payable in March each year. In addition, Mr. Matthew has the ability to earn an additional extraordinary bonus if he delivers transformative performance. The agreement also entitles Mr. Matthew to participate in Life Assurance, Group Income Protection, Private medical insurance, Accident Insurance, a Dental plan, and a Healthcare cash plan. Mr. Matthew is entitled to receive an annual salary of £235,000 per annum. The agreement is terminable by him or the company not less than three months’ prior written notice. 7.2 Executive Directors In connection with the expected admission to the London Stock Exchange, the Executive Directors will enter into new service agreements with the Group, which will come into effect on admission, with the following terms: 341
7.2.1 Gilad Myerson will receive a base salary of £500,000 per annum, Alan Bruce will receive a base salary of £400,000 per annum and Iain Lewis will receive a base salary of £300,000 per annum. The base salaries are reviewed annually. There is no obligation to increase the relevant Executive Director’s salary following a salary review. 7.2.2 Each Executive Director will be eligible for a discretionary annual bonus payment of up to 150% of his base salary. Further information regarding Executive Director remuneration is set out at paragraph 7.5 (Directors’ and Senior Managers’ remuneration) of this Part 15 (Additional Information). 7.2.3 The Executive Directors will be eligible to participate in the Company’s employee incentive schemes, further details of which are set out in paragraph 8 of this Part 15 (Additional Information). Gilad Myerson is also entitled to participate in the Management Equity Plan as further set out in paragraph 8.4 (Management Equity Plan) of this Part 15 (Additional Information). 7.2.4 Each Executive Director will be entitled to receive an amount of up to 15% of his base salary as a contribution to a pension scheme. The Executive Directors may also receive other benefits (for example, the provision of life insurance and private medical insurance) and other market standard benefits. 7.2.5 Each Executive Director will also be entitled to reimbursement of reasonable expenses authorised by the Board. 7.2.6 Each Executive Director’s service agreement will be terminable by the Company or the respective Executive Director on 6 months’ written notice, or by the Company without notice where (i) they become disqualified from holding or cease to hold office as a director by virtue of any court order, under any provision of general law or under any provision of the Articles or (ii) they lose any approval given to them by any statutory or regulatory authority as a result of which they are no longer able to perform their duties. 7.2.7 The Executive Directors are subject to certain restrictive covenants for a period after termination of their executive service contract. This includes a non-competition covenant which applies for 6 months from the date of termination of the relevant executive service contract and non-solicitation covenants in respect of customers, suppliers and employees which apply for 12 months from the date of termination of the relevant executive service contract. The undertaking not to disclose or use confidential information applies during and after employment. 7.2.8 The Executive Directors are not permitted to be directly or indirectly employed, engaged, concerned or interested, whether as a director, employee, sub-contractor, partner, consultant, proprietor, agent or otherwise, in any other business, undertaking or occupation or the setting up of any other business, undertaking or occupation, or accept any other engagement or public office (other than becoming a Minority Holder, as defined in their service agreements, provided that they disclose this in writing to the board of the Company). The executive service contracts also contain provisions relating to share dealings. 7.2.9 The Executive Directors have the benefit of a qualifying third party indemnity from the Group (the terms of which are in accordance with the 2006 Act) and appropriate directors’ and officers’ liability insurance. 7.2.10 The Company is entitled to put the Executive Directors on garden leave during their employment. During such period of garden leave, the Executive Directors will be entitled to receive salary and all contractual benefits. 7.2.11 The Company has the ability to terminate the employment of the Executive Directors with immediate effect by making a payment in lieu of notice which shall consist of base salary only. 7.2.12 The Senior Managers are, in certain circumstances, entitled to enhanced redundancy pay of up to 52 weeks’ pay depending on age and service. 7.2.13 In certain defined and time limited circumstances set out in his service agreement, where his employment is terminated, Alan Bruce is entitled to payment equal to 3 times 342
base annual salary for loss of employment subject to him signing a settlement agreement. 7.2.14 In certain defined and time limited circumstances set out in his service agreement, where his employment is terminated, Iain Lewis is entitled to payment equal to 12 months’ base salary for loss of employment subject to him signing a settlement agreement. 7.3 Non-Executive Directors In connection with the expected admission to the London Stock Exchange, each of the Non- Executive Directors (other than Idan Wallace) will enter into a letter of appointment with the Company, which will terminate on the occurrence of certain events, and will last for an initial period of three years and be subject to annual re-election: Mr Wallace entered into a letter of appointment with the Company on 10 October 2022 on substantially the same terms as the letters of appointment to be entered into by the Proposed Directors (save as otherwise disclosed in this paragraph 7.3). 7.3.1 The letters of appointment of each of the independent Non-Executive Directors (but not for Idan Wallace) will be conditional upon admission and terminate in the event that admission does not occur by 30 November 2022, will last for an initial period of three years and will be subject to annual re-election. 7.3.2 The Non-Executive Directors’ fees will be set at a level to reflect the amount of time and level of involvement required in order to carry out their duties as members of the Board and its committees, and to attract and retain Non-Executive Directors of the highest calibre with relevant commercial and other experience. The Senior Independent Director, John Mogford, will receive an annual fee of £105,000, this fee is inclusive of membership of any Board committee. Each of Deborah Gudgeon and Lynne Clow will receive an annual fee of £95,000, this fee is inclusive of membership of any Board committee. Assaf Ginzburg will receive an annual fee of £75,000, this fee is inclusive of membership of any Board committee. Idan Wallace, is not entitled to receive an annual fee in connection with his appointment. 7.3.3 The fees paid to the Non-Executive Directors are to be determined by the remuneration committee, and the fees of the other Non-Executive Directors will be determined by the Board. No Board member may participate in the approval of their own fees. 7.3.4 Each independent Non-Executive Director will sign up to share subscription agreements. The Non-Executive Directors will not otherwise be eligible to participate in any of the Company’s incentive arrangements and do not receive pension contributions. The Non-Executive Directors are entitled to reimbursement of reasonable and properly incurred expenses (including travel expenses). The Non- Executive Directors will not be entitled to receive any compensation on termination of their appointment. 7.3.5 The Non-Executive Directors will have the benefit of a qualifying third-party indemnity from the Company (the terms of which are in accordance with the 2006 Act) and appropriate directors’ and officers’ liability insurance. 7.3.6 Save as set out in this paragraph 7, no benefits are payable by any member of the Group to any Director or Senior Manager upon termination of employment. 7.4 Remuneration Policy In anticipation of a public listing of Ithaca Energy, the Company undertook a review of the Company’s remuneration policy for senior employees, including the Executive Directors, to ensure that it is appropriate for the listed company environment. In undertaking this review, the Company sought independent, specialist advice. The principal objectives of the policy, which shall apply from the expected admission, are to attract, retain and motivate the Executive Directors and senior employees, incorporating incentives that align with and support the Group’s business strategy as it evolves, and which align executives to the creation of long-term shareholder value. 343
The remuneration committee (which the Company intends to constitute should the Group proceed with a public listing of the Ithaca Energy business) will oversee the implementation of the Company’s remuneration policy and, in particular, will seek to ensure that the Executive Directors are properly rewarded for the Group’s performance and the delivery of the Group’s strategy. 7.5 Directors’ and Senior Managers’ remuneration In the financial year ended 31 December 2021, the aggregate remuneration paid (including any contingent or deferred compensation) and benefits in kind granted by the Company and its Subsidiaries for services in all capacities to the Company and its Subsidiaries to the Directors and Senior Managers was £1.3 million, of which £0.8 million comprised salaries/fees, £223,062 bonuses, £46,500 car allowances, £269,708 pension contributions and £6,040 healthcare benefits. Set out in the table below is the remuneration paid and benefits in kind granted to the Directors and Senior Managers in the year ended 31 December 2021. The Directors and Senior Managers are categorised in their positions as at the date of this Registration Document for these purposes. Name Position Annual Remuneration Salary (£) Annual Remuneration Bonus (£) (2) Other Benefits (£) Date of joining the Group Gilad Myerson . . . . Chairman 337,500 (1) 763,359 10,200 19 April 2021 Alan Bruce . . . . . . . CEO 113,846 (1) 102,500 10,200 16 August 2021 Iain Lewis . . . . . . . CFO n/a n/a n/a 25 July 2022 John Horsburgh . . . . General Manager, Subsurface and Wells 235,100 58,775 10,200 12 May 2008 Julie McAteer . . . . . General Manager, Legal & Business Affairs 190,000 59,375 10,200 24 February 2020 Rachel Stanley . . . . General Manager NOJV, Energy Transition, Technology and Innovation 193,550 36,290 10,200 14 October 1996 Brian Winton . . . . . . General Manager Operations, Projects and Decommissioning 180,000 45,000 10,200 1 January 2021 Craig Matthew . . . . General Manager, Greenfield Projects 66,349 (1) 5,000 n/a 16 August 2021 Note: (1) Denotes pro rata entitlement for the financial year ended 31 December 2021. (2) The figures in this column reflect bonuses for performance in the year ended 31 December 2021 but which were not paid until March 2022. Bonuses in respect of performance during the financial year ended 31 December 2020 were paid to certain directors and senior managers in the financial year ended 31 December 2021. Given these relate to the financial year ended 31 December 2020, these have not been reflected in this table. Due to the current structure of the Company’s pension arrangements, neither the Company nor any of its Subsidiaries set aside or accrued amounts to provide for pension, retirement or similar benefits of the Directors and Senior Managers. The Company’s group personal pension plan is a collection of individual pension plans where each member enters into an individual contract with the pension provider in their own name. 7.6 Bonus arrangements Should the Group proceed with a public listing of the Ithaca Energy business, it intends to adopt the Executive Bonus proposals set out below: Executive Directors and other senior employees are eligible to participate in the Ithaca Energy annual bonus plan. In the event of any admission, the maximum annual bonus opportunity for Executive Directors will be 150% of base salary. The annual bonus will be based on stretching financial, strategic and operational targets. Half of any bonus earned will be subject to bonus deferral. Any bonus subject to deferral will be deferred into an award over Ordinary Shares in accordance with the Ithaca Energy Deferred Share Bonus Plan (summarised at paragraph 8 below). 344
The existing FY2022 annual bonus will continue to operate for the remainder of the year and will be payable in cash following the year end. The current bonus ordinarily has a maximum annual bonus opportunity for the Executive Directors of 50% of salary and is subject to the achievement of a scorecard of measures. Separately, in the event of any admission, approximately 30 employees (including the Executive Directors) the Company intends to award a cash bonus of up to £50,000 each to recognise their exceptional contribution to admission. These bonuses will not be subject to any further conditions or deferral requirements and will be payable at admission. The total IPO bonus pot available for distribution in connection with such bonuses is £1,500,000. Additionally, Mr Myerson is entitled to receive a one-off payment for the accounting period ending 30 September 2022, in the amount of $1 million. The payment is due to be paid on 1 April 2023. The remuneration committee will have the discretion to adjust bonus outcomes (including to zero) if it believes that the outcome is not a fair and accurate reflection of business performance. The exercise of this discretion may result in a downward or upward adjustment in the amount of bonus that would otherwise be earned by reference to the applicable bonus targets. 7.7 Additional success based compensation Pursuant to arrangements agreed with IEEPL on 15 July 2021, Mr Myerson is also entitled to separate additional success based compensation linked to the outcome of the arbitration proceedings raised by IEUK, further details of which are set out in paragraph 14 (Legal and Arbitration Proceedings) of this Part 15 (Additional Information). In the event that IEUK is successful in the proceedings, either by way of commercial settlement or arbitral award by the arbitration tribunal, Mr Myerson shall be entitled to up to 1.8% of the net proceeds received by IEUK provided at the date of payment he remains employed by the Group and no notice to terminate his employment has been served. The outcome of the claim is uncertain at this stage and the quantum of any proceeds sought by IEUK is subject to expert evidence that is yet to be finalised. As such it is not possible to quantify the amount of any potential success based compensation and consequently it is not possible to quantify the amount of Mr Myerson’s potential related additional compensation, although it is IEUK’s reasonable expectation that, if it is successful in the proceedings, the level of damages recovered by IEUK will be material and accordingly Mr Myerson’s additional compensation could be significant. Further details of the proceedings are set out in paragraph 14 (Legal and Arbitration Proceedings) of this 15 (Additional Information). Mr Wallace, the CEO of the Delek Group and a Non-Executive Director in the Company, is entitled to a payment of up 1% of the net proceeds received by IEUK in respect of the same arbitration proceedings on the same terms as Mr Myerson’s additional compensation. Further details of the arrangements for Mr Wallace are set out in paragraph 15 (Related Third Party Transactions) of this Part 15 (Additional Information). 8. EMPLOYEE INCENTIVE SCHEMES Should the Group proceed with a public listing of the Ithaca Energy business, it intends to adopt the share plans set out below for the grant of awards on or following such public listing, such adoption to take place immediately prior to and conditional upon such public listing. For these purposes references to the “Company” means the holding company of the Group, references to “Shares” means ordinary shares in the capital of that Company, references to the “Remuneration Committee” means the remuneration committee of that Company which the Group intends to constitute should the Group proceed with a public listing of the Ithaca Energy business in the UK. The Group proposes to adopt three employee share schemes immediately prior to expected admission to the London Stock Exchange: (i) the Ithaca Energy Long Term Incentive Plan; (ii) the Ithaca Energy Deferred Share Bonus Plan; and (iii) a Share Incentive Plan. The Group has also adopted a further employee share scheme—the Management Equity Plan—prior to expected admission, and in respect of which awards of Ordinary Shares will continue to vest for a period after expected admission. The principal features of each of the employee share schemes are summarised below. 345
8.1 Ithaca Energy Long Term Incentive Plan General The Ithaca Energy Long Term Incentive Plan (the “LTIP”) will enable Executive Directors and selected employees of the Group to be granted awards (“LTIP Awards”) over Ordinary Shares. The LTIP has been designed to align with prevailing best practice and the terms of the Directors’ Remuneration Policy which is summarised at paragraph 7.5 (Directors’ and Senior Managers’ remuneration) of this Part 15 (Additional Information). The operation of the LTIP will be overseen by the Remuneration Committee, which consists entirely of non-executive directors. Eligibility The LTIP rules provide that all employees of the Group (including Executive Directors) are eligible to participate at the discretion of the Remuneration Committee. However, for so long as any Ordinary Shares held by Gilad Myerson under the Management Equity Plan (described at paragraph 8.4 below) remain unvested in accordance with his terms, Mr Myerson shall not be eligible to participate in the LTIP. Individual Limits The maximum number of Ordinary Shares that may be awarded to a participant in the form of LTIP Awards in any financial year will be limited so that the market value of such Ordinary Shares on the grant date will not exceed 225% of the participant’s base salary or any higher limit that is specified under the Company’s prevailing shareholder-approved Directors’ Remuneration Policy in force at the time that the relevant LTIP Award is granted. Market value for the purposes of the above limit shall generally be taken to be either the market value of Ordinary Shares on the dealing day immediately preceding the date on which the LTIP Award is granted or by reference to a short averaging period, or on such other reasonable basis as the Remuneration Committee decides. Vesting of LTIP Awards and Performance Conditions LTIP Awards may be subject to stretching performance conditions which will determine the extent to which such LTIP Awards shall be capable of vesting (“Performance Awards”). Alternatively, LTIP Awards may be granted which are not subject to performance conditions and which vest solely on the basis of the participant’s continued employment with the Group (“Restricted Share Awards”). Restricted Share Awards may not be granted to Executive Directors. Performance Awards will not ordinarily be capable of vesting until the third anniversary of their grant date, except in exceptional circumstances such as corporate events (see further below). Post-vesting holding period Executive Directors (and such other participants as the Remuneration Committee determines) shall be required to retain any vested Ordinary Shares acquired under the LTIP until the fifth anniversary of the grant date of the relevant LTIP Award. In exceptional circumstances, the Remuneration Committee may allow a participant who is subject to the post-vesting holding period to sell, transfer, assign or dispose of some or all of those Ordinary Shares prior to the end of the post-vesting holding period. Initial Awards Ithaca Energy intends to grant an initial set of LTIP Awards to senior employees (excluding Mr Myerson and Mr Bruce) immediately prior to the date of expected admission (the “At-IPO Awards”). The At-IPO Awards are intended to recognise effort and performance up to expected admission, to provide an incentive and retention mechanism for recipients and also to settle certain obligations of Ithaca Energy under legacy incentive arrangements offered prior to expected admission. 346
The At-IPO Awards will be granted in the form of a Restricted Share Award and will not be subject to any performance conditions. The At-IPO Awards will vest in three equal instalments on the first, second and third anniversaries of the date of expected admission respectively. The At-IPO Awards will be granted over Ordinary Shares having a market value (determined by reference to the offer price payable in connection with the expected admission), equal to a specified percentage of the participant’s base salary, with the percentage depending on the individual’s employment grade (and ranging from 50% to 100% of base salary). Additionally, Ithaca Energy intends to grant a set of LTIP Awards to senior employees including the Executive Directors other than Mr Myerson) immediately prior to the date of expected admission (the “Initial LTIP Awards”). The Initial LTIP Awards will be granted in the form of either Performance Awards or Restricted Share Awards. Executive Directors receiving Initial LTIP Awards will be granted Performance Awards. The Initial LTIP Awards will ordinarily vest on the third anniversary of the date of expected admission, and in the case of the Initial LTIP Awards which are granted as Performance Awards. The performance measures for the Initial LTIP Awards will be as follows: • 50% Relative TSR—the Company’s TSR to be assessed against a comparator group of companies over a period of 3 years from expected admission. 25% of the shares vest for achieving Median ranking, rising on a straight-line basis to full vesting for achieving an Upper Quartile ranking. • 50% a balanced score card of company performance measures—these shall comprise safety & environmental measures, operational measures, growth measures (by reference to strategic acquisitions) and financial measures (by reference to EBITDAX performance). The Initial LTIP Awards will be granted over Ordinary Shares having a market value (determined by reference to the offer price payable in connection with expected admission), equal to a specified percentage of the participant’s base salary, with the percentage depending on the individual’s employment grade (and ranging from 75% to 225% of base salary). For the Executive Directors (other than Mr Myerson), the Initial LTIP Awards will be granted over Ordinary Shares having a market value equal to 225% and 200% of salary for the Chief Executive Officer and Chief Financial Officer respectively. Performance Awards Performance conditions applicable to Performance Awards granted after expected admission will be kept under review and may be varied in the future years, but may include a combination of financial, value creation, operational or strategic measures. Details of the performance conditions applicable to LTIP Awards granted to Executive Directors will be fully disclosed in the Company’s Annual Report and Accounts which are prepared for the year in which the relevant LTIP Awards were granted and will at all times be subject to the Company’s prevailing shareholder-approved Directors’ Remuneration Policy. The Remuneration Committee may vary the performance conditions applying to existing Performance Awards if an event has occurred which causes the Remuneration Committee reasonably to consider that it would be appropriate to amend the performance conditions, provided the Remuneration Committee considers the varied performance conditions are a fairer measure of performance and provide a more effective incentive for the participant and will not be materially less difficult to satisfy than the original conditions would have been but for the event in question. Adjustment of vesting outcome of LTIP Awards Other than the At-IPO Awards, the Remuneration Committee retains discretion to adjust the extent of vesting of any LTIP Award that would otherwise result under the LTIP rules. In the case of Performance Awards, such adjustment may be irrespective of the extent to which any performance condition applicable to that Performance Award has been met. Such discretion would only be used where the Remuneration Committee considers that the extent of vesting but for any adjustment would not produce an appropriate vesting outcome for the relevant participant or the Group, taking into account overall performance of the Group or the participant, or because the vesting outcome is inappropriate in the context of 347
circumstances that were unexpected or unforeseen at the start of the applicable performance period. Cessation of Employment If a participant ceases to be employed within the Group, their LTIP Award(s) will normally lapse on the date of termination of employment. However, if a participant ceases to be employed with the Group due to their: (i) death; (ii) ill- health or disability; (iii) the sale of the Group member or business unit which is the participant’s employer company or business unit for which they work out of the Group; or (iv) in any other circumstances at the Remuneration Committee’s discretion, then the participant will be treated as a “good leaver”, in which case their LTIP Award(s) shall vest subject to: • in the case of Performance Awards, the extent to which the performance conditions applicable to the Performance Award(s) have, in the opinion of the Remuneration Committee, been satisfied over the original performance period; and • in the case of all LTIP Awards, a time pro-rata apportionment of the number of Ordinary Shares under the LTIP Award(s) by reference to the length of time between the grant date of the relevant LTIP Award and the date of cessation of the participant’s employment, relative to the full length of the original vesting period. LTIP Awards held by good leavers will normally vest on their normal vesting timetable. Exceptionally and at the Remuneration Committee’s discretion, LTIP Awards held by good leavers may vest sooner following the date of the participant’s cessation of employment. In a good leaver scenario, the Remuneration Committee will retain discretion to vary the application of time pro-rating and increase the number of Ordinary Shares which vest (although, in the case of a Performance Award, this may not result in the number of Ordinary Shares which vest being higher than the number of Ordinary Shares which may vest by reference to application of the performance conditions). Takeover, Reconstruction etc. In the event of: (i) a takeover of the Company; (ii) a scheme of arrangement (not being an internal corporate re-organisation); (iii) a winding-up of the Company; or (iv) (at the discretion of the Remuneration Committee) a demerger, unvested LTIP Awards shall vest immediately subject to: • in the case of Performance Awards, the Remuneration Committee’s assessment of the extent to which the performance conditions applicable to the LTIP Awards have been met at the date of the relevant corporate event or (at the Remuneration Committee’s discretion) the extent to which such performance conditions would, in the opinion of the Remuneration Committee, have been satisfied over the original performance period; and • in the case of all LTIP Awards, a time pro-rata apportionment of the number of Ordinary Shares under the LTIP Award by reference to the length of time between the grant date of the relevant LTIP Award and the date of the corporate event, relative to the full length of the original vesting period. Where there is a takeover or other corporate event, the Remuneration Committee will retain discretion to vary the application of time pro-rating and increase the number of Ordinary Shares which vest (although, in the case of a Performance Award, this may not result in the number of Ordinary Shares which vest being higher than the number of Ordinary Shares which may vest by reference to application of the performance conditions). Alternatively, on the occurrence of a takeover or a scheme or arrangement, the Remuneration Committee may specify that LTIP Awards shall not vest on the occurrence of such event and instead participants shall be required to ‘roll-over’ their awards into equivalent new awards over shares in a new holding company. LTIP Awards will be automatically ‘rolled-over’ on the occurrence of an internal reorganisation. 348
8.2 Ithaca Energy Deferred Bonus Plan General The Ithaca Energy Deferred Share Bonus Plan (the “DSBP”) is intended to facilitate the deferral of a portion of any annual bonus which is paid to selected employees of the Group into awards over Ordinary Shares (“DSBP Awards”). The DSBP has been designed to align with prevailing best practice and the terms of the Directors’ Remuneration Policy which is summarised at paragraph 7.1 of this Part 15 (Additional Information). The operation of the DSBP will be overseen by the Remuneration Committee, which consists entirely of non-executive directors. Eligibility All employees of the Group are eligible to participate in the DSBP and receive DSBP Awards at the discretion of the Remuneration Committee. The DSBP will primarily be operated to defer the bonuses of Executive Directors. However, the Remuneration Committee may select other employees of the Group to participate in the DSBP at its discretion. Size of DSBP Awards DSBP Awards shall be granted over such number of Ordinary Shares as have a market value equal to the value of the portion of the employee’s bonus that the Remuneration Committee has determined is required to be deferred into a DSBP Award. In the case of Executive Directors, the proportion of their annual bonus which is required to be deferred into a DSBP Award shall be not less than the amount specified in the Company’s prevailing shareholder-approved Directors’ Remuneration Policy in force at the time that the DSBP Award is granted. The Remuneration Committee retains discretion to specify that a higher proportion (including up to 100%) of an Executive Director’s annual bonus shall be required to be deferred into a DSBP Award at its discretion. Market value for the purposes of the above limit shall generally be taken to be either the market value of Ordinary Shares on the dealing day immediately preceding the date on which the DSBP Award is granted or by reference to a short averaging period, or on such other reasonable basis as the Remuneration Committee decides. Vesting of DSBP Awards DSBP Awards granted to Executive Directors will not ordinarily be capable of vesting until the third anniversary of their grant date, except in exceptional circumstances such as corporate events. Shorter vesting periods may apply to DSBP Awards granted to employees who are not Executive Directors. The vesting of DSBP Awards will not ordinarily be subject to the achievement of any performance conditions. Leaving employment If a participant ceases to be employed within the Group due to their dismissal for cause or their voluntary resignation, their DSBP Awards will normally lapse on the date of termination of employment. If a participant ceases to be employed with the Group for any reason other than their dismissal for cause or their voluntary resignation, their DSBP Award will remain capable of vesting in full on its normal vesting timetable unless the Remuneration Committee determines that any such DSBP Awards held by good leavers shall vest at an earlier date (although it is anticipated that the Remuneration Committee would not ordinarily permit early exercise of DSBP Awards by good leavers). 349
Corporate events In the event of: (i) a takeover of the Company; (ii) a scheme of arrangement (not being an internal corporate re-organisation); (iii) a winding-up of the Company; or (iv) (at the discretion of the Remuneration Committee) a demerger, unvested DSBP Awards shall vest immediately and in full. Alternatively, on the occurrence of a takeover or a scheme or arrangement, the Remuneration Committee may specify that DSBP Awards shall not vest on the occurrence of such event and instead participants shall be required to ‘roll-over’ their awards into equivalent new awards over shares in a new holding company. DSBP Awards will be automatically ‘rolled-over’ on the occurrence of an internal reorganisation. Terms common to the LTIP and DSBP In this paragraph 8.2, references to “Awards” are to both LTIP Awards and DSBP Awards unless otherwise stated. Grants of Awards Awards may be granted: • in the period of six weeks following expected admission; • in the period of six weeks commencing on the dealing day following the announcement by the Company of its results for any period; • in the case of the LTIP, within six weeks of a person commencing employment with the Group; • in the case of the DSBP, as soon as reasonably practicable following the determination of the relevant employee’s bonus for any period; and • subject to any relevant restrictions on dealings in Ordinary Shares, on any other day on which the Remuneration Committee determines that exceptional circumstances exist that justify the grant of an Award. If regulatory or statutory restrictions prevent Awards from being granted in these periods, Awards may be made in the period immediately after the removal of all such restrictions. No Awards may be granted under either the LTIP or the DSBP more than 10 years after the date of any admission of the Company to the London Stock Exchange. Structure of Awards Awards may be structured as: (i) conditional awards of Ordinary Shares; or (ii) as nil-cost or nominal-cost options to acquire Ordinary Shares. The Remuneration Committee may also grant cash-based awards of an equivalent value to share-based awards, or settle share-based awards with cash, although the Remuneration Committee does not currently intend to do so. Exercise periods (applicable only to options) Where Awards are granted in the form of options to acquire Ordinary Shares, once vested such options will remain exercisable up until the tenth anniversary of their grant date (or such shorter period that the Remuneration Committee specifies on grant). Shorter exercise periods apply in the case of Awards held by “good leavers” and/or vesting of Awards in connection with corporate events. Dilution limits Awards granted under either the LTIP or the DSBP may be satisfied by the issue of new Ordinary Shares, Ordinary Shares purchased in the market by an employee benefit trust or Ordinary Shares transferred from treasury. 350
No Award may be granted under either the LTIP or the DSBP if it would cause the number of new Ordinary Shares issued or issuable pursuant to awards and options granted in any rolling 10 year period starting on expected admission under any Group share plan (including the LTIP, DSBP and the SIP) to exceed 10% of the Company’s issued ordinary share capital at the proposed date of grant. A similar 5% in 10 years limit applies to awards granted under the Company’s discretionary share plans (which would include the LTIP and the DSBP). For the avoidance of doubt, the At-IPO Awards and the Initial LTIP Awards do not count towards these dilution limits. As is typical, if Awards are specified as being capable of being satisfied by a transfer of existing Ordinary Shares only (including Ordinary Shares held by or purchased by the Company’s employees’ share trust), the percentage limits stated above will not apply. For so long as it is required by institutional investor guidelines, these dilution limits will also apply to Awards satisfied by the transfer of Ordinary Shares from treasury. Dividend equivalent payments The Remuneration Committee may determine that a participant is entitled to receive a payment (in cash or shares) when they receive their vested Ordinary Shares of an amount equivalent to any dividends that would have been payable in relation to the vested Ordinary Shares between the date of grant and the vesting date of the Award (or if later, and only whilst an Award which is structured as an option remains unexercised, the expiry of any post-vesting holding period). Any dividend equivalent payment may exclude the amount of any special dividends or other dividends and/or may assume re-investment of dividends in further Ordinary Shares, in each case at the discretion of the Remuneration Committee. Post-cessation holding period Executive Directors (and such other participants as the Remuneration Committee determines) will ordinarily be required to retain a number of Ordinary Shares that vest in connection with any Award until at least the second anniversary of the date of their cessation of employment with the Group. The number of Ordinary Shares that are required to be retained shall be determined by the Remuneration Committee at the time that the Award vests. The details of the post-cessation holding period, including the specified number or value of Ordinary Shares that an individual is required to retain post-cessation of their employment, will be set out in the Directors’ Remuneration Policy. Exceptionally, the Remuneration Committee may allow participants who are subject to the post- cessation holding period to sell, transfer, assign or dispose of some or all of those Ordinary Shares prior to the end of the post-cessation holding period, subject to such additional terms and conditions as the Remuneration Committee specifies. Malus and Clawback The Remuneration Committee may apply the malus and clawback provisions, at any point prior to the third anniversary of the date on which an Award vests, if: • it is discovered that there has been a material misstatement of the Group’s financial results for any period; • it is discovered that an error of calculation has occurred when assessing the performance conditions; • the participant has committed fraud or misconduct; • the behaviour of the participant materially fails to reflect the governance or values of the Company or has caused injury to the reputation of the Group; and/or • the Company has suffered an instance of material corporate failure. Any application of malus and clawback may be satisfied by way of a reduction in the amount of any future bonus, subsisting award or future share awards (whether granted under the LTIP, 351
DSBP or any other discretionary share plan adopted by any Group member) and/or a requirement to make a cash payment. Variations of share capital If there is: (i) a capitalisation or rights issue; (ii) a sub-division, consolidation or reduction of the Company’s ordinary share capital; (iii) a de-merger or payment of a special dividend; or (iv) any variation of the Company’s share capital that may (in the opinion of the Remuneration Committee) affect the value of the Company’s shares, then the Remuneration Committee may (at its discretion) adjust the number of Ordinary Shares subject to Awards. Amendments The Remuneration Committee may amend the LTIP and the DSBP at any time at its discretion. However, the provisions governing: (i) eligibility requirements; (ii) equity dilution; (iii) individual limits on participation; (iv) the basis for determining participants’ rights to acquire shares; and (v) the adjustments that may be made following a rights issue or any other variation of capital, cannot be altered to the advantage of participants without the prior approval of the Company’s shareholders in general meeting. There is an exception for minor amendments to benefit the administration of the LTIP or the DSBP, to take account of a change in legislation affecting the LTIP or the DSBP (as applicable) or to obtain or maintain favourable tax, exchange control or regulatory treatment for participants in the LTIP or DSBP or for any member of the Group. Rights attaching to shares Awards which are structured as conditional awards over Ordinary Shares or as options over Ordinary Shares will not confer any shareholder rights, such as the right to vote the Ordinary Shares or to receive any dividend, until a participant has received the Ordinary Shares after vesting or exercise (as applicable). Ordinary Shares allotted or transferred under the LTIP or the DSBP will rank alongside shares of the same class then in issue. Miscellaneous Awards are not transferable (except on death). Benefits received under the LTIP or DSBP are not pensionable benefits. No payment shall be required for the grant of an Award. The Remuneration Committee may adopt schedules to, or establish further plans based on, the LTIP and/or the DSBP but which are modified to take account of local tax, exchange control or securities laws in any territory, provided that such further plans are materially similar to the LTIP or DSBP (as applicable) and that any Ordinary Shares made available under such further plans are treated as counting against the limits on individual or overall participation in the LTIP or DSBP (as applicable). 8.3 Share Incentive Plan General The Ithaca Energy Share Incentive Plan (the “SIP”) complies with and will be operated within the requirements of Schedule 2 to the Income Tax (Earnings and Pensions) Act 2003 (“Schedule 2”) so that the SIP qualifies as a Schedule 2 Share Incentive Plan under the governing legislation. Types of awards The SIP comprises the following three elements and the Directors may decide which element (or elements) to offer to eligible employees: (a) “Free Shares”, which are Ordinary Shares which may be allocated to an eligible employee for free. 352
The maximum market value of Free Shares that may be allocated to any eligible employee in any tax year is £3,600 (or such other limit as may be permitted under Schedule 2). Free Shares may be allocated to eligible employees equally or on the basis of performance, as permitted by Schedule 2. (b) “Partnership Shares”, which are Ordinary Shares that an eligible employee may purchase out of their pre-tax earnings. The market value of Partnership Shares that may be acquired by an eligible employee in any tax year may not exceed £1,800 (or 10% of the eligible employee’s salary, if lower), or such other limit as may be permitted by Schedule 2. (c) “Matching Shares”, which are Ordinary Shares which may be allocated for free to an eligible employee who elects to purchase Partnership Shares. The Directors may allocate Matching Shares to an eligible employee who purchases Partnership Shares at a ratio of up to two Matching Shares for every one Partnership Share (or such other maximum ratio as may be permitted by Schedule 2). Eligibility Any UK-based employee (including any UK-based Executive Director) of Ithaca Energy or any other participating subsidiary of Ithaca Energy who has been employed for a qualifying period of such length as the Directors may determine from time to time (but not exceeding 18 months) is eligible to participate in the SIP. All eligible employees must be invited to participate. Retention of Shares Free Shares and Matching Shares will be held by the trustee of the SIP trust (“Trustee”) on behalf of the participants. Ordinarily, any Free Shares and Matching Shares must be held by the Trustee for a period of between three and five years after the date that those Free Shares and/or Matching Shares are awarded. Partnership Shares will be acquired and held by the Trustee on behalf of participants, using the funds contributed by the relevant participant by way of pre-tax salary deductions. Partnership Shares can be withdrawn from the SIP trust at any time. Leaving employment The Directors may determine that any Free Shares and/or Matching Shares will be forfeited if a participant ceases to be employed by the Group within three years (or such lesser period as the Directors may determine) from the award of those Free Shares and/or Matching Shares, unless the participant leaves by reason of death, injury, disability, redundancy, retirement, a transfer to which the Transfer of Undertakings (Protection of Employment) Regulations 2006 would apply or if the participant’s employer company ceases to be an “associated company” of Ithaca Energy. In any of those cases, the participant will be required to withdraw their Shares from the SIP trust. If an employee ceases to be employed by the Group at any time after acquiring Partnership Shares, the employee will be required to withdraw the Partnership Shares from the SIP trust. 353
Corporate events In the event of a general offer being made to Shareholders, participants may be able to direct the Trustee how to act in relation to their Ordinary Shares. In the event of a corporate reorganisation, any Ordinary Shares held by participants may be replaced by equivalent shares in a new holding company. In the case of a variation of share capital of Ithaca Energy, Ordinary Shares held in the SIP will be treated in the same way as other Ordinary Shares. In the event of a rights issue, participants may be able to direct the Trustee how to act on their behalf. Dividends on Ordinary Shares held by the Trustee Any dividends paid on Ordinary Shares held by the Trustee on behalf of participants may be either distributed to participants or used to acquire additional Ordinary Shares for employees. If any dividends are used to acquire additional Ordinary Shares, any such additional Ordinary Shares will be held by the Trustee on behalf of the participants on the same basis as the underlying Ordinary Shares on which the dividends were paid. Rights attaching to Ordinary Shares acquired under the SIP An employee will be treated as the beneficial owner of Ordinary Shares held on their behalf by the Trustee. Non-transferability of awards Grants of Free Shares and Matching Shares are not transferable other than to the participant’s personal representatives in the event of their death. Benefits received under the SIP will not be pensionable. Satisfaction of awards and dilution limits Awards of Ordinary Shares in connection with the SIP may be satisfied by the issue of new Ordinary Shares, Ordinary Shares purchased in the market by the SIP trust or Ordinary Shares transferred from treasury. No award of Ordinary Shares may be made under the SIP if it would cause the number of new Ordinary Shares issued or issuable pursuant to awards and options granted in any rolling 10 year period starting on expected admission under any Group share plan (including the LTIP, DSBP and the SIP) to exceed 10% of the Company’s issued ordinary share capital at the proposed date of award. For so long as it is required by institutional investor guidelines, these dilution limits will also apply to awards of Ordinary Shares which are satisfied by the transfer of Ordinary Shares from treasury. Amendment The Directors may amend the SIP at any time at their discretion. However, the provisions governing: (i) eligibility requirements; (ii) equity dilution; (iii) individual limits on participation; (iv) the basis for determining participants’ rights to acquire shares; and (v) the adjustments that may be made following a rights issue or any other variation of capital, cannot be altered to the advantage of participants without the prior approval of the Company’s shareholders in general meeting. There is an exception for minor amendments to benefit the administration of the SIP, to take account of a change in the requirements of Schedule 2 or any other 354
legislation affecting the SIP or to obtain or maintain favourable tax, exchange control or regulatory treatment for participants in the SIP or for any member of the Group. International schedules and sub-plans The Directors may adopt schedules to, or establish further plans based on, the SIP but which are modified to take account of local tax, exchange control or securities laws in any territory, provided that such further plans are materially similar to the SIP and that any Ordinary Shares made available under such further plans are treated as counting against the limits on individual or overall participation in the SIP. 8.4 Management Equity Plan Pursuant to arrangements entered into prior to the date of this Registration Document, Ithaca Energy has established a management equity plan for the benefit of Gilad Myerson (the “MEP”). The principal purpose of the MEP is to incentivise and align Mr Myerson’s interests with those of Ithaca Energy’s shareholders in the realisation of maximum shareholder value following the expected admission. The MEP is structured such that Mr Myerson is entitled to receive shares in Ithaca Energy which, on the expected admission date, have a value which is equal to 1.3% of the market value of Ithaca Energy above a fixed hurdle of $2.5 billion (the “Hurdle”). When Mr Myerson joined Ithaca Energy the market value was substantially lower than $2.5 billion, and the MEP is intended to create a structural incentive for Mr Myerson to maximise the value of the share capital of Ithaca Energy. Under the MEP, Mr Myerson subscribed for two separate classes of shares (B1 Ordinary Shares and B2 Ordinary Shares) in Ithaca Energy and which carried limited rights (e.g., no voting rights, and limited rights to transfer the shares). Immediately prior to the expected admission, the B1 Ordinary Shares and B2 Ordinary Shares will convert into such number of Ordinary Shares as have a value (by reference to the offer price payable in connection with that expected admission) which is equal to, respectively, 1% and 0.3% of the market value of Ithaca Energy on the expected admission minus the Hurdle (the “MEP Shares”). The MEP Shares will ‘vest’ over a five year period starting from 1 October 2021 as follows: • the B1 Ordinary Shares (or any Ordinary Shares received in respect of those B1 Ordinary Shares): 15% on 1 October 2022, a further 15% on 1 October 2023, a further 15% on 1 October 2024, a further 15% on 1 October 2025, and the remaining 40% on 1 October 2026. • the B2 Ordinary Shares or any Ordinary Shares received in respect of those B2 Ordinary Shares): 45% on 1 October 2024, a further 15% on 1 October 2025, and the remaining 40% on 1 October 2026. Accordingly, from 1 October 2026 the MEP Shares will be fully vested. Whilst any of the MEP Shares remain unvested, Mr Myerson shall not be eligible to participate in, and receive grants of awards under, the Ithaca Energy Long Term Incentive Plan (as described at paragraph 8.1 of this Part 15 (Additional Information)). On each vesting date, Mr Myerson may receive further Ordinary Shares so as to ensure that the aggregate value of the MEP Shares is maintained at 1.3% of the value of Ithaca Energy above the Hurdle. Whilst the MEP Shares are unvested, they will be held in a nominee account on Mr Myerson's behalf and may not be transferred or sold out of the nominee account (other than with the consent of Ithaca Energy). A loan facility of up to $500,000 was provided by Ithaca Energy to cover income tax and National Insurance contributions that arose on the share subscription. 355
The B1 Ordinary Shares and B2 Ordinary Shares acquired will remain subject to forfeiture provisions in a leaver scenario. If Mr Myerson leaves as a ‘Bad Leaver’, all of the MEP Shares held by him (whether vested or unvested) shall be subject to compulsory transfer for nominal payment. Mr Myerson will be a ‘Bad Leaver’ if: (1) his employment is terminated at any time due to fraud, gross misconduct or conviction of a criminal offence; or (2) if Mr Myerson resigns voluntarily at any time prior to 1 September 2023. If Mr Myerson leaves as a ‘Good Leaver’ (being any reason other than as a ‘Bad Leaver’), any unvested MEP Shares shall be subject to compulsory transfer for nominal payment. However Mr Myerson shall be entitled to retain any MEP Shares which have vested. For the purposes of determining the number of MEP Shares have vested in a ‘Good Leaver’ scenario, an accelerated vesting schedule shall apply being 40% of the MEP Shares originally represented by the B1 Ordinary Shares only where cessation occurs prior to 1 October 2024, thereafter increasing to 60%, 80% and 100% of all of the MEP Shares on each anniversary of 1 October 2024. In certain circumstances where Mr Myerson's employment with the Group ceases as a result of any involvement from an activist minority shareholder, then Mr Myerson shall be entitled to retain any of the MEP Shares which have vested as at the termination date and, additionally, a further 50% of the unvested MEP Shares as at the termination date. In certain circumstances, such as change of control of Ithaca Energy, material disposal or termination of employment before 1 October 2023, Mr Myerson shall, in lieu of all of his MEP Shares, be entitled to receive (or, in certain circumstances, may elect to receive) a one-time payment of up to $9 million minus any bonuses received after 29 September 2022 (including the one-off payment described below). This payment will be subject to deductions for income tax and National Insurance contributions. This payment is in lieu of all the MEP Shares, which must be transferred by Mr Myerson for nil payment, and is intended to operate as a floor on the value that Mr Myerson may receive in recognition of his contribution to value creation from 2019 onwards and the incentive arrangements forfeited by him on commencing employment with the Group. As part of the overall terms of the MEP, Mr Myerson is entitled to receive a one-off payment for the accounting period ending 30 September 2022 (as described in paragraph 7.6 of this Part 15 (Additional Information)). 8.5 Option Agreements Option held by Gilad Myerson Gilad Myerson has an option over Ordinary Shares (the “GM Option”). The GM Option represents a right to subscribe for Ordinary Shares (the “GM Option Shares”) which have a value which is equal to the higher of (i) 0.2% of the net value of Ithaca Energy assets less its liabilities as at the date immediately before the IPO date; and (ii) 0.2% of the market value of the issued share capital of Ithaca Energy by reference to the most recent annual valuation of Ithaca Energy undertaken for audit as at the date immediately before the IPO date. The GM Option may only be exercised on (or in contemplation of) the occurrence of an exit event such as an IPO. Where an exit event occurs, the GM Option shall become exercisable immediately and in full. The GM Option shall not become exercisable unless and until an exit event occurs. If Mr Myerson gives or receives notice of termination of his employment with any member of the Group prior to the occurrence of an exit event, the GM Option will normally lapse. However, if Mr Myerson ceases to be employed as a result of his (i) death; (ii) permanent incapacity; (iii) illness; (iv) unfair dismissal; (v) redundancy; or (vi) voluntary resignation after 3 years, then he will be treated as a ‘good leaver” and entitled to retain and exercise the GM Option over the number of GM Option Shares which have vested as at the leaving date. The extent to which the GM Option has vested is determined in accordance with a time vesting schedule, whereby 20% of the GM Option Shares vest on each anniversary of the grant date of the Option (21 July 2021). The GM Option will lapse, to the extent not exercised, at the end of the day before the tenth anniversary of the grant date of the GM Option. 356
Dividend equivalents will be paid, if Ithaca Energy declares and pays a cash dividend during a period in which any GM Option Shares have vested but not been exercised, equal to the value of the dividend, net of tax, that the vested GM Option Shares would have received had Mr Myerson exercised the GM Option and acquired the respective GM Option Shares. The GM Option is subject to malus and clawback provisions which will apply at any point prior to the third anniversary of the Ithaca Energy board determining that a number of specified circumstances have occurred as specified in the GM Option agreement (including, but not limited to, Mr Myerson having failed to meet appropriate standards of fitness and propriety or a company in the Group for which Mr Myerson is responsible having suffered a material failure of risk management). Option held by Alan Bruce Alan Bruce has an option over Ordinary Shares (the “AB Option”). The Option represents a right to subscribe for Ordinary Shares (the “AB Option Shares”) which have a value which is equal to the higher of (i) 0.2% of the net value of Ithaca Energy assets less its liabilities as at the date immediately before the IPO date; and (ii) 0.2% of the market value of the issued share capital of Ithaca Energy by reference to the most recent annual valuation of Ithaca Energy undertaken for audit as at the date immediately before the IPO date. Exercise of the AB Option is subject to a vesting schedule, in accordance with which the AB Option, as a result of the IPO, will vest and become exercisable over a five year period, as to 20% of the AB Option Shares on each anniversary of the grant date of the Option (21 July 2021). If Mr Bruce gives or receives notice of termination of his employment with any member of the Group, the AB Option will normally lapse. However, if Mr Bruce ceases to be employed as a result of his (i) death; (ii) permanent incapacity; (iii) illness; (iv) unfair dismissal; (v) redundancy; or (vi) voluntary resignation after 3 years, then he will be treated as a ‘good leaver” and entitled to retain and exercise the AB Option over the AB Option Shares which have vested as at the leaving date. The AB Option will lapse, to the extent not exercised, at the end of the day before the tenth anniversary of the grant date of the AB Option. Dividend equivalents will be paid, if Ithaca Energy declares and pays a cash dividend during a period in which any AB Option Shares have vested but not been exercised, equal to the value of the dividend, net of tax, that the vested AB Option Shares would have received had Mr Bruce exercised the Option and acquired the respective AB Option Shares. The AB Option is subject to malus and clawback provisions which will apply at any point prior to the third anniversary of the Ithaca Energy board determining that a number of specified circumstances have occurred as specified in the AB Option agreement (including, but not limited to, Mr Bruce having failed to meet appropriate standards of fitness and propriety or a company in the Group for which Mr Bruce is responsible having suffered a material failure of risk management). 9. PENSIONS The Group operates a defined contribution group personal pension scheme. The employees that wish to participate in the scheme pay a minimum contribution of 3% of their salary, and Ithaca Energy contributes a maximum of 15% of total salary. 10. PRINCIPAL SHAREHOLDERS AND RELATED PARTY TRANSACTIONS Details of principal shareholders of the Company and material transactions with related parties to which the Company or its subsidiaries are party (or otherwise concern the Company) are set out in Part 7 (Principal Shareholders and Related Party Transactions). 11. INVESTMENTS AND PRINCIPAL ESTABLISHMENTS 11.1 The Company has made no material investments since 30 June 2022 being the latest date to which the historical financial information in Part 13 (Historical Financial Information) was prepared other than the subsidiary undertakings listed in paragraph 3.3 of this Part 15 (Additional Information). 357
11.2 The Company currently has no material investments (in progress or planned for the future on which the Directors have made firm commitments or otherwise). 11.3 The Company is not party to any corporate joint ventures and does not hold a proportion of capital in an undertaking which is likely to have a significant effect on the assessment of its own assets and liabilities, financial position or profits and losses. 11.4 The principal establishments of the Group are as follows: Location Tenure Hill of Rubislaw, Aberdeen, AB15 6XL . . . . . . . . . . . . . . . . . . . . . . . . . . . . Leasehold 23 College Hill, London, EC4R 2RP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Leasehold 12. MATERIAL CONTRACTS The following contracts (not being contracts entered into in the ordinary course of business) have been entered into by the Company or another member of the Group: (a) within the two years immediately preceding the date of this Registration Document which are, or may be, material to the Company or any member of the Group; and/or (b) at any time and contain provisions under which the Company or any member of the Group has an obligation or entitlement which is, or may be, material to the Company or any member of the Group as at the date of this Registration Document: 12.1 Finance 12.1.1 RBL Facility Agreement with BNP Paribas Overview On 19 July 2021, IEUK as borrower, signed a deed of amendment, restatement and release in relation to its existing borrowing base facility agreement dated 29 May 2019 with, among others, BNP Paribas (in its various capacities) for a $1.225 billion borrowing base facility to, among other things, fund the refinancing of its existing borrowing base facility, existing $500 million senior notes (being the 2024 Notes) and for its lawful general corporate purposes (the “RBL Facility Agreement”). The terms and conditions of the RBL Facility Agreement comprise two facilities: (a) a multicurrency revolving borrowing base credit facility up to $1.076 billion comprising BNP Paribas, Lloyds Bank plc, Wells Fargo Bank N.A., London Branch, The Royal Bank of Scotland plc, Deutsche Bank AG, Amsterdam Branch, DNB (UK) Limited, ING Belgium S.A./NV, Morgan Stanley and Mizrahi Tefahot Bank Limited, London Branch as lenders (“Facility A”); and (b) a US dollar revolving borrowing base credit facility up to $149 million comprising the aforementioned lenders as lenders (“Facility B” and together with Facility A, the “Facilities”). Facility A may be utilised by way of loan or letter of credit and may be utilised in US dollars, pounds sterling or euros. Facility B may be utilised by way of loan only and may only be utilised in US dollars. Each of IEEPL, Ithaca GSA Limited, Ithaca GSA Holdings Limited, Ithaca Minerals (North Sea) Limited, Ithaca Energy Holdings (UK) Limited, Ithaca Petroleum Limited, Ithaca Causeway Limited, Ithaca Gamma Limited, Ithaca Epsilon Limited, Ithaca Energy Developments UK Limited, Ithaca Exploration Limited, IOG, Ithaca MA Limited and Ithaca Alpha (NI) Limited are guarantors under the RBL Facility Agreement. The entities within the Siccar Point Group will accede to the RBL Facility Agreement as guarantors immediately following the expected date of admission. Each obligor subordinates its claims against each other obligor and each guarantor jointly and severally guarantees the obligations of each obligor under the RBL Facility Agreement and related finance documents, in each case, in favour of the lenders and other finance/hedging parties. The RBL Facility Agreement is drafted on the basis of a customary reducing borrowing base facility arrangement whereby the maximum amount that can be drawn or outstanding on any 358
date shall be the lesser of the total commitments (being $1.225 billion) and the borrowing base amount. The borrowing base amount shall be calculated by reference to a banking case derived from an agreed financial model prepared by the technical bank prior to each semi- annual redetermination date. The borrowing base amount, in relation to any redetermination period (periods of six months), shall be the amount set out in the banking case which is the maximum amount of the loans that could be outstanding in such calculation period whilst ensuring (i) a project life cover ratio of not less than 1.5:1 and a loan life coverage ratio of not less than 1.3:1 in respect of Facility A and (ii) a project life cover ratio of not less than 1.3:1 and a loan life coverage ratio of not less than 1.2:1 in respect of Facility B, in each case for each calculation period until the applicable final repayment date. The borrowing base amount will be approved by the lenders on each redetermination date. Security The lenders and other finance/hedging parties also benefit from security over substantially all the assets of IEUK and each guarantor—including security over their bank accounts and all balances and claims arising from such accounts, certain material agreements and certain insurance policies which each is required to maintain, as well as a first priority security over the shares in each obligor (other than IEEPL). The Facilities will share any proceeds from the enforcement of security pari passu. Repayment and Maturity The Facilities will mature on 31 May 2026 (or, if earlier, the last day of the first calculation period in which the aggregate remaining borrowing base reserves for all borrowing base assets are projected in the then current projection to be less than 25% of the initial approved reserves). Each of the Facilities are revolving facilities and subject to semi-annual reductions in accordance with an agreed amortisation schedule. Each of the total commitments shall reduce over the life of the Facilities in accordance with an agreed reduction schedule. Facility A will reduce to $808 million on 1 July 2024, $674 million on 1 January 2025, $490 million on 1 July 2025 and $335 million on 1 January 2026. Facility B will reduce to $102 million on 1 July 2024, $61 million on 1 January 2025, $46 million on 1 July 2025 and $31 million on 1 January 2026. Fees Commitment Fee: IEUK shall pay commitment fees on a quarterly basis at the rate of 40% of the margin on not utilised but available amounts and 25% of the margin on unavailable amounts. LC Commission: IEUK shall pay on a quarterly basis: (a) a commission equal to 50% of the margin on the daily amount of exposure in respect of each performance letter of credit in respect of which approved cash cover has not been provided; (c) a commission equal to the margin on the daily amount of exposure in respect of each letter of credit which is not a performance letter of credit in respect of which approved cash cover has not been provided; and (d) a commission equal to 0.40% per annum on the daily amount of exposure for which approved cash cover has been provided, provided that no lender is entitled to commission to the extent that its exposure is subject to cash cover provided by a borrower pursuant to the terms of the RBL Facility Agreement. Interest The interest rate on Facility A is (i) SOFR (or in relation to any loan in euros, EURIBOR or in relation to any loan in pounds sterling, SONIA) plus a margin of 3.5% per annum until (but excluding) the date falling four years after the date of the RBL Facility Agreement and (ii) SOFR (or in relation to any loan in euro, EURIBOR or in relation to any loan in pounds sterling, SONIA) plus a margin of 3.75% thereafter. 359
The interest rate on Facility B is (i) SOFR plus a margin of 4.5% per annum until (but excluding) the date falling four years after the date of the RBL Facility Agreement and (ii) SOFR plus a margin of 4.75% thereafter. Interest periods in respect of the Facilities will be one, three or six months’ or any other period agreed between IEUK and the majority lenders. Prepayment and Cancellation The RBL Facility Agreement contains prepayment and cancellation provisions customary for a facility of this type such as illegality, voluntary prepayment, mandatory prepayment of disposals except for permitted disposals (meaning disposals that are not borrowing base assets), mandatory prepayments of insurance claim proceeds relating to the borrowing base assets except for excluded insurance proceeds (meaning proceeds which are to be promptly applied for the repair, replacement or reinstatement of the relevant asset(s) to which the claim relates) and a mandatory prepayment for a change of control, which shall not be triggered by an initial public offering of the shares in the Company where the ultimate change of control of the Company is less than 50%. Distributions Save as otherwise agreed by the majority lenders, no obligor may make or declare payment of any distribution unless: (b) such distribution is made from funds available for that purpose pursuant to the RBL Facility Agreement; and (ii) no event of default is continuing or will occur as a result of making such distribution; or (e) in relation to any distribution in connection with any bridge facility agreement between IEUK and IEEPL and/or any additional bond financing, such distribution is equal to the amount of any payment in connection with any such bridge facility agreement and/or additional bond financing (including (if applicable) but not limited to, any payment to be made indirectly through IENS or other specific Bond Issuer); or (f) it is a distribution which is permitted in connection with specific financings. The above shall not apply to any distribution by an obligor which is (i) paid to the proceeds account of another obligor or (ii) any distribution required to give effect to any permitted disposal of the RBL Facility Agreement. The right to make a distribution falls at the end of the proceeds account waterfall. This contains requirements to pay various items before an obligor would be entitled to make a distribution including (but not limited to) finance party fees, costs and expenses; hedging costs and hedging termination payments; accrued interest; principal; gross expenditure. Thereafter, if: (a) all amounts payable under the RBL Facility Agreement and certain related documents which have fallen due for payment have been paid; (b) the aggregate US dollar amount of the outstanding utilisations does not exceed the maximum available amount; (c) no borrowing base deficiency has occurred or will occur as a result of making such payment; (d) the forecast which was due to be adopted by the most recent recalculation date has been so adopted; (e) no event of default is continuing or will occur as a result of making such payment; (f) such payment is contemplated in the most recent corporate cashflow projection and such corporate cashflow projection shows no funding shortfall after such expenditure having been taken into account; and (g) payment of such amount is permitted or not prohibited under any additional bridge financing or additional bond financing, 360
then a distribution may be made provided that (i) such payment is no later than 30 days after a recalculation date; and (ii) the provisions detailed in the paragraph below shall apply in respect of the making of any distributions. An obligor may withdraw amounts from the proceeds accounts in or towards the making of any distributions in accordance with the proceeds account waterfall (as detailed above), provided that no withdrawal or payment shall be permitted until the earlier of: (a) (i) the first date on which oil is produced from the wells located in the Captain field; and (ii) the date falling on or after the second anniversary of the satisfaction of the conditions precedent under the deed of amendment, restatement and release dated 19 July 2021 provided that IEUK has submitted to BNP Paribas a corporate cashflow projection which demonstrates to its satisfaction (acting on the instruction of the majority lenders (acting reasonably)) that the amount by which the total corporate sources exceeds total corporate uses is more than $150 million in any quarter of the forecast period as at the date of the proposed distribution); and (b) if at least 10% of the share capital of Ithaca Energy (or any replacement direct shareholder of IEEPL incorporated for the purposes of listing IEEPL) has been listed on a stock exchange, then (a) above shall not apply in respect of the withdrawal for the payment of distributions. In addition, on each date on which the IEUK intends to make a distribution it must demonstrate that (i) its total corporate sources exceed its total corporate uses in each quarter of the relevant forecast period; and (ii) the obligors have sufficient freely available funds to meet any decommissioning security obligations in respect of the borrowing base assets for the period ending three years from that date, otherwise an event of default will occur. An obligor may, at any time, transfer amounts from a proceeds account maintained by it which is denominated in any one currency to any other proceeds account maintained by it which is denominated in another currency. IOG shall procure that all amounts payable to it are paid into a proceeds account or the CNSL retained decommissioning liabilities account (as the case may be). To the extent IOG receives amounts in an account that is not a proceeds account but which would otherwise be required to be credited to a proceeds account, IOG shall transfer the same as soon as reasonably practicable (but in any event within five business days) to a proceeds account. Covenant Package The RBL Facility Agreement contains customary representations, including as to status, binding obligations, non-conflict with other obligations, power and authority, borrowing base assets and project documents, environmental compliance, ownership, the accuracy of information, borrowing base projections, anti-bribery, anti-corruption and sanctions and in certain cases are subject to knowledge and materiality qualifications. The RBL Facility Agreement imposes a number of affirmative and negative covenants on IEEPL and certain of its Subsidiary Undertakings and/or the obligors. Affirmative covenants include compliance with, among other things, environmental matters, hedging policy, applicable laws (including sanctions) and tax rules, its obligations under licences and the maintenance of certain bank accounts, insurance policies and material agreements. The RBL Facility Agreement also contains negative covenants, including, among other things, a negative pledge and restrictions (subject to, where appropriate, agreed exceptions) on: capital expenditure, distributions (including shareholder loan payments), additional financial indebtedness, disposals, acquisitions, investments and asset sales, and changes in the entities’ business, its constitutional documents or certain material agreements and an event of default for failure to comply with certain financial ratios. Such financial ratios include a project life cover ratio of not less than 1.15:1 (the project life coverage ratio being, at each calculation date, the ratio of the net present value of projected net revenues (accounting for capital expenditure add back) for the present and subsequent periods to the aggregate amount of the principal outstanding under the RBL Facility Agreement (other than in respect of letters of credit in relation to costs associated with a borrowing base asset which are already counted as gross expenditure in the most recent projection)); a loan life coverage ratio of not less than 1.05:1 (the loan life coverage ratio being, at each calculation date, the ratio of the net present value of projected net revenues (accounting for capital 361
expenditure add back) for the present and subsequent periods arising on or before the earliest of the final repayment date or reserve tail date to the aggregate amount of the principal outstanding under the RBL Facility Agreement); a ratio of net debt (excluding obligations to any other member of the Group) to EBITDAX of not less than 3.5:1; and demonstrating that total corporate sources exceed total corporate uses (which is capable of being rectified by delivery of a rectification plan in form and substance satisfactory to the majority lenders within 30 days of the date on which the relevant projection was due to be delivered). The RBL Facility Agreement contains customary events of default including breach of financial ratios, non-payment of any amount under the finance documents, insolvency and analogous proceedings, cross-default, misrepresentation, the qualification of accounts, repudiation and effectiveness, litigation and material adverse change. There are additional events of default relating to the material project documents (which are qualified by reference to material adverse effect) and borrowing base assets. 12.1.2 Indenture Overview On 30 July 2021, IENS plc entered into an indenture among IEEPL (as guarantor) and other guarantors, BNY Mellon Corporate Trustee Services Limited (as trustee), The Bank of New York Mellon, London Branch (as principal paying agent) and The Bank of New York Mellon SA/ NV, Dublin Branch (in various capacities) (the “Indenture”). The Indenture provides for (i) the issuance of its 9% senior notes due 2026 and any additional notes issued by IENS plc under the Indenture from time to time (the “2026 Notes”), and (ii) the issuance by the guarantors (as hereinafter defined) of their respective guarantees of the 2026 Notes. The proceeds of the initial offering on 30 July 2021 were used by the Group, together with drawings under the RBL Facility Agreement, to refinance its existing borrowing base facility and existing $500 million 2024 Notes. Pursuant to the initial offering on 30 July 2021, IENS plc issued $625.0 million in aggregate principal amount of 2026 Notes. IENS plc may issue additional notes in minimum denominations of $200,000 and integral multiples of $1,000 in excess thereof under the Indenture from time to time. Listing The 2026 Notes are admitted to the Official List of The International Stock Exchange. Interest and Maturity Interest on the 2026 Notes will accrue at the rate of 9% per annum and is payable semi- annually in arrears on 15 January and 15 July. Payment of interest commenced on 15 January 2022. Interest on overdue principal and interest (if any) accrues at a rate that is 1.0% higher than the then applicable interest rate on the 2026 Notes. IENS plc will make each interest payment to the holders of record on the immediately preceding 1 January and 1 July. Interest on the 2026 Notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360 day year comprised of twelve 30-day months. The 2026 Notes will mature on 15 July 2026. Redemption The 2026 Notes are only redeemable at IENS plc’s option prior to maturity under the following circumstances: • in connection with any tender offer or other offer to purchase all of the 2026 Notes, if holders of not less than 90% of the aggregate principal amount of the then outstanding 2026 Notes validly tender and do not validly withdraw such 2026 Notes in such tender offer or offer to purchase, all of the noteholders will be deemed to have consented to such tender offer or other offer and, accordingly, IENS plc will have the right to redeem all 2026 362
Notes that remain outstanding at a price equivalent to the price paid pursuant to such tender offer or offer to purchase; and • in the event of certain changes in the law of any relevant taxing jurisdiction affecting taxation of the 2026 Notes, IENS plc may redeem the 2026 Notes in whole, but not in part, at any time upon giving prior notice, at a redemption price of 100% of the principal amount, plus accrued and unpaid interest (if any) and additional amounts (if any) due as a result of the withholding or deduction for taxes up to and including the date of redemption. IEEPL and its restricted subsidiaries may acquire or cause to be acquired, the 2026 Notes by means other than a redemption, whether pursuant to a tender offer, open market purchase or otherwise, so long as the acquisition does not violate the following terms of the Indenture: • prior to 15 July 2023, IENS plc may redeem all or part of the 2026 Notes at a redemption price equal to 100% of the principal amount of such 2026 Notes redeemed, plus accrued and unpaid interest (if any) to the redemption date plus a “make whole” premium, subject to the rights of the holders on the relevant date to receive interest due on the relevant interest payment date; • in addition, on or prior to 15 July 2023, IENS plc may redeem up to 40% of the original principal amount of each of the 2026 Notes with the net cash proceeds from specified equity offerings at a redemption price equal to 109.000% of the principal amount thereof plus accrued and unpaid interest (if any) to the redemption date, provided that at least 50% of the original principal amount of the 2026 Notes remain outstanding after the redemption; and • on or after 15 July 2023, IENS plc may on any one or more occasions redeem all or a part of the 2026 Notes at the following redemption prices (expressed as percentages of principal amount): • in 2023, at a redemption price of 104.500%; • in 2024, at a redemption price of 102.250%; or • in 2025 and thereafter, at a redemption price of 100.000%, plus accrued and unpaid interest (if any). Change of Control Under the terms of the Indenture, a “Change of Control” is deemed to have occurred if (i) all or substantially all of the properties or assets of IEEPL and its restricted subsidiaries are sold, leased or otherwise disposed of to any person other than a ‘permitted holder’ (which includes, amongst others, DGL and its Subsidiary Undertakings, and their affiliates); (ii) a plan relating to the liquidation or dissolution of IEEPL is adopted; and (iii) a person, other than a ‘permitted holder’, becomes the beneficial owner of more than 50% of the voting stock of the IEEPL. A transaction will not be deemed to involve a “Change of Control” solely as a result of IEEPL becoming a direct or indirect wholly-owned subsidiary of a holding company provided certain conditions as outlined in the Indenture are met. Upon the occurrence of a “Change of Control”, IENS plc will be required to offer to repurchase the 2026 Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest (if any) to the date of the purchase. Distributions The terms of the 2026 Notes include restrictions on the ability of IEEPL, and certain of its subsidiaries, to, directly or indirectly: • declare or pay any dividend or make any other payment or distribution (including, without limitation, in connection with any merger, amalgamation or consolidation); • repurchase (including, without limitation, in connection with any merger, amalgamation or consolidation) any equity interest in IEEPL or its parent; 363
• make any principal payment on or repurchase any indebtedness of IEEPL or any guarantor that is subordinated to the 2026 Notes (subject to certain exceptions); • make any payment on or repurchase certain shareholder debt obligations; or • make any investment not permitted under the terms of the 2026 Notes, unless at the time of, and after giving effect to, such restricted payment: • no event of default has occurred or is continuing or would occur as a consequence of such payment; • IEEPL would have been permitted to incur at least $1 of additional indebtedness pursuant to the fixed charge cover ratio test set out in the 2026 Notes and/or (for certain exceptions to the restriction on payments) the consolidated leverage ratio of IEEPL will not exceed 1.3:1; and • such payment, together with the aggregate of all other restricted payments following the issue date, is equal to or less than the sum, without duplication, of: • either: • (x) an amount equal to $100 million for each twelve months passed since 30 July 2021 or (y) where the consolidated leverage ratio is 0.6:1, 50% of the consolidated net income of IEEPL for the specified period; or • following a public equity offering of greater than 25% of the issued common stock of IEEPL, 50% of the consolidated net income of IEEPL for the specified period; plus • 100% of the aggregate net cash proceeds and fair market value of marketable securities and other property or assets received by IEEPL as a contribution to its common capital or from the issue of certain interests of IEEPL; plus • (i) to the extent any restricted investment is (x) sold, the aggregate amount received in cash and the fair market value of the marketable securities and other property received by IEEPL and certain of its subsidiaries, or (y) made in an entity that becomes a restricted subsidiary, 100% of the fair market value of the restricted investment of IEEPL and certain of its subsidiaries; plus (ii) to the extent any subsidiary not designated as restricted is subsequently re-designated as or merged with a restricted subsidiary, or all or substantially all properties or assets of such unrestricted security is transferred to IEEPL or certain of its subsidiaries which are restricted, the fair market value of the property received by IEEPL or its restricted subsidiary or the amount of restricted investment (to the extent such investment reduced the restricted payments capacity under this bullet point and were not previously repaid); plus • 100% of distributions received in cash by IEEPL or certain of its subsidiaries from a subsidiary which is not restricted, to the extent such amounts are not otherwise included in the consolidated net income of IEEPL for such period. The value of all restricted payments made will be the fair market value on the date of such payment (or declaration in the case of dividends). The restriction on payments under the terms of the 2026 Notes will not prohibit: • dividend or redemption payments which would have complied with the terms of the 2026 Notes at the date of declaration or notice; • certain payments which would otherwise be restricted but which are in exchange for certain equity or debt interests of IEEPL; • the repurchase of debt of IEEPL or any guarantor that is subordinated to the 2026 Notes if paid for using net cash proceeds from a substantially concurrent refinancing for the purpose of such repurchase; • dividend payments by a restricted subsidiary on no more than a pro rata basis; 364
• so long as no event of default has occurred and is continuing or would be caused thereby, the repurchase of IEEPL’s equity interests held by its current or former officers, directors, employees or consultants pursuant to a stock option or similar agreement, subject to certain requirements; • the repurchase of IEEPL’s equity interests held by its current or former directors or employees in connection with the vesting or any equity compensation in order to satisfy a tax withholding obligation; • repurchases of certain debt obligations subordinated to the 2026 Notes at a purchase price not greater than (i) in the event of a change of control, 101% of the principal amount and unpaid interest or (ii) in the event of an asset sale, 100% of the principal amount and unpaid interest, subject to certain additional requirements; • the repurchase of IEEPL capital stock representing fractional shares in connection with a merger or other combination or any other transaction permitted by the terms of the 2026 Notes; • the repurchase of equity interests representing a portion of the exercise price of stock options or warrants; • so long as no event of default has occurred and is continuing or would be caused thereby, regularly scheduled or accrued dividends to holders of disqualified stock of IEEPL or certain of its subsidiaries in accordance with the fixed charge coverage ratio test as set out in the terms of the 2026 Notes; • payment of cash in lieu of the issuance of fractional shares upon the exercise of options or warrants or the conversion or exchange of capital stock; • so long as no event of default has occurred and is continuing or would be caused thereby, certain advances paid to officers, directors, employees or consultants or in relation to any management equity plan or certain similar arrangements, subject to certain additional restrictions; • so long as no event of default has occurred and is continuing or would be caused thereby, repurchase of equity interests of IEEPL to be held as treasury stock not exceeding $50 million plus proceeds from the sale of such equity interests from treasury stock; • dividend payments by IEEPL to the Company to make corresponding dividend payments following the initial public offering provided that there is no continuing event of default and the aggregate amount of all such dividends does not, in a fiscal year, exceed the greater of: • 7% per annum of the net cash proceeds received by IEEPL in any public equity offering; and • the greater of: • the greater of (A) an amount equal to 5% of the market capitalisation of the Company (being the total number of ordinary shares of the Company at the date a dividend is declared multiplied by the mean closing price per ordinary share for the 30 consecutive trading days prior to that date) and (B) 5% of the IPO market capitalisation of the Company (being an amount equal to the total number of ordinary shares of the Company at the time of the initial public offering multiplied by the price per ordinary share sold in the initial public offering) pursuant to the initial public offering, provided that after giving pro forma effect to the payment of any such dividend, the consolidated leverage ratio of IEEPL would not exceed 1.05:1; and • the greater of (A) 7% of the market capitalisation of the Company or (B) 7% of the IPO market capitalisation of the Company, provided that after giving pro forma effect to the payment of any such dividend, the consolidated leverage ratio of IEEPL would not exceed 0.8:1, 365
provided that in each case, if such public equity offering was of capital stock of a parent, the net proceeds of any such dividend are used to fund a corresponding dividend in equal or greater amount on the capital stock of such parent. • so long as no event of default has occurred and is continuing or would be caused thereby, an amount not exceeding the greater of $135 million over the term of the 2026 Notes and 3.2% of the total consolidated assets of Ithaca and its subsidiaries (as shown on the most recent balance sheet); • payments in an aggregate amount not exceeding the aggregate amount of certain capital contributions; • payments related to a tax sharing agreement, subject to certain additional requirements; • distributions to any parent by IEEPL or certain of its subsidiaries in amounts not exceeding (without duplication) (a) amounts required for certain expenses of such parent, or (b) amounts constituting payments of fees and expenses in connection with certain transactions with affiliates; and • payments in connection with the offering of the 2026 Notes, the amendment and restatement of the RBL Facility Agreement and the redemption and repayment of certain existing indebtedness on or about the date of the issuance of the 2026 Notes. Any dividend payment under the 2026 Notes will be subject to the waterfall provisions in the RBL Facility Agreement and must be made no later than 30 days after a recalculation date (being 31 May and 30 November of each calendar year, or any interim recalculation date). Guarantees and Security The 2026 Notes are guaranteed by IEEPL (as senior guarantor) and those of IEEPL’s Subsidiary Undertakings (other than IENS plc) that are borrowers and guarantors under the RBL Facility Agreement (as subordinated guarantors) The 2026 Note guarantees are joint and several obligations of the guarantors. The obligations of the subordinated guarantors under the subordinated note guarantees are subordinated in right of payment to the subordinated guarantors’ obligations under the RBL Facility Agreement and may be subordinated in right of payment to the subordinated guarantors’ future senior obligations. The 2026 Note guarantee of a guarantor will be automatically and unconditionally released upon the occurrence of certain events outlined in the Indenture. The 2026 Notes are unsecured. Ranking The 2026 Notes: • constitute general obligations of IENS plc; • rank pari passu in right of payment with all existing and future obligations of IENS plc that are not expressly contractually subordinated in right of payment to the 2026 Notes; • rank senior in right of payment to all future obligations of IENS plc that are subordinated in right of payment to the 2026 Notes; • are effectively subordinated to all existing and future secured obligations of IENS plc to the extent of the value of the property and assets securing such obligations, unless such assets also secure the 2026 Notes on an equal and rateable or senior basis; • are structurally subordinated to all existing and future obligations of IEEPL’s subsidiaries that do not guarantee the 2026 Notes (other than IENS plc); and • are guaranteed on a senior basis by IEEPL and on a senior subordinated basis by the subordinated guarantors, subject to limitations under applicable law as set out in the Indenture. 366
Covenants The Indenture limits, among other things, the ability of IENS plc and its restricted subsidiaries to: • incur additional debt and issue guarantees and preferred stock; • make certain payments, including dividends and other distributions, with respect to outstanding share capital; • repay or redeem subordinated debt or share capital; • create or incur certain liens; • impose restrictions on the ability of IEEPL’s restricted subsidiaries to pay dividends or other payments to IEEPL or any of its other restricted subsidiaries; • make certain investments or loans; • sell, lease or transfer certain assets, including shares of any restricted subsidiary of IEEPL; • guarantee certain types of other indebtedness of IEEPL or its restricted subsidiaries without also guaranteeing the 2026 Notes; • expand into unrelated businesses; • merge or consolidate with other entities; and • enter into certain transactions with affiliates. Each of the covenants is subject to a number of important exceptions and qualifications. In addition, the Indenture also contains certain customary events of default. If any event of default occurs in relation to the bankruptcy or insolvency of IENS plc or IEEPL, all then outstanding 2026 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing then the trustee or holders of at least 25% in aggregate principal amount of the then outstanding 2026 Notes may declare all the then outstanding 2026 Notes to be due and payable immediately by notice in writing to IENS plc. 12.1.3 Intercreditor Arrangements In relation to the financing arrangements, there is a Bond Subordination Agreement between, amongst others, IEEPL, DGL, BNP Paribas and BNY Mellon Corporate Trustee Services Limited dated 1 November 2019 (and to which BNY Mellon Corporate Trustee Services Limited in its capacity as Trustee acceded to on 30 July 2021) which sets out the rank and priority of the relevant liabilities owed by the Group as follows: (i) first, the liabilities due under the RBL Facility Agreement and related finance documents (i.e. the senior liabilities), (ii) second, the liabilities due in respect of the 2026 Notes and related bond documents, and (iii) third, the liabilities owed to DGL. There is also a Hedging Intercreditor Agreement between, amongst others, IEEPL, BNP Paribas and IEUK dated 4 November 2019 which governs the relationship of the unsecured hedging counterparties vis a vis the finance parties in respect of the senior liabilities (including the secured hedging liabilities). Finally, there is a Subordination Agreement between, amongst others, IEUK and BNP Paribas dated 4 November 2019, which subordinates any inter-group obligations owed amongst the members of the Group to the senior liabilities. 12.1.4 Letters of Credit and Surety Bonds The Group enters into letters of credit and surety bonds principally to provide security for its decommissioning obligations. The Group has entered into a number of deeds of indemnity in respect of the surety bonds (the “Deeds of Indemnity”). These include: 367
(a) Deed of indemnity between, amongst others, IEEPL (as lead indemnitor) and HCC International Insurance Company plc (“HCCI”) dated 28 January 2021 (“HCCI Deed of Indemnity”); (b) Deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Everest Insurance (Ireland), DAC (“Everest”) dated 22 January 2022 (“Everest Deed of Indemnity”); (c) Deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Liberty Mutual Insurance Europe SE (“Liberty”) dated 26 November 2020 (“Liberty Deed of Indemnity”); (d) Deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Aspen Insurance UK Limited (“Aspen”) dated 30 November 2020 (“Aspen Deed of Indemnity”); and (e) Deed of indemnity between, amongst others, IEEPL (as lead indemnitor) and Markel International Insurance Company Limited (“MIIC”) dated 21 January 2022 (“MIIC Deed of Indemnity”). The Deeds of Indemnity all provide that, in the event of a change of control, the surety will be entitled to make demand for the payment of cash to cover a deposit in an amount equal to an amount the relevant Surety determines is the amount of the maximum aggregate liability of the surety in connection with any outstanding bond or bonds. The triggers for a change of control vary between the Deeds of Indemnity and are summarised as follows: (a) Under the HCCI Deed of Indemnity, a change of control will occur where IEEPL ceases to control (as defined in sections 449—451 of the Corporation Tax Act 2010) any other indemnitor or bond holder or where any person or group of persons (other than DGL or any subsidiary thereof) acting in concert gain control of IEEPL or other bond holder. (b) Under the Everest Deed of Indemnity and Liberty Deed of Indemnity, a change of control will occur where any person or group of persons acting in concert gain control (as defined in section 416 of the Income and Corporation Taxes Act 1988) of IEEPL. (c) Under the Aspen Deed of Indemnity, a change of control will occur where there is a change to the persons who: (i) hold the majority of voting rights in IEEPL (or any other indemnitor); or (ii) who are entitled to remove a majority of IEEPL’s (or any other indemnitor’s) board of directors. (d) Under the MIIC Deed of Indemnity, a change of control will occur where a person or group of persons acting in concert gain direct or indirect control of IEEPL by holding more than 50% of its issued share capital or a majority of the voting or director appointment rights. The notice required to be provided prior to such cash cover being due varies under the Deeds of Indemnity and is as follows: (a) Under the HCCI Deed of Indemnity, the indemnitors will pay to HCCI a sum equal to the aggregate bond amounts under all outstanding bonds within 5 business days of HCCI’s written demand. (b) Under the Everest Deed of Indemnity, the indemnitors will deposit with Everest, in cash or any other form of acceptable security, a sum equal to the face value of any guarantee then outstanding on behalf of any subsidiary of any indemnitor within 5 business days of receipt of written request from Everest. (c) Under the Liberty Deed of Indemnity, the indemnitors will deposit with Liberty, in cash or any other form of acceptable security, a sum equal to 101.5% of the face value of any guarantee then outstanding on behalf of any subsidiary of any indemnitor within 5 business days of receipt of written request from Liberty. 368
(d) Under the Aspen Deed of Indemnity, the indemnitors will deposit with Aspen an amount equal to the amount that Aspen determines, in its sole discretion, is its maximum aggregate liability in connection with the outstanding bonds, within 30 days of notice from Aspen. Under the MIIC Deed of Indemnity, the indemnitors will pay to MIIC, in cash or any other form of acceptable security, a sum equal to 101.5% of the aggregate bond amounts in respect of all outstanding bonds within 5 business days of MIIC’s written demand. The Group has the following surety bonds and letters of credit issued in respect of its decommissioning activities each issued benefitting the Law Debenture Trust Corporation P.L.C.: (a) A letter of credit of £80,163,582 issued by BNP Paribas benefitting the Law Debenture Trust Corporation P.L.C. in respect of decommissioning obligations of Alba; (b) An on demand bond of £28,912,554 issued by Aspen benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Alder; (c) An on demand bond of £8,771,000 issued by HCCI benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Anglia; (d) An on demand bond of £7,854,000 issued by Liberty benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Athena. (e) A letter of credit of £9,736,555 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Brodgar; (f) An on demand bond of £25,000,000 issued by Aspen benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Britannia; (g) A letter of credit of £83,062,170 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Britannia; (h) An on demand bond of £2,047,567 issued by Liberty benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Broom; (i) An on demand bond of £16,407,138 issued by Liberty benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Don South West & Conrie; (j) An on demand bond of £6,365,829 issued by HCCI benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Enochdhu; (k) A letter of credit of £6,489,627 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Erskine; (l) An on demand bond of £1,000,000 issued by Liberty benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Hurricane; (m) An on demand bond of £4,791,250 issued by Liberty benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Jacky; (n) A letter of credit of £4,302,574 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of West Don; (o) An on demand bond of £1,064,411 issued by HCCI benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Ythan; (p) A letter of credit of $45,000,000 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C in respect of decommissioning obligations of Elgin Franklin; and (q) A letter of credit of £359,291 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C in respect of bi-lateral decommissioning obligations of Pickerill. IEUK is seeking to increase the letter of credit utilisation capacity under the RBL Facility Agreement prior to expected admission as the letters of credit issued by BNP Paribas in respect of Brittania and Erskine are to be replaced and it is anticipated that, for a short period of time while the existing letters of credit are returned for cancellation, the utilisation exposure will exceed the capacity in the RBL Facility Agreement. The existing Britannia and Erskine letters of credit (set out above) are to be replaced by the following: 369
(r) A letter of credit of £83,062,170 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Britannia; (s) A letter of credit of £3,244,814 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Erskine; and (t) A letter of credit of £3,244,814 issued by BNP Paribas benefitting the Law Debenture Trust Corporate P.L.C. in respect of decommissioning obligations of Erskine. The Group also has a deferred payment on demand bond of $70 million issued by a surety syndicate by Liberty, HCCI, MIIC and Everest (each with a quarter liability share) in respect of its obligation to furnish the deferred consideration security pursuant to the Marubeni Acquisition Agreement. The Group has the following letters of credit issued by BNP Paribas in respect of its obligations under the Sullom Voe Terminal Tariff Agreements: (a) A letter of credit of £271,068 issued by BNP Paribas benefitting EnQuest Heather Limited in respect of obligations under the Sullom Voe Terminal Tariff Agreement for Columba B & D; and (b) A letter of credit of £115,450 issued by BNP Paribas benefitting EnQuest Heather Limited in respect of obligations under the Sullom Voe Terminal Tariff Agreement for Columba E. As at the Last Practicable Date, the Group does not have letters of credit or surety bonds in respect of its other assets. See paragraph 1.20 (The Group may face unanticipated increased or incremental costs in connection with decommissioning obligations.) of Part 1 (Risk Factors) above. 12.1.5 Hedging Arrangements The Group maintains certain commodity hedges to manage its exposure to movements in oil and gas prices. In addition, the Group holds a small portfolio of foreign exchange derivatives. In connection with these activities, the Group has entered into International Swaps and Derivatives Association master agreements (the “ISDAs”) with several hedging partners. The ISDAs have been entered into by IEUK with Deutsche Bank AG, J.P. Morgan Securities PLC, Goldman Sachs International, Britannic Energy Trading Limited, ABN AMRO Bank N.V., Royal Bank of Canada, Lloyds Bank Corporate Markets PLC, Skandinaviska Enskilda Banken AB (PUBL), BNP Paribas and Natwest Markets PLC respectively, all on 6 November 2019. These ISDAs contain change of control provisions which give rise to an event of default or a termination right in the case of (i) a merger without assumption (where a merger, transfer, reorganisation or similar results in the resulting, surviving or transferee entity failing to assume all of the obligations of the previous entity under the ISDA); (ii) a credit event upon merger (which, amongst other things, includes where any person acquires directly or indirectly an ownership interest enabling it to control the party but which results in the creditworthiness of said party becoming materially weaker) or (iii) a notification by the facility agent of a change of control under the RBL Facility Agreement (see paragraph 12.1.1 above) (save for in relation to the Goldman Sachs International and Britannic Energy Trading Limited ISDAs). Exercising of the termination rights/events of default under the ISDAs are subject to the intercreditor agreement entered into in respect of the RBL Facility Agreement and/or the prior consent of the security trustee or the majority lenders under the terms of the ISDAs. 12.1.6 SPEL Facility Agreement with, among others, Natixis Overview On 8 December 2020, SPEL signed an amendment and restatement agreement in relation to their existing borrowing base facility agreement with (1) Natixis (as Agent); (2) DNB Bank ASA, London Branch (as Security Agent); and (3) DNB (UK) Limited, ING Bank N.V., Natixis, London Branch, Natixis, ABN AMRO Bank N.V., Commonwealth Bank of Australia, Barclays Bank PLC, BNP Paribas SA, Credit Agricole Corporate and Investment Bank and Nedbank Limited (as lenders), for a $550 million senior secured borrowing base facility to, among other things, finance the acquisition of SPEEPL, for general corporate purposes and for the financing of 370
offshore asset acquisitions in the United Kingdom, Norway, Delek, the Netherlands and/or the Republic of Ireland (the “SPEL Facility Agreement”). The terms and conditions of the SPEL Facility Agreement comprises one revolving credit facility up to a total of $550 million (for the purposes of this paragraph 12.1.6 of Part 15 (Additional Information) the “SPEL Facility”). The Facility includes an accordion option for $200 million which SPEL may request by giving written notice provided there is no default continuing at such time and the notice is issued no later than 8 November 2023. The SPEL Facility may be utilised by way of loan and may be utilised in US dollars, pounds sterling or euros. Each of SPEUKL and SPEEPL are original guarantors under the SPEL Facility Agreement. Each obligor subordinates its claims against each other obligor and each guarantor jointly and severally guarantees the obligations of each obligor under the SPEL Facility Agreement and related finance documents, in each case, in favour of the lenders and other finance/hedging parties. The SPEL Facility Agreement is drafted on the basis of a customary reducing borrowing base facility arrangement whereby the maximum amount that can be drawn or outstanding will be recalculated every six months based on the value of the borrowing base assets and certain economic and financial assumptions. The borrowing base amount shall be calculated by reference to a banking case prior to each semi-annual redetermination date. The borrowing base amount, in relation to any calculation period (periods of six months), shall be the lesser of the project life cover ratio amount calculated by dividing the net present value of projected net revenues (accounting for capex add back) for the present and subsequent calculation periods by 1.5 and the loan life cover ratio amount calculated by dividing the net present value of projected net revenues (accounting for capex add back) for the present and subsequent calculation periods by 1.25. The Siccar Point Acquisition triggered the Change of Control provisions (as set out below) and, as a result, SPEL sought to prepay the outstanding facility. This was repaid in full on 30 June 2022 with all securities being released. Security The lenders benefit from first ranking English and Scots law security. The English law security includes several all-asset floating charges as well as security over all of SPEL’s and SPEEPL’s bank accounts, security over SPEL’s shares in SPEUKL and SPEEPL as well as over SPEFL shares in SPEL and the assignments of intercompany loans owed to SPEL and SPEFL. The Scots law security consists of three bonds and floating charges granted by SPEL, SPEUKL and SPEEPL respectively. Repayment and Maturity The Facility will mature on 8 November 2027 (or, if earlier, the date on which the value of the remaining reserves of all borrowing base assets are deemed to have fallen to be less than 25% of the initial approved reserve threshold). The Facility is a revolving facility and subject to semi-annual reductions in accordance with an agreed amortisation schedule. Each of the total commitments shall reduce over the life of the Facility in accordance with an agreed reduction schedule. The Facility will reduce to £495 million on 1 July 2024, $440 million on 1 January 2025, $385 million on 1 July 2025, $330 million on 1 January 2026, $275 million on 1 July 2026, $220 million on 1 January 2027 and $165 million on 1 July 2027. Fees SPEL shall pay commitment fees at the rate of 20% of the margin on the daily amount by which the total commitments exceed the borrowing base amount and 40% of the margin on the daily amount by which the borrowing base amount exceeds the amount in USD of all outstanding utilisations. 371
Interest The interest rate in respect of the drawn loans under the SPEL Facility Agreement is the sum of the margin and LIBOR (or EURIBOR if drawn in euros). The margin was 3.0% per annum for the period ending 8 November 2021 and 3.5% per annum thereafter provided that the rate will now reduce to 3.25% per annum if the Mariner field exceeds certain production projections. Interest periods in respect of the Facility will be one, three or six months or any other period agreed between SPEL and Natixis (acting on the instructions of all of the lenders in relation to the relevant loan). Prepayment and Cancellation The SPEL Facility Agreement contains prepayment and cancellation provisions customary for a facility of this type such as illegality, voluntary prepayment and a mandatory prepayment for a change of control, which shall not be triggered by an initial public offering of the shares in the Company where the ultimate change of control of the Company is less than 50%. Prepayment of a utilisation may be made on giving Natixis no less than 5 business days’ notice provided that, where a utilisation is being paid in part, it must reduce the base currency amount of the utilisation by a minimum of $5 million. Similarly, cancellation of the available Facility may be made on giving Natixis no less than five business days’ notice provided that, where the cancellation is in part, it must be for a minimum of $5 million and such cancellation would not demonstrate a funding shortfall in the most recent liquidity and funding statements. Change of Control Under the SPEL Facility Agreement, a “Change of Control” is deemed to have occurred if any person or group of persons acting in concert (other than Blackstone Energy Partners II LP, Blackstone Energy Partners (Cayman) II LP, Blackstone Energy Partners (Cayman) II F LP, Blackstone Capital Partners VI LP, Blackstone Capital Partners (Cayman II) VI LP, Blue Water Energy Fund I-A LP, Blue Water Energy Fund I LP and their affiliates) gains direct or indirect control of SPEL. The term “control” means (1) the power to cast more than 50% of the votes at a general meeting of SPE: (2) the power to appoint or remove the majority of directors of SPEL, (3) the power to give directions to the operating and financial policies of SPEL which the directors of SPEL are obliged to comply with; and (4) the holding of more than 50% of the issued share capital of SPEL. In the event of a Change of Control (or the sale of all or substantially all of the assets) the Facility shall be automatically cancelled and all outstanding utilisations, together with accrued interests, shall be immediately due and payable. Dividends The obligors are generally prohibited from making any distributions including dividend payments. This, however, is subject to certain exceptions including: (1) where a distribution is made 18 months after the date of the SPEL Facility Agreement, provided such distribution is made within 20 days of a recalculation date and the amount of the distribution has been taken into account in the most recent liquidity statement and funding statement, no default is continuing and no funding shortfall is continuing; (2) where a distribution is made in and among the obligors; (3) where a distribution is made with the prior approval of the majority lenders; and (4) where a distribution is made to a subordinated debt issuer in compliance with the terms of an inter-company loan subordination agreement. The right to make a distribution falls at the end of the proceeds account waterfall. This contains the usual requirements to pay various items first including fees due under the finance documents, costs and expenses, hedging costs, accrued interests and gross expenditure. Covenant Package The SPEL Facility Agreement contains customary representations, including as to status, binding obligations, non-conflict with other obligations, power and authority, insolvency, tax, the banking case, existence of project documents, environmental compliance, title to field interests, 372
the accuracy of information, anti-corruption and sanctions and in certain cases are subject to knowledge and materiality qualifications. The SPEL Facility Agreement imposes a number of positive and negative covenants on the obligors. Positive covenants include compliance with, among other things, environmental matters, applicable laws (including sanctions) and tax rules and with its obligations under its licences, maintenance of certain bank accounts, insurance policies and project documents. The SPEL Facility Agreement also contains negative covenants, including, among other things, a negative pledge and restrictions (subject to, where appropriate, agreed exceptions) on distributions (as set out above), additional financial indebtedness, disposals, acquisitions, mergers, and changes in the entities’ business, its constitutional documents or certain project documents. The SPEL Facility Agreement contains customary events of default including breach of non- payment of any amount under the finance documents, insolvency, a funding shortfall, cross- default, misrepresentation, change of ownership, cessation of business, repudiation and recission of agreements, litigation and material adverse change. There are additional events of default relating to the material project documents (which are qualified by reference to material adverse effect) and borrowing base assets. 12.1.7 Siccar Point Bonds Overview SPEB issued a series of senior unsecured callable bonds up to a maximum of $200 million (“Siccar Point Bonds”) on 4 March 2021 pursuant to terms and conditions dated 2 March 2021 entered into with Nordic Trustee AS (as bond trustee). The Siccar Point Bonds rank pari passu between themselves and will at least rank pari passu with all other obligations of SPEB (save for those claims which are preferred by bankruptcy, insolvency, liquidation or similar). Following completion of the Siccar Point Acquisition on 30 June 2022, SPEB issued a put option notice to Nordic Trustee AS pursuant to the change of control provisions detailed below. Bondholders holding Siccar Point Bonds totalling $166.4 million elected to exercise the put provision and require repayment at a price of 101% of the nominal amount of such bonds. The repayment was settled on 1 August 2022. Subsequently, on 22 September 2022, Siccar Point Bonds totalling $25.6 million were redeemed at a premium of c.6% on behalf of SPEB. On 12 October 2022, the remaining Siccar Point Bonds totalling $8 million were redeemed at the make-whole amount of 105.4%. Security Each of SPEL, SPEUKL, SPEEPL and SPEFL are the original guarantors under the Siccar Point Bonds’ terms and conditions and have provided Norwegian law guarantees in favour of Nordic Trustee AS. Each of the guarantees (other than the guarantee granted by SPEFL) is subordinated to the SPEL Facility Agreement. Redemption and maturity Payments in relation to the Siccar Point Bonds are made on each payment date, being 4 March and 4 September of every year. Interest on any overdue amounts will accrue at the coupon rate (i.e. 9%) plus 3%. The Siccar Point Bonds have a maturity date of 4 March 2026 and must be redeemed by SPEB on such date for 100% of their nominal amount. SPEB may redeem all of the outstanding Siccar Point Bonds by written notice to Nordic Trustee AS (and bondholders) at least 10 business days, but no more than 20 business days, prior to the intended repayment date. The redemption amount payable will differ depending on the period during which the notice is issued: (1) if the Siccar Point Bonds are redeemed prior to 3 March 2023, then a price equal to the sum of the present value on the prepayment date of 105.4% of the nominal amount of the redeemed Siccar Point Bonds and the remaining interest payment in respect of the redeemed Siccar Point Bonds to 3 March 2023 will be payable; (2) if the Siccar Point Bonds are redeemed between 4 March 2023 and 3 March 2024, a price of 105.4% of the 373
nominal amount for each redeemed bond will be payable; (3) if the Siccar Point Bonds are redeemed between 4 March 2024 and 3 March 2025, a price of 103.6% of the nominal amount of each redeemed bond will be payable; and (4) if the Siccar Point Bonds are redeemed between 4 March 2025 and 4 March 2026, a price of 101.8% of the nominal amount of each redeemed bond will be payable. In addition, SPEB is entitled to redeem all of the outstanding Siccar Point Bonds at a price of 100% of the nominal amount if it is or will be required to gross up any withheld tax imposed by law from any payment in respect of the Siccar Point Bonds as result of a change in applicable implemented after the date of the Siccar Point Bonds’ terms and conditions. Interest The Siccar Point Bonds accrue interest at the rate of 9% per annum. The interest periods are the periods between 4 March and 4 September and 4 September and 4 March each year, with the interest payable at the end of each interest period. Change of Control Under the Siccar Point Bonds’ terms and conditions, a “Change of Control Event” is deemed to have occurred if a person or group of persons (other than Blackstone Group Inc., Blue Water Energy LLP and their affiliates) acting in concert gain decisive influence (i.e. having a direct or indirect majority of the voting rights or a right to elect or remove a majority of the directors in that other person) over SPEB, SPEL or SPEFL. If a Change of Control Event occurs then each bondholder is entitled to require that SPEB purchases all or some of its Siccar Point Bonds at a price of 101% of the nominal amount of such bonds. If Siccar Point Bonds representing more than 90% of the outstanding Siccar Point Bonds have been purchased as a result of a Change of Control Event then SPEB is entitled to repurchase all the remaining outstanding Siccar Point Bonds at a price of 101% of the nominal amount. Dividends In order for SPEL to make distributions (including dividends) and incur further financial indebtedness the net interest bearing debt to EBITDAX ratio must be 3.0x or less (the “Incurrence Test”) with such calculation being made no earlier than one month prior to the relevant event. In addition to the Incurrence Test not being met, SPEL is prohibited from making any distribution (including dividends) if: (1) liquidity is less than $35 million; (2) the aggregate amount of all distributions in the relevant year exceeds 50% of the group’s consolidated net profit for the previous financial year; or (3) there is a continuing event of default. SPEL is required to ensure that its group companies do not make any distributions other than to SPEL. SPEB is required to ensure that SPEFL does not make any distributions while an event of default is continuing. Covenant package SPEL is required to ensure that at all times the group maintains liquidity of at least $15 million with such covenant being tested on 30 June and 31 December of each year. More generally, the Siccar Point Bonds’ terms and conditions contain a number of positive and negative covenants which apply to both SPEB and SPEL. Positive covenants include compliance with applicable laws and conducting all business transactions on market terms. The negative covenants include a negative pledge and restrictions (subject to, where appropriate, agreed exceptions) on distributions, additional financial indebtedness, disposals, mergers, and changes in the entities’ business. The Siccar Point Bonds’ terms and conditions contain customary events of default which, if applicable, will entitle Nordic Trustee AS to declare that all or part of the outstanding Siccar Point Bonds together with accrued interest are payable. The events of default include non- payment of amounts due, misrepresentation, cross-default and insolvency. 374
12.2 Capital Note On 4 November 2019, the Company (as borrower) and DKL Energy (as lender) entered into a $392.0 million capital note agreement (“Capital Note Agreement”) pursuant to which the Company issued a note in aggregate principal amount of $392.0 million to DKL Energy (the “Capital Note”). The Capital Note was originally subordinated against a $200.0 million facility agreement, dated 4 November 2019, among DKL Energy, the Company and BNP Paribas (the “BNPP Facility Agreement”), which was discharged on 18 June 2021. The Capital Note does not bear interest and is not linked to the consumer price index. On 2 October 2022, the Capital Note Agreement was amended to provide that repayment of the Capital Note would not occur prior to 1 January 2024 unless from the proceeds of an initial public offering of the Company (in which case, repayment is permitted on notice). The Capital Note Agreement is governed by English law. The expectation of both the Company and DKL Energy is that the Capital Note will be repaid by the Company (on notice to DKL Energy) using the proceeds of an initial public offering in the event of any admission . Following such repayment, DKL Energy would provide a confirmation that such payment is in full and final settlement of any amounts due or payable by the Company in respect of the Capital Notes. 12.3 Tracker Loan On 4 November 2019, the Company (as borrower) and DKL Energy (as lender) entered into a $198,000,000 intercompany loan agreement (“Tracker Loan”). The Tracker Loan was put in place as part of the agreed equity funding of the Chevron Acquisition. The Tracker Loan was originally subordinated against the BNPP Facility Agreement, which was discharged on 18 June 2021. The interest payable by the Company to DKL Energy under the Tracker Loan matched the interest payable pursuant to the BNPP Facility Agreement until 4 May 2021, following which the Tracker Loan became interest free. The rate of interest on the BNPP Facility Agreement for each interest period (each being a 3 month period) was the aggregate of (1) (i) from and including the utilisation date to but excluding the 27 August 2020, 6.5% per annum; (ii) from and including the 27 August 2020 to and including the 12 months anniversary of the utilisation date, 8.5% per annum; (iii) from but excluding the 12 month anniversary of the utilisation date to and including the 15 month anniversary of the utilisation date, 11% per annum; and (iv) from the date following the 15 month anniversary of the utilisation date, 11.5% per annum; and (2) LIBOR. An interest period was not to extend beyond 4 May 2021. On 3 October 2022, the Tracker Loan was amended to provide that repayment of the Tracker Loan would not occur prior to 1 January 2024 unless from the proceeds of an initial public offering of the Company (in which case, repayment is permitted on notice). As at 30 June 2022, the principal and interest outstanding under the Tracker Loan was $77.3 million. The expectation of both the Company and DKL Energy is that all amounts outstanding under the Tracker Loan would be repaid by the Company (on notice to DKL Energy) using the proceeds of an initial public offering in the event of any admission. Following such repayment, DKL Energy would provide a confirmation that such payment is in full and final settlement of any amounts due or payable by the Company in respect of the Tracker Loan. 12.4 Subordinated Shareholder Loan IEEPL (as borrower), IEUK and DGL (as lender) entered into a $250 million unsecured term loan facility on 4 November 2019 (the “Subordinated Delek Loan”). The loan is subordinated against the RBL Facility Agreement and the Indenture. Interest accrues on the loan at a rate of 4.75% per annum. IEEPL is permitted to prepay the loan provided it is in compliance with the terms of the RBL Facility Agreement and the Indenture and the amount of such prepayment is limited to an amount which IEEPL could use to make an equity distribution or a purchase or redemption of its issued share capital. The loan will mature on 15 November 2025. On 3 August 2021, the Group repaid the outstanding principal. As at 30 June 2022, $28.9 million of accrued interest remained outstanding. On 4 October 2022, the Group repaid in aggregate $29.5 million of 375
accrued and outstanding interest under, and costs payable in connection with, the Subordinated Delek Loan, thereby retiring the loan. 12.5 Mitsui Acquisition Agreement Mitsui and IOG entered into the Mitsui Acquisition Agreement on 17 September 2021 pursuant to which IOG agreed, on the terms and subject to the conditions of the Mitsui Acquisition Agreement to acquire a 13.3% participating interest in UKCS Petroleum Production Licence No. P.213 Block 16/26, Area A—Alba Field Area (the “Mitsui Interests”) from Mitsui. Completion under the Mitsui Acquisition Agreement was conditional on certain conditions precedent, including NSTA consent to the transfer of the Mitsui Interests. The conditions precedent were satisfied and the Mitsui Acquisition completed on 30 November 2021. By way of the Mitsui Acquisition, IOG acquired a 13.3% additional interest in the Alba field taking its total interest in the Alba field to 36.7%. The total consideration for the transfer of the Mitsui Interests was the payment by Mitsui to IOG, following adjustment, of $56.4 million. Pursuant to the terms of the Mitsui Acquisition Agreement, IOG has indemnified Mitsui for certain decommissioning and environmental liabilities relating to any of the Mitsui Interests acquired by IOG, irrespective of when such liabilities are or were incurred. The Mitsui Acquisition Agreement contains a number of warranties given by Mitsui in favour of IOG in relation to the Mitsui Interests. Pursuant to the terms of the Mitsui Acquisition Agreement, IEEPL and Mitsui & Co., Ltd, as the respective parent companies of IOG and Mitsui, entered into deeds of guarantee and indemnity. IEEPL agreed to guarantee to Mitsui (i) the due and punctual payment to Mitsui by IOG of all amounts which IOG is or shall become obliged to pay to Mitsui and (ii) the due and punctual performance by IOG of all other terms, covenants, stipulations and obligations in the Mitsui Acquisition Agreement. Mitsui & Co., Ltd agreed to give an equivalent guarantee to IOG in respect of payments and obligations of Mitsui. 12.6 Marubeni Acquisition Agreement IEEPL (as guarantor), IEUK and MNSL entered into the Marubeni Acquisition Agreement on 2 November 2021 pursuant to which IEUK agreed, on the terms and subject to the conditions of the Marubeni Acquisition Agreement, to acquire the issued share capital of MOGL from MNSL. Completion under the Marubeni Acquisition Agreement was conditional on certain conditions precedent, including NSTA approval of the transaction. The conditions precedent were satisfied and the Marubeni Acquisition completed on 4 February 2022. By way of the Marubeni Acquisition, IEUK acquired MOGL’s entire interest in the Marubeni Assets. IEUK paid a $7 million deposit on signing of the Marubeni Acquisition Agreement and, on completion, taking into account interim period adjustments, MNSL paid IEUK the sum of $70 million. In addition, IEUK has agreed to pay a further $70 million in cash on 1 July 2025. IEUK has also agreed to pay further contingent consideration in cash of up to a maximum amount of $255 million consisting of: (i) $75 million following certain cumulative production volumes in relation to Montrose; (ii) $27 million following certain cumulative production volumes in relation to Arbroath wells; (iii) $43 million following certain cumulative production volumes in relation to a certain well at Shaw; (iv) $25 million in connection with commercial discovery from the Vigne exploration well; (v) $25 million in connection with the tie-back of Birgitta; (vi) $15 million following certain cumulative production volumes in relation to a certain well at Shaw; (vii) $15 million following certain cumulative production volumes in relation to a certain well at Cayley; (viii) up to $30 million, dependent on realised oil prices, in connection with sales volumes from the MonArb and Columba fields during the calendar years 2022 to 2024; and (ix) 20% of revenue above a price of $65/BBL capped at $30 million in total over the years 2023 to 2024. Pursuant to the terms of the Marubeni Acquisition Agreement, IEUK has indemnified MNSL for certain decommissioning and environmental liabilities relating to the entities acquired by IEUK, irrespective of when such liabilities are or were incurred. IEUK’s obligations under the Marubeni Acquisition Agreement are guaranteed by IEEPL. 376
The Marubeni Acquisition Agreement contains a number of warranties given by MNSL in favour of IEUK in relation to MOGL and the Marubeni Assets. 12.7 Summit Acquisition Agreement IEEPL (as guarantor), IEUK and Sumitomo entered into the Summit Acquisition Agreement on 28 February 2022 pursuant to which IEUK agreed, on the terms and subject to the conditions of the Summit Acquisition Agreement, to acquire the issued share capital of Summit from Sumitomo. Completion under the Summit Acquisition Agreement was conditional on certain conditions precedent, including approval of the transaction by the NSTA and the Ministry of Economic, Trade and Industry of Japan. The conditions precedent were satisfied and the Summit Acquisition completed on 30 June 2022. By way of the Summit Acquisition, IEUK acquired Summit’s entire interest in the Summit Assets. IEUK paid a $10 million deposit on signing of the Summit Acquisition Agreement and total cash consideration on completion, following interim period adjustments, of approximately $109 million. The cash consideration was funded through a combination of the RBL Facility and existing cash resources of IEUK. Pursuant to the terms of the Summit Acquisition Agreement, IEUK has indemnified Sumitomo for certain decommissioning and environmental liabilities relating to the entities acquired by IEUK, irrespective of when such liabilities are or were incurred. IEUK’s obligations under the Summit Acquisition Agreement are guaranteed by IEEPL. The Summit Acquisition Agreement contains a number of warranties given by Sumitomo in favour of IEUK in relation to Summit and the Summit Assets. The agreement also contains certain indemnities given by Sumitomo in favour of IEUK, including in respect of liabilities deriving from certain out-of-scope assets which were terminated or transferred out of Summit prior to completion of the Summit Acquisition. 12.8 Siccar Point Acquisition Agreement IEEPL (as guarantor), IEUK and the Siccar Point Seller entered into the Siccar Point Acquisition Agreement on 7 April 2022 pursuant to which IEUK agreed, on the terms and subject to the conditions of the Siccar Point Acquisition Agreement, to acquire the issued share capital of SPEHL and certain loan notes issued by SPEFL from the Siccar Point Seller. Completion under the Siccar Point Acquisition Agreement was conditional on certain conditions precedent, including NSTA approval of the transaction. The conditions precedent were satisfied and the Siccar Point Acquisition completed on 30 June 2022. By way of the Siccar Point Acquisition, IEUK acquired SPEHL’s entire interest in the Siccar Point Assets. The total cash consideration paid by IEUK on completion in respect of the Siccar Point Acquisition, following adjustment, was $1.015 billion (of which approximately $688 million was paid to the Siccar Point Seller and approximately $278 million was in repayment of an existing lending facility). The cash consideration was funded through a combination of the RBL Facility and existing cash resources of IEUK. In addition, IEUK has agreed to pay in cash a further $1.5/BBL of total Rosebank and Cambo P50 reserves in the respective FDPs (up to a maximum of $300 million aggregate) in connection with final investment decisions being taken in respect of the Cambo field and the Rosebank field, with 50% payable at the end of 2024. Shell’s share for Cambo FID of $50 million is expected to be received at Cambo FID. IEUK has also agreed to pay up to a further $60 million quarterly in cash, dependent on realised commodity prices, in connection with sales volumes from the Siccar Point Assets over the calendar years 2023 to 2025. The commodity prices will be based on the higher of (i) 50% of sales volumes multiplied by excess Brent price minus hedging losses and (ii) zero, with floor prices set at $85/BBL (2023), $80/BBL (2024) and $75/BBL (2025). Pursuant to the terms of the Siccar Point Acquisition Agreement, IEUK has indemnified the Siccar Point Seller for certain decommissioning and environmental liabilities relating to the entities acquired by IEUK, irrespective of when such liabilities are or were incurred. IEUK’s obligations under the Siccar Point Acquisition Agreement are guaranteed by IEEPL. 377
Simultaneous with entry into the Siccar Point Acquisition Agreement, IEUK and certain managers of SPEHL entered into a warranty deed which contained certain warranties given by such managers in favour of IEUK in relation to SPEHL and the Siccar Point Assets. 12.9 Kemira Contract for the provision of liquid polymer and associated services IOG and Kemira entered into the Kemira Contract on 17 June 2016 pursuant to which Kemira shall provide certain services and products in connection with provision of liquid polymer. There is an agreed pricing formula (as revised by the parties on 1 January 2021) and IOG has 30 days following receipt of an invoice to make payment to Kemira for the relevant work order. The relationship between IOG and Kemira is non-exclusive and will expire on 31 December 2027 (unless mutually agreed otherwise). Pursuant to the Kemira Contract, IOG can terminate the Kemira Contract, any work order or any part of the work undertaken by Kemira without cause at any time by giving Kemira at least 30 days’ notice. IOG shall pay Kemira (i) for the work performed and the portion of the work in manufacturing process and (ii) any reasonable documented expenses incurred in respect of any portion of the work not yet put into the manufacturing process less any amount that Kemira is able to avoid, mitigate or recover from another source provided such payments will not exceed the agreed purchase agreement under the Kemira Contract. Pursuant to the Kemira Contract, the parties agree to indemnify and hold each other harmless in respect of certain losses under the Kemira Contract and other consequential or indirect losses arising out of the Kemira Contract. Subject to certain exceptions, Kemira’s total liability to IOG arising out of or related to its performance of the work is limited to the purchase price of the relevant product. 12.10 Chevron Acquisition Documents 12.10.1 Chevron Acquisition Agreement IEUK entered into the Chevron Acquisition Agreement with CNSHL on 29 May 2019. The exercise of the put and call option under the Chevron Acquisition Agreement was conditional on a number of conditions precedent, including OGA approval of the transaction and completion by CNSHL of an internal restructuring in order to extract certain out-of-scope assets and liabilities from CNSL prior to completion. The conditions were satisfied and the Chevron Acquisition completed on 8 November 2019. The total cash consideration paid by IEUK in respect of the Chevron Acquisition, following adjustment and including a $200 million deposit paid on signing of the CSNL Acquisition Agreement, was $1.727 billion. The cash consideration was funded through a combination of the RBL Facility, the proceeds of the 2024 Notes, equity funds advanced to the Group from holding companies of the Company (see paragraphs 12.3.8, 12.3.9 and 12.4 above) and existing cash resources of IEUK. As part of the consideration for the Chevron Acquisition, IEUK also assumed CNSHL’s obligation to make repayment to CNSL in respect of certain intra-group debts (see paragraph 12.10.3 below). By way of the Chevron Acquisition, IEUK acquired CNSL’s entire interest in the Chevron Acquired Assets. In addition, certain historic interests—being the Retained Decommissioning Liability Fields—have remained in CNSL under IEUK’s ownership in accordance with the terms of the Chevron Acquisition Agreement, as described in paragraph 12.10.2 below. The Chevron Acquisition Agreement contains a number of warranties given by CNSHL in favour of IEUK in relation to CNSL and the Chevron Acquired Assets. The agreement also contains certain indemnities given by CNSHL in favour of IEUK, including in respect of any liabilities deriving from out-of-scope assets which were transferred out of CNSL prior to completion of the Chevron Acquisition (as described above) as well as the Retained Decommissioning Liability Arrangements which are summarised in paragraph 12.10.2 below. CNSHL’s obligations under the Chevron Acquisition Agreement are guaranteed by a parent entity of substance within CNSHL’s group. 378
IEEPL provided a parent company guarantee on 29 May 2019 in favour of CNSHL pursuant to the Chevron Acquisition Agreement. Under this guarantee, IEEPL is prohibited from merging or consolidating without CNSHL’s consent (such consent not to be unreasonably withheld) except for any merger carried out as part of an IPO of the shares in IEEPL or one of its holding companies where, after such merger and IPO, DGL holds directly or indirectly 50% or more of the issued share capital or otherwise retains control of IEEPL and such merger does not prejudice IEEPL’s ability to discharge the guaranteed obligations under the parent company guarantee. 12.10.2 Retained Decommissioning Liability Arrangements As part of the Chevron Acquisition, CNSL retained the obligations which had been put in place in respect of (1) Heather; (2) Strathspey; and (3) Cambo (the “Retained Decommissioning Liability Arrangements”), notwithstanding the fact that these fields (the “Retained Decommissioning Liability Fields”) will generate no value for CNSL (now IOG). Under the Chevron Acquisition Agreement, CNSHL undertakes to: (a) provide the decommissioning security required to be provided to the counter-party by IOG under each of the Retained Decommissioning Liability Arrangements; and (b) pay the IOG share of the costs of decommissioning each of the Retained Decommissioning Liability Fields to IOG. IOG will pre-fund such costs (to be reimbursed by CNSHL) up to $5 million, with any decommissioning payments over $5 million to be transferred by CNSHL to IOG prior to the date for payment. CNSHL’s obligations under the Chevron Acquisition Agreement are guaranteed by a parent entity of substance within CNSHL’s group. If the relevant decommissioning costs are increased as a result of IEUK breaching certain material obligations in the Chevron Acquisition Agreement or IEUK’s ‘wilful misconduct’ (the “Buyer Liabilities”), CNSHL shall not be obliged to: (i) provide security; or (ii) pay, for such increased costs. CNSHL provides IEUK with an uncapped decommissioning indemnity in respect of the Retained Decommissioning Liability Fields and for any costs / losses that IOG or IEUK or its affiliates incurs as a result of CNSHL not providing the security or paying the sums required for decommissioning costs in time. Conversely, IEUK provides a counter-indemnity for: (a) any increase in liabilities as a result of IOG voluntarily acquiring additional interest in a Retained Decommissioning Liability Field or transferring any interest to another member of the IEUK group; and (b) the Buyer Liabilities. A short overview of each of the Retained Decommissioning Liability Arrangements is included below for completeness: (a) Heather Retained Decommissioning Liability Arrangements CNSL (now IOG) transferred its entire interest in Heather to (now) EnQuest Heather Limited but retained liability for paying its share of the decommissioning costs of the existing Heather facilities. IOG remains a party to the joint operating agreement to the extent of decisions related to decommissioning only. As noted under 12.10.1, CNSHL will provide the required security and pay such decommissioning costs, subject to the terms of the Chevron Acquisition Agreement. (b) Strathspey Retained Decommissioning Liability Arrangements CNSL (now IOG) transferred its entire interest in Strathspey to CNR International (U.K.) Limited but retained liability for paying decommissioning costs related to the transferred interest up to a cap. As noted under 12.10.1, CNSHL will provide the required security and pay such decommissioning costs, subject to the terms of the Chevron Acquisition Agreement. (c) Cambo exploration well Retained Decommissioning Liability Arrangements CNSL (now IOG) withdrew from the Cambo field and transferred its entire interest to SPEEPL, but retained liability for paying decommissioning costs related to the transferred interest if abandonment of the Cambo well occurs by 11 May 2022. As noted under paragraph 12.10.1, CNSHL will provide the required security and pay such decommissioning costs, subject to the terms of the Chevron Acquisition Agreement. The Company understands that abandonment of the Cambo well did not occur by 11 May 2022. 379
12.10.3 Debts owed by IEUK to CNSL (now IOG) (a) Pre-Chevron Acquisition Restructuring Loan As part of the extraction of the out-of-scope asset and liabilities from CNSL to CNSHL prior to completion of the Chevron Acquisition (as described in paragraph 12.10.1 above), a loan was put in place between CNSHL and CNSL (the “Pre-Chevron Acquisition Restructuring Loan”). The Pre-Chevron Acquisition Restructuring Loan, which is the form of a non-interest- bearing loan note originally issued by CNSHL in favour of CNSL, represented the consideration owed by CNSHL to CNSL in respect of the transfer of such assets and liabilities. CNSHL’s obligations in respect of the Pre-Chevron Acquisition Restructuring Loan (including the obligation to make repayment in respect of such loan) were novated to IEUK on 8 November 2019 as part of completion of the Chevron Acquisition. The amount outstanding in respect of the Pre-Chevron Acquisition Restructuring Loan is £331,978,471. (b) Pre-Chevron Acquisition Cash Extraction Loan Prior to completion of the Chevron Acquisition (and in accordance with the Chevron Acquisition Agreement), certain cash sums were extracted from CNSL and transferred to CNSHL by way of an upstream loan (the “Pre-Chevron Acquisition Cash Extraction Loan”). The Pre- Chevron Acquisition Cash Extraction Loan is in the form of a non-interest-bearing intra-group term loan originally entered into between CNSL (as lender) and CNSHL (as borrower). CNSHL’s obligations in respect of the Pre-Chevron Acquisition Cash Extraction Loan (including the obligation to make repayment in respect of such loan) were novated to IEUK on 8 November 2019 as part of completion of the Chevron Acquisition. The amount of principal outstanding in respect of the Pre- Chevron Acquisition Cash Extraction Loan is $510 million as at 30 June 2022. 12.10.4 Captain IP Licence Pursuant to the terms of an intellectual property licence between CNSHL (as licensor) and IEUK (as licensee) (as successor to CNSL (now IOG) following the transfer of the operations in respect of the Captain field to IEUK on 6 January 2020) dated 8 November 2019 (the “Captain IP Licence”), CNSHL granted to IOG a non-exclusive, royalty-free and sub-licensable licence to use certain intellectual property in the area of the Captain field. The purpose of the Captain IP Licence is to allow IOG to continue exploration and production operations in the Captain field after closing of the Chevron Acquisition Agreement, which is essential for the ongoing Captain EOR (see Part 4 (Business Overview)). The licensed intellectual property includes UK patents resulting from patent applications pertaining to (i) polymer flooding enhanced oil recovery; (ii) surfactant stimulation; and (iii) produced polymer patents for chemical treatment and heat exchange coating, and certain know how relating to use in the area of the Captain field. CNSHL makes no warranties and disclaims all liabilities in respect of the licensed intellectual property. IOG will indemnify CNSHL if it suffers any loss in connection with IOG’s exercise of rights under the Captain IP Licence, use by a third party of the licensed intellectual property disclosed to them by IOG, any breach by IOG of the terms of the Captain IP Licence and third-party claims. The Captain IP Licence will continue until the cessation of production from the Captain field, unless terminated by CNSHL sooner in accordance with the terms of the Captain IP Licence. 12.10.5 Master IP Licence Pursuant to the terms of a master licence agreement between Chevron USA. Inc (as licensor) and IOG and IEUK (the “Licensees”) dated 8 November 2019 (the “Master Licence Agreement”), Chevron USA has agreed to licence certain valuable and proprietary information and materials that can be used in planning, constructing, operating, maintaining and managing the Interests (as defined in the Chevron Acquisition Agreement) solely for the purposes of allowing the Licensees to continue exploration and production operations within the Interests after closing of the Chevron Acquisition Agreement. Each non-exclusive, royalty-free licence to use certain materials and processes is granted pursuant to, and governed by the terms of, 380
individual Process Licence Agreements to be entered into between Chevron USA and the Licensees in accordance with the Master Licence Agreement. Other than warranting that it has the right to grant such licences, Chevron USA makes no warranties and disclaims all liabilities in respect of the materials and processes. Subject to certain exceptions, the Licensees will indemnify Chevron USA if it suffers any loss in connection with the Licensees’ exercise of rights under the Master Licence Agreement and any Process Licence Agreements, use by a third party of the materials and processes disclosed to them by the Licensees, any breach by the Licensees of the terms of the Master Licence Agreement and third-party claims. The Master Licence Agreement will continue until the cessation of production from all of the Interests, unless terminated by Chevron USA. sooner in accordance with the terms of the Master Licence Agreement. Each individual Process Licence Agreement has an expiry date specified within its terms. 12.11 Technip Contract for the provision of pipelay and subsea construction services (including flexible and umbilical supply) for the Captain EOR II IEUK and Technip have entered into the Technip Contract which was signed on 29 April 2021 and 4 May 2021, pursuant to which Technip will perform pipelay and subsea construction services (including flexible and umbilical supply) in relation to the Captain EOR II. The Technip Contract incorporates a schedule of rates and prices which apply to the work. Technip is to be remunerated on a milestone payment basis. IEUK is obliged to make payment of Technip’s invoices within 30 days of receipt. The scheduled completion date for completion of all of the work under the Technip Contract is 1 March 2024. IEUK has the right to terminate the Technip Contract for its convenience on notice to Technip. In the event of such termination, IEUK is obliged to make payment of a cancellation payment to Technip provided that Technip is progressing the work in accordance with the schedule set out in the Technip Contract. Any amounts already paid to Technip by IEUK as part of the milestone payment structure are to be deducted from the cancellation payment. IEUK also has express rights to terminate the Technip Contract in response to any material default on the part of Technip and also if Technip becomes subject to specified insolvency events. The parties have both agreed to indemnify and hold each other harmless in relation to specified risks (including consequential and indirect losses). The Technip Contract incorporates various financial caps on Technip’s liability. 12.12 Management Services Agreement On 24 August 2021, DKL Investments and IEUK entered into an agreement for the provision of professional, directorial, financial administrative, business initiation and advisory services provided by DKL Investments to IEUK and its subsidiaries (the “Management Services Agreement”). Pursuant to the terms of the Management Services Agreement, DKL Investments is entitled to an annual fee for the services provided to IEUK. The Management Services Agreement was deemed to take effect from on 1 January 2021 and continue until terminated by either party on not less than thirty (30) days‘ written notice. It is expected that in the event of any admission of the Company to the London Stock Exchange, DKL Investments and IEUK will enter into a deed of termination with respect to the Management Services Agreement and the Management Services Agreement will terminate with immediate effect upon execution of such deed of termination. 13. SIGNIFICANT CHANGE There has been no significant change in either the financial performance or financial position of the Group since 30 June 2022, being the end of the last financial period for which the historical financial information in Part 13 (Historical Financial Information) relating to the Group was published. 381
14. LEGAL AND ARBITRATION PROCEEDINGS There are no governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) during the 12 months preceding the date of this Registration Document, which may have, or have had in the recent past, significant effects on the Company’s and/or the Group’s financial position or profitability, save as described in this paragraph 14 (Legal and Arbitration Proceedings) of Part 15 (Additional Information). IEEPL and the Group’s former CEO, Les Thomas, are party to a securities class action lawsuit under the Alberta Securities Act. Initiated in May 2015, the class action alleges that IEEPL published documents and made certain statements containing misrepresentations regarding the FPF-1 floating production facility and the then-development of the Greater Stella Area. On 7 March 2019, the plaintiff’s application for leave to commence a secondary market claim under the Alberta Securities Act and for certification of such claim as a class action was heard by the Court of Queen’s Bench of Alberta. On 24 June 2019, a judgment was issued by the court granting leave to proceed with the claim for a reduced claim period. The dispute remains ongoing, and the Company does not anticipate a trial on the merits to occur until late 2024 or 2025, following mediation expected in 2023 due to Alberta being a mandatory mediation jurisdiction. The Plaintiff’s counsel has estimated its damages to be approximately C$30 million (Canadian dollars). However, given the uncertainty of litigation, the preliminary stage of the case, and the legal standards that must be met for, among other things, class certification and success on the merits, the Company cannot estimate the reasonably possible loss or range of loss that may result from this action. IEEPL disputes these claims and intends to defend the matter vigorously. On 15 May 2020, Greenpeace Limited appealed to the Court of Session against the decisions of the Secretary of State to agree to the grant of consent for the Vorlich field development and of the decision of the NSTA to grant consent to BP Exploration Operating Company Limited (then operator of the Vorlich field) for the Vorlich field development. Greenpeace Limited sought an order quashing the decisions of the Secretary of State and the NSTA in respect of the Vorlich field development and their judicial costs. The appeal was unsuccessful. Following a hearing in September 2021 the Inner House of the Court of Session refused Greenpeace Limited’s appeal on 7 October 2021. Greenpeace Limited sought permission to appeal the Inner House of the Court of Session’s decision to the Supreme Court of the United Kingdom. Permission to appeal was refused by the Inner House of the Court of Session on 14 January 2022 and by the Supreme Court of the United Kingdom on 25 August 2022. (Greenpeace Limited having sought said permission directly). IEUK, as a partner in the Vorlich field, was an interested party in relation to the Court of Session proceedings. As the permission to appeal has been refused, the appeal process comes to an end and the consents remain unaffected. On 29 April 2021, IEUK commenced formal arbitration proceedings against CNSHL. The arbitration is seated in London, UK, governed by the Arbitration Act 1996, and is being conducted under the UNCITRAL Rules. IEUK has brought the claims in relation to CNSHL’s alleged misrepresentations and breach of certain provisions of the Chevron Acquisition Agreement in respect of the condition of the Alba floating storage unit. Given the ongoing nature of the proceedings and the possibility of different outcomes, the Group has not made any provision in the Group’s accounts in respect of this matter. Whilst the quantum of the damages is subject to expert evidence that is yet to be finalised, it is IEUK’s reasonable expectation that, if it is successful in the proceedings, the level of damages recovered will be material. IEUK is not aware of any reason why the counterparty to the arbitration would be unable to satisfy any award. CNSHL has not brought any counterclaims against IEUK, and IEUK’s exposure is therefore limited to an adverse costs award (an adverse costs award is unlikely to be material in the context of the Group’s operations). 382
15. RELATED THIRD PARTY TRANSACTIONS 15.1 Ithaca Energy 15.1.1 Save as disclosed below, there are no related party transactions between Ithaca Energy and its related parties that were entered into during the financial years covered by the historical financial information and up to the Latest Practicable Date. 15.1.2 Ithaca Energy’s main related parties comprise members of key management personnel and its controlling shareholder, DKL Energy, along with affiliated persons and entities. Delek Group is the ultimate holding company of DKL Energy. Transactions with these related parties are disclosed below: (a) Pursuant to arrangements agreed with IEEPL on 15 July 2021, Mr Wallace, a Non-Executive Director of the Company and the CEO of the Delek Group, is entitled to a success based compensation linked to the outcome of the arbitration proceedings raised by IEUK, further details of which are set out in paragraph 14 (Legal and Arbitration Proceedings) of this Part 15 (Additional Information). In the event that IEUK is successful in the proceedings, either by way of commercial settlement or arbitral award by the arbitration tribunal, Mr Wallace shall be entitled to up to 1% of the net proceeds received by IEUK provided at the date of payment he remains in employed by the Delek Group and no notice to terminate his employment has been served. The outcome of the claim is uncertain at this stage and the quantum of any proceeds sought by IEUK is subject to expert evidence that is yet to be finalised. As such it is not possible to quantify the amount of any potential additional compensation and consequently it is not possible to quantify Mr Wallace’s potential additional compensation, although it is IEUK’s reasonable expectation that, if it is successful in the proceedings, the level of damages recovered by IEUK will be material and accordingly Mr Wallace’s additional compensation could be significant. Further details of the proceedings are set out in paragraph 14 (Legal and Arbitration Proceedings) of this Part 15 (Additional Information). Mr Myerson, the Executive Chairman of the Company is entitled to a payment of up 1.8% of the net proceeds received by IEUK in respect of the same arbitration proceedings on the same terms as Mr Wallace’s additional success based compensation. Further details of the arrangements for Mr Myerson are set out in paragraph 7.7 (Additional success based compensation) of this Part 15 (Additional Information). (b) The Company has been notified by Delek that (if the expected admission of the Company to the London Stock Exchange occurs) it intends to establish a management equity plan at the level of the Immediate Shareholder for the benefit of Mr Wallace and certain other senior executives within the Delek Group (the “Delek MEP”). The Company understands that the terms of the Delek MEP are in the process of being agreed but that the Delek MEP would be satisfied by the transfer by DKL Energy of Ordinary Shares to the particular individual and would be subject to the terms of any lock-up arrangements to which DKL Energy will be bound in the event of any admission. (c) The Company (as borrower) and DKL Energy (as lender) are party to the Capital Note Agreement pursuant to which the Company issued the Capital Note to DKL Energy. The expectation of both the Company and DKL Energy is that the Capital Note would be repaid by the Company (on notice to DKL Energy) using the proceeds of an initial public offering in the event of any admission. Following such repayment, DKL Energy would provide a confirmation that such payment is in full and final settlement of any amounts due or payable by the Company in respect of the Capital Notes. Further details of the Capital Note Agreement and Capital Note are set out in paragraph 2.1 of Part 7 (Principal Shareholder and Related Party Transactions). (d) The Company (as borrower) and DKL Energy (as lender) are party to the Tracker Loan. As at 30 June 2022, the amounts outstanding under the Tracker Loan was $77.3 million. All amounts outstanding under the Tracker Loan are 383
expected to be repaid by the Company using the proceeds of an initial public offering in the event of any admission. Further details of the Tracker Loan are set out in paragraph 2.2 of Part 7 (Principal Shareholder and Related Party Transactions); (e) On 24 August 2021, DKL Investments and IEUK entered into an agreement for the provision of professional, directorial, financial administrative, business initiation and advisory services provided by DKL Investments to IEUK and its subsidiaries (the “Management Services Agreement”). It is expected that in the event of any admission of the Company to the London Stock Exchange, DKL Investments and IEUK will enter into a deed of termination with respect to the Management Services Agreement and the Management Services Agreement will terminate with immediate effect upon execution of such deed of termination. For further details, please see paragraph 12.2 (Management Services Agreement) of Part 15 (Additional Information); (f) Gilad Myerson has been employed by DKL Investments as Chief Executive Officer, since 11 November 2019. In the event of expected admission to the London Stock Exchange, Mr.Myerson’s employment, and related directorships of, with DKL Investments will terminate prior to such admission. For further details, please see paragraph 7 of Part 15 (Additional Information). (g) On 29 September 2022, the Company, DKL Energy and Gilad Myerson entered into a management incentive agreement relating to the Company (the “Management Incentive Agreement”). Pursuant to the Management Incentive Agreement and a related share subscription agreement, Mr Myerson has acquired an interest in the MEP Shares. The MEP Shares that Mr Myerson has acquired in are subject to restrictions on Mr Myerson's ability to transfer or dispose of such MEP Shares, or to receive any dividends or exercise any voting rights in connection with them, for the duration of a specified vesting period ordinarily expiring in 2026. For further details, please see paragraphs 5.1 (Summary of the Articles) and 8.4 (Management Equity Plan) of Part 15 (Additional Information). (h) Alan Bruce and Gilad Myerson each have an option over ordinary shares in the Company (the “Options”). The Options represent a right for each holder to subscribe for Ordinary Shares (which have a value which is equal to the higher of (i) 0.2% of the net value of Ithaca Energy assets less its liabilities as at the date immediately before the IPO date; and (ii) 0.2% of the market value of the issued share capital of Ithaca Energy by reference to the most recent annual valuation of Ithaca Energy undertaken for audit as at the date immediately before the IPO date. For further details of the arrangements please see paragraph 8.5 of Part 15 (Additional Information). 16. AUDITORS AND REPORTING ACCOUNTANTS Deloitte LLP, whose office is at 1 New Street Square, London, EC4A 3HQ, has provided an accountant’s report on the historical financial information of the Group for the three years ended 31 December 2019, 2020 and 2021 and the six months ended 30 June 2022 as set out in Section A of Part 13 (Historical Financial Information). Deloitte LLP is registered to carry on audit work in the UK and Ireland by the Institute of Chartered Accountants in England and Wales. Ernst & Young LLP, whose office is at 1 More London Place, London, SE1 2AF, has provided an accountant’s report on (i) the historical financial information of the Siccar Point Group for the three years ended 31 December 2019, 2020 and 2021 and the six months ended 30 June 2022 as set out in Section B of Part 13 (Historical Financial Information) and (ii) the historical financial information of IOG (formerly Chevron North Sea Limited) for the year ended 31 December 2019 as set out in Section C of Part 13 (Historical Financial Information). Ernst & Young LLP is registered to carry on audit work in the UK and Ireland by the Institute of Chartered Accountants in England and Wales. 384
The financial information contained in this Registration Document which relates to the Company does not constitute full statutory accounts as referred to in section 434(3) of the 2006 Act. Statutory audited accounts of the Group, on which the Group’s previous auditors, Ernst & Young LLP, have given their unqualified report and which contained no statement under section 498(2) or (3) of the 2006 Act, have been delivered to the Registrar of Companies in respect of the two accounting periods ended 31 December 2019 and 31 December 2020. Statutory audited accounts of the Group, on which the Group’s auditors, Deloitte LLP, have given their unqualified report and which contained no statement under section 498(2) or (3) of the 2006 Act, have been delivered to the Registrar of Companies in respect of the accounting period ended 31 December 2021. 17. CONSENTS 17.1 Deloitte LLP of 1 New Street Square, London, EC4A 3HQ is registered to carry on audit work in the UK and Ireland by the Institute of Chartered Accountants in England and Wales and has given and has not withdrawn its written consent to the inclusion in this Registration Document of its report in Section A of Part 13 (Historical Financial Information) and Part 10 (Unaudited Pro Forma Condensed Combined Financial Information) and references thereto in the form and context in which they appear and has authorised the contents of its reports for the purposes of item 1.3 of Annex 1 of the UK version of Commission Delegated Regulation (EU) 2019/980, as it forms part of UK law by virtue of the EUWA. As the Shares have not been and will not be registered under the US Securities Act, Deloitte LLP has not filed and will not file a consent under Section 7 of the US Securities Act. 17.2 Ernst & Young LLP of 1 More London Place, London, SE1 2AF has given and has not withdrawn its written consent to the inclusion in this Registration Document of its reports in Section B and Section C of Part 13 (Historical Financial Information) and references thereto in the form and context in which they appear and has authorised the contents of its reports for the purposes of item 1.3 of Annex 1 of the UK version of Commission Delegated Regulation (EU) 2019/980, as it forms part of UK law by virtue of the EUWA. As the Shares have not been and will not be registered under the US Securities Act, Ernst & Young LLP has not filed and will not file a consent under Section 7 of the US Securities Act. 17.3 Netherland, Sewell & Associates, Inc., whose registered office is at 2100 Ross Avenue, Suite 2200, Dallas, Texas 75201, United States of America, are independent petroleum engineers, geologists, geophysicists and petrophysicists and (in its capacity as a competent person), Netherland, Sewell & Associates, Inc., has given and not withdrawn its written consent to the inclusion in this Registration Document of its report which is set out in Part 18 (Competent Person’s Report) and references thereto in the form and context in which they appear and has authorised the contents of those parts of this Registration Document for the purposes of 5.3.2(2)(f) of the Prospectus Regulation Rules. Netherland, Sewell & Associates, Inc. do not have any material interest in the Company. The Company confirms that, between the date of publication of the NSAI CPR and the date of this Registration Document, no material changes have occurred, the omission of which would make the NSAI CPR misleading. 18. THIRD PARTY INFORMATION The Company confirms that all external third-party information included in this Registration Document has been accurately reproduced and, so far as the Company is aware and has been able to ascertain from information published by such third parties, no facts have been omitted which would render the reproduced information inaccurate or misleading. Where third-party information has been used in this Registration Document, the source of such information has been identified. Where the Group has relied upon internally developed estimates, the information is identified as Company estimates or beliefs. Unless otherwise stated, such information has not been audited. 19. NSAI CPR There have been no material changes since the effective date of the NSAI CPR (being 30 June 2022), the omission of which would make such report misleading. 385
19. GENERAL The financial information contained in this Registration Document does not amount to statutory accounts within the meaning of Section 434(3) of the Companies Act 2006. 20. DOCUMENTS AVAILABLE FOR INSPECTION Copies of the following documents shall be available for inspection on the Company’s website at www.Ithacaenergy.com for a period of 28 days from the date of publication of this Registration Document: • the Articles; • the historical financial information of the Group as at and for the six months ended 30 June 2022 and the years ended 31 December 2019, 2020 and 2021 and , together with the related accountant’s report from Deloitte LLP, which is set out in Section A of Part 13 (Historical Financial Information); • the historical financial information of the Siccar Point Group as at and for the six month period ended 30 June 2022 and the years ended 31 December 2019, 2020 and 2021, together with the related accountant’s report from Ernst & Young LLP, which is set out in Section B of Part 13 (Historical Financial Information); • the historical financial information of IOG (formerly Chevron North Sea Limited) as at and for the year ended 31 December 2019, together with the related accountant’s report from Ernst & Young LLP, which is set out in Section C of Part 13 (Historical Financial Information); • the report from Deloitte LLP on the unaudited pro forma condensed combined financial information, which is set out in Part 10 (Unaudited Pro Forma Condensed Combined Financial Information); • the service agreements and letters of appointment referred to in in this Part 15 (Additional Information); • the Competent Person’s Report by Netherland, Sewell & Associates, Inc., set out in Part 18 (Competent Person’s Report); • the consent letters referred to in paragraph 17 (Consents) of this Part 15 (Additional Information) above; and • a copy of this Registration Document. Dated: 18 October 2022 386
PART 16—DEFINITIONS The following definitions apply throughout this Registration Document, unless the context otherwise requires: “$” or “USD” or “US dollars” . . . . . . . . . . the lawful currency of the United States “£” or “GBP” or “UK pounds sterling” or “pence” . . . . . . . . . . the lawful currency of the United Kingdom “€” or “Euro” . . . . . . . . the single currency of the participating member states of the Third Stage of European Economic and Monetary Union of the Treaty Establishing the European Community, as amended from time to time; “2006 Act” or “Companies Act” . . . . the Companies Act 2006, as amended; “2024 Notes” . . . . . . . . the $500 million aggregate principal amount of 9.375% senior notes due 2024 issued by the Bond Issuer; “2026 Notes” . . . . . . . . the $625 million aggregate principal amount of 9.000% senior notes due 2026 issued by the Bond Issuer; “AB Option” . . . . . . . . . has the meaning given to it in paragraph 8.5 (Option Agreements) in Part 15 (Additional Information); “AB Option Shares” . . . has the meaning given to it in paragraph 8.5 (Option Agreements) in Part 15 (Additional Information); “Adjusted EBITDAX” . . . has the meaning given to it in paragraph 4 of Part 2 (Presentation of Financial and Other Information); “AIM” . . . . . . . . . . . . . . the AIM market operated by the London Stock Exchange; “A Ordinary Shares” . . . the A ordinary shares of $1 each in the capital of the Company; “Alberta Securities Act” . the Securities Act (Alberta), RSA 2000 cS-4 in Canada; “Articles” or “Articles of Association” . . . . . . . the articles of association of the Company as in force at the date of this Registration Document; “Aspen” . . . . . . . . . . . . Aspen Insurance UK Limited; “Aspen Deed of Indemnity” . . . . . . . . the deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Aspen dated 30 November 2020; “At-IPO Awards” . . . . . . has the meaning given to it in paragraph 8.1 (Ithaca Energy Long Term Incentive Plan) of Part 15 (Additional Information); “Available Liquidity” . . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “B1 Ordinary Shares” . . the B1 ordinary shares of $0.01 each in the capital of the Company; “B2 Ordinary Shares” . . the B2 ordinary shares of $0.01 each in the capital of the Company; “BEIS” . . . . . . . . . . . . . the Department of Business, Energy and Industrial Strategy of the United Kingdom; “BNPP Facility Agreement” . . . . . . . . $200.0 million facility agreement dated 4 November 2019 among DKL Energy, the Company and BNP Paribas; “Board” . . . . . . . . . . . . the board of directors of the Company; “BPGM” . . . . . . . . . . . . BP Gas Marketing Limited; 387
“BPOI” . . . . . . . . . . . . . BP Oil International Limited; “Brexit” . . . . . . . . . . . . the withdrawal of the United Kingdom from the European Union; “Business Corporations Act” . . . the Business Corporations Act 2000 (as amended) of the province of Alberta, Canada; “Buyer Liabilities” . . . . . has the meaning given to it in paragraph 12.10.2 (Retained Decommissioning Liability Arrangements) of Part 15 (Additional Information); “Capital Note” . . . . . . . . the capital note in aggregate principal amount of $392,000,000 issued by the Company to DKL Energy pursuant to the Capital Note Agreement; “Capital Note Agreement” . . . . the $392,000,000 capital note agreement between the Company (as borrower) and DKL Energy (as lender) dated 4 November 2019, as amended from time to time; “Captain IP Licence” . . . has the meaning given to it in paragraph 12.10.4 (Captain IP Licence) of Part 15 (Additional Information); “certificated” or “in certificated form” . . . . a share or other security not in uncertificated form (that is, not in CREST); “Chairman” . . . . . . . . . . the executive chairman of the Board; “Chevron Acquired Assets” . . . . . . . . . . . those assets acquired by the Group by way of the Chevron Acquisition, being Alba, Alder, Britannia, Brodgar, Callanish, Captain, Elgin-Franklin, Enochdhu, Erskine, Jade and Thundercat; “Chevron Acquisition” . . the acquisition by IEUK from CNSHL of the entire issued share capital of CNSL; “Chevron Acquisition Agreement” . . . . . . . . the put and call option agreement entered into between CNSHL and IEUK in respect of the Chevron Acquisition dated 29 May 2019, as amended from time to time; “CNSHL” . . . . . . . . . . . Chevron Eurasia Pacific Limited (formerly named Chevron North Sea Holdings Limited), a company incorporated in England & Wales with registered number 11867122; “CNSL” or “IOG” . . . . . . Ithaca Oil and Gas Limited (formerly named Chevron North Sea Limited), a company incorporated in England & Wales with registered number 01546623; “Company” or “Ithaca Energy” . . . . . . . . . . Ithaca Energy Limited (formerly known as Delek North Sea Limited), a private company limited by shares, incorporated under the 2006 Act and registered in England & Wales with registered number 12263719; “CREST” . . . . . . . . . . . the relevant system (as defined in the CREST Regulations) for paperless settlement of sales and purchases of securities and the holding of shares in uncertificated form in respect of which Euroclear is the operator (as defined in the CREST Regulations); “CREST Regulations” . . the Uncertificated Securities Regulations 2001 (SI2001/3755); “Current Year Profit Forecast” . . . . . . . . . has the meaning given in paragraph 1 (Current Year Profit Forecast) of Part 14 (Profit Forecasts); 388
“Deeds of Indemnity” . . together, the HCCI Deed of Indemnity, Everest Deed of Indemnity, Aspen Deed of Indemnity and MIIC Deed of Indemnity; “Delek Group” . . . . . . . DGL and its subsidiaries; “Delek MEP” . . . . . . . . . has the meaning given to it in paragraph 15.1.2(b) (Ithaca Energy) of Part 15 (Additional Information); “DGL” or “Delek” . . . . . . Delek Group Ltd., a company incorporated in Israel with registered number 520044322 and whose securities are admitted to trading on the Tel Aviv Stock Exchange; “Directors” . . . . . . . . . . the (i) directors of the Company as at the date of the Registration Document, being the Executive Directors, and Idan Wallace; and (ii) for the purpose of this document, the Proposed Directors, and “Director” means any one of them; “Disclosure Guidance and Transparency Rules” . . . . . . . . . . . the disclosure guidance and transparency rules issued by the FCA under Part VI of FSMA; “DKL Energy” (or the “Immediate Shareholder”) . . . . . . DKL Energy Limited, a company incorporated in Jersey with registered number 130061; “DKL Investments” . . . . DKL Investments Limited, a company incorporated in Jersey with registered number 116681; “DSBP” . . . . . . . . . . . . the Ithaca Energy Deferred Share Bonus Plan; “DSBP Awards” . . . . . . has the meaning given to it in paragraph 8.1 (Ithaca Energy Deferred Bonus Plan) of Part 15 (Additional Information); “Energy Act” . . . . . . . . the Energy Act 2016 (and “Energy Acts” means such Act and other applicable Energy Acts of the United Kingdom from time to time, in each case as amended from time to time); “Energy Profits Levy” . . the charge referred to as the energy (oil and gas) profits levy within the Energy Profits Act. “Energy Profits Act” . . . Energy (Oil and Gas) Profits Levy Act 2022; “EnQuest” . . . . . . . . . . Enquest PLC; “ESG” . . . . . . . . . . . . . Environmental, Social and Governance; “EURIBOR” . . . . . . . . . . the Euro Inter-bank Offered Rate; “European Union” or “EU” the European Union, first established by the treaty made at Maastricht on 7 February 1992; “Euroclear” . . . . . . . . . . Euroclear UK & Ireland Limited, the operator (as defined in the CREST Regulations) of CREST; “Everest” . . . . . . . . . . . Everest Insurance (Ireland), DAC; “Everest Deed of Indemnity” . . . . . . . . the deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Everest dated 22 January 2022; “Executive Directors” . . the executive directors of the Company as at the date of this Registration Document, whose details are set out in paragraph 1.1 of Part 6 (Directors, Senior Managers and Corporate Governance); “Existing Ordinary Shares” . . . . . . . . . . the A Ordinary Shares, the B1 Ordinary Shares and the B2 Ordinary Shares in issue as at the date of this document; 389
“Exit” . . . . . . . . . . . . . . has the meaning given to it in paragraph 5.1 (Summary of the Articles) in Part 15 (Additional Information); “Facility A” . . . . . . . . . . a multicurrency revolving borrowing base credit facility up to $1.076 billion comprising BNP Paribas, Lloyds Bank plc, Wells Fargo Bank N.A., London Branch, The Royal Bank of Scotland plc, Deutsche Bank AG, Amsterdam Branch, DNB (UK) Limited, ING Belgium S.A./NV, Morgan Stanley and Mizrahi Tefahot Bank Limited, London Branch as lenders; “Facility B” . . . . . . . . . . a US dollar revolving borrowing base credit facility up to $149 million comprising BNP Paribas, Lloyds Bank plc, Wells Fargo Bank N.A., London Branch, The Royal Bank of Scotland plc, Deutsche Bank AG, Amsterdam Branch, DNB (UK) Limited, ING Belgium S.A./NV, Morgan Stanley and Mizrahi Tefahot Bank Limited, London Branch as lenders; “Facilities” . . . . . . . . . . together, Facility A and Facility B; “FCA” . . . . . . . . . . . . . the UK Financial Conduct Authority; “FDP” . . . . . . . . . . . . . the field development plan; “FID” . . . . . . . . . . . . . . Final investment decision; “FRC” . . . . . . . . . . . . . Financial Reporting Council in the United Kingdom “Free Shares” . . . . . . . . has the meaning given to it in paragraph 8.3 (Share Incentive Plan) of Part 15 (Additional Information); “FSMA” . . . . . . . . . . . . the Financial Services and Markets Act 2000, as amended; “FY2019” . . . . . . . . . . . the financial year of the Group or IOG or the Siccar Point Group (as applicable) ended 31 December 2019; “FY2020” . . . . . . . . . . . the financial year of the Group or IOG or the Siccar Point Group (as applicable) ended 31 December 2020; “FY2021” . . . . . . . . . . . the financial year of the Group or IOG or the Siccar Point Group (as applicable) ended 31 December 2021; “GM Option” . . . . . . . . . has the meaning given to it in paragraph 8.5 (Option Agreements) in Part 15 (Additional Information); “GM Option Shares” . . . has the meaning given to it in paragraph 8.5 (Option Agreements) in Part 15 (Additional Information); “Governance Code” . . . . the UK Corporate Governance Code issued by the Financial Reporting Council, as amended from time to time; “Group” or “Ithaca Energy” . . . . . . . . . . the Company and its Subsidiaries from time to time; “Group Adjusted EBITDAX” . . . . . . . . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “Group Financial Information” . . . . . . . the audited historical financial information of the Group for the six month period ended 30 June 2022 and for each of the years ended 31 December 2021, 2020 and 2019 included in Section A of Part 13 (Historical Financial Information); “Group Free Cashflow” . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “GSA Acquisition” . . . . . the acquisition of all of the GSA licences and the associated infrastructure interests of One Dyas E&P Limited (formerly, Dyas UK Limited) and Petrofac Limited, including the acquisition of One Dyas E&P Limited (formerly, Dyas UK Limited), Stella FPF Holdings Limited 390
and Petrofac Limited’s interests in FPF1 Limited, the company that owned the FPF-1 floating production facility that is used on the GSA production hub, completed in December 2018; “Harbour Energy” . . . . . the group of companies of which Harbour Energy plc is the holding company; “HCCI” . . . . . . . . . . . . . HCC International Insurance Company plc; “HCCI Deed of Indemnity” . . . . . . . . the Deed of indemnity between, amongst others, IEEPL (as lead indemnitor) and HCCI dated 28 January 2021; “Historical Financial Information” or “HFI” . the historical financial information included in Part A of Sections A, B and C of Part 13 (Historical Financial Information); “historical financial period” . . . . . . . . . . . the period from the start of FY2019 to 30 June 2022; “HMRC” . . . . . . . . . . . . Her Majesty’s Revenue and Customs; “HS&E . . . . . . . . . . . . . Health, safety and environmental; “Hurdle” . . . . . . . . . . . . has the meaning given to it in paragraph 8.4 (Management Equity Plan) in Part 15 (Additional Information); “Hurdle Amount” . . . . . has the meaning given to it in paragraph 5.1 (Summary of the Articles) in Part 15 (Additional Information); “IA” . . . . . . . . . . . . . . . has the meaning given to it in paragraph 5.2 (Supplementary Charge) of Part 8 (Regulation); “IAS 34” . . . . . . . . . . . . IAS 34 Interim Financial Reporting; “IEA” . . . . . . . . . . . . . . the International Energy Agency; “IEEPL” . . . . . . . . . . . . Ithaca Energy E&P Limited, (formerly named Ithaca Energy Limited), a company registered in Jersey with registered number 126983; “IENS plc” or “Bond Issuer” . . . . . . . . . . . Ithaca Energy (North Sea) plc, a company incorporated in Scotland with registered number SC595124; “IEUK” . . . . . . . . . . . . . Ithaca Energy UK Limited, a company incorporated in Scotland with registered number SC272009; “IFRS” . . . . . . . . . . . . . the International Financial Reporting Standards as issued by the International Accounting Standards Board; “ILS” . . . . . . . . . . . . . . the Israeli New Shekel, the lawful currency of Israel; “Incurrence Test” . . . . . has the meaning given to it in paragraph 12.1 (Siccar Point Bonds) of Part 15 (Additional Information); “IOG Financial Information” . . . . . . . the financial statements of IOG as at and for the year ended 31 December 2019 included in Section C of Part 13 (Historical Financial Information); “Indenture” . . . . . . . . . . the indenture under which the 2026 Notes were issued among, inter alios, the Bond Issuer, IEEPL as Senior Guarantor, the Subordinated Guarantors (as defined therein), BNY Mellon Corporate Trustee Services Limited, as trustee and The Bank of New York Mellon, London Branch, as Principal Paying Agent and The Bank of New York Mellon SA/NV, Dublin Branch, as Transfer Agent and Registrar; “ISDAs” . . . . . . . . . . . . International Swaps and Derivatives Association master agreements; “Kemira” . . . . . . . . . . . Kemira OYJ with offices at Porkkalankatu 3, 00180 Helsinki, Finland; 391
“Kemira Contract” . . . . the contract for the provision of liquid polymer entered into between IOG and Kemira on 17 June 2016, as amended from time to time; “KPI” . . . . . . . . . . . . . . key performance indicator; “Kroll Report” . . . . . . . . a valuation report in connection with impairment testing of the Group under IAS 36 prepared by Kroll Advisory Ltd included in the annual report of DGL for the year ended 31 December 2021; “Latest Practicable Date” 17 October 2022, being the latest practicable date before the publication of this Registration Document; “LEI” . . . . . . . . . . . . . . legal entity identifier; “Liberty” . . . . . . . . . . . Liberty Mutual Insurance Europe SE; “Liberty Deed of Indemnity” . . . . . . . . the deed of indemnity between, amongst others, IEEPL (as principal indemnitor) and Liberty dated 26 November 2020; “LIBOR” . . . . . . . . . . . . the London Inter-bank Offered Rate; “Licensees” . . . . . . . . . has the meaning given to it in paragraph 12.10.5 (Master IP Licence) of Part 15 (Additional Information); “Listing Rules” . . . . . . . the listing rules of the FCA made under Part VI of FSMA; “Listing Value” . . . . . . . has the meaning given to it in paragraph 5.1 (Summary of the Articles) in Part 15 (Additional Information); “London Stock Exchange” . . . . . . . . London Stock Exchange plc; “Long Term Profit Forecast” . . . . . . . . . has the meaning given in paragraph 2 (Long Term Financial Forecast) of Part 14 (Profit Forecasts); “LTIP” . . . . . . . . . . . . . the Ithaca Energy Long Term Incentive Plan; “LTIP Awards” . . . . . . . awards over Ordinary Shares granted to Executive Directors and selected employees of the Group pursuant to the LTIP; “LTM” . . . . . . . . . . . . . last twelve months; “Management Incentive Agreement” . . . . . . . the management incentive agreement between the Company, DKL Energy, Gilad Myerson dated 29 September 2022; “Management Services Agreement” . . . . . . . the agreement for the provision of professional, directorial, financial administrative, business initiation and advisory services between DKL Investments and IEUK and its subsidiaries dated 24 August 2021; “Marubeni Acquisition” . the acquisition by IEUK from MNSL of the entire issued share capital of MOGL; “Marubeni Acquisition Agreement” . . . . . . . . the sale and purchase agreement entered into between MNSL, IEUK and IEEPL in respect of the Marubeni Acquisition dated 2 November 2021, as amended from time to time; “Marubeni Assets” . . . . those assets acquired by the Group by way of the Marubeni Acquisition, being MonArb and Columba; “Master Licence Agreement” . . . . . . . . has the meaning given to it in paragraph 12.10.5 (Master Licence Agreement) of Part 15 (Additional Information); “Matching Shares” . . . . has the meaning given to it in paragraph 8.3 (Share Incentive Plan) of Part 15 (Additional Information); 392
“MEP” or “Management Equity Plan” . . . . . . . has the meaning given to that term in paragraph 8.4 (Management Equity Plan) of Part 15 (Additional Information); “MEP Shares” . . . . . . . . has the meaning given to that term in paragraph 8.4 (Management Equity Plan) of Part 15 (Additional Information); “MER UK Strategy” . . . . the Maximising Economic Recovery Strategy for the UK as published by BEIS in 2016; “MIIC” . . . . . . . . . . . . . Markel International Insurance Company Limited; “MIIC Deed of Indemnity” the deed of indemnity between, amongst others, IEEPL (as lead indemnitor) and dated 21 January 2022; “Mitsui” . . . . . . . . . . . . Mitsui E&P UK Limited a company incorporated in England and Wales with registered number 07652477; “Mitsui Acquisition” . . . the acquisition by IOG from Mitsui of certain interests in the UKCS Petroleum Production Licence No. P.213 Block 16/26, Area A—Alba Field Area; “Mitsui Acquisition Agreement” . . . . . . . . the sale and purchase agreement entered into between Mitsui and IOG in respect of the Mitsui Acquisition dated 17 September 2021; “Mitsui Interests” . . . . . has the meaning given to it in paragraph 12.5 (Mitsui Acquisition Agreement) of Part 15 (Additional Information); “MNSL” . . . . . . . . . . . . Marubeni North Sea Limited, a company incorporated in England & Wales with registered number 05119283; “MOGL” . . . . . . . . . . . . Ithaca MA Limited (formerly named Marubeni Oil & Gas (U.K.) Limited), a company incorporated in England & Wales with registered number 03947050; “net debt” . . . . . . . . . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “net debt to Group Adjusted EBITDAX” . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “net debt to LTM Adjusted EBITDAX” . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “Net Zero Plan” . . . . . . has the meaning given to it on Part 1 (Risk Factors); “NI 31-103” . . . . . . . . . . National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations; “NI 33-105” . . . . . . . . . . National Instrument 33-105 Underwriting Conflicts; “NI 45-106” . . . . . . . . . . National Instrument 45-106 Prospectus Exemptions; “Non-Executive Directors” . . . . . . . . . the non-executive directors of the Company as at the date of this Registration Document, whose details are set out in paragraph 1 of Part 6 (Directors, Senior Managers and Corporate Governance); “North Sea Transition Deal” . . . . . . . . . . . . North Sea Transition Deal published in March 2021 by BEIS and OEUK setting out how the UK Government and the oil and gas industry will work together to support the country’s transition to net zero carbon by 2050 393
“NSAI” . . . . . . . . . . . . . Netherland, Sewell & Associates, Inc., whose registered office is at 2100 Ross Avenue, Suite 2200, Dallas, Texas 75201, United States of America; “NSAI CPR” or “Competent Person’s Report” . . . . . . . . . . . the competent person’s report produced by NSAI dated as at 30 June 2022 (as contained in Part 18 (Competent Person’s Report)); “NSAI Historic Reports” . the competent person’s report produced by NSAI dated as at (i) 31 December 2021, and (ii) 31 December 2019 and 2020; “NSAI Reports” . . . . . . . (i) the NSAI CPR, and (ii) the NSAI Historic Reports; “NSTA” . . . . . . . . . . . . the UK North Sea Transition Authority, being a business name of the Oil and Gas Authority, a limited company registered in England and Wales with registered number 09666504, and registered office at Sanctuary Buildings, 20 Great Street, London, SW1P 3BT, United Kingdom, whose sole shareholder is the Secretary of State, and any successor in relevant function; “NSTD” . . . . . . . . . . . . North Sea Transition Deal published in March 2021 by BEIS and OEUK setting out how the UK Government and the oil and gas industry will work together to support the country’s transition to net zero carbon by 2050 “OECD” . . . . . . . . . . . . the Organisation for Economic Cooperation and Development; “Official List” . . . . . . . . the official list maintained by the FCA in its capacity as competent authority for the purposes of Part VI of FSMA; “Ordinary Shares” or “Shares” . . . . . . . . . . the ordinary shares in the capital of the Company following completion of the Share Capital Reorganisation; “Paris Agreement” . . . . the Paris Agreement negotiated at the 2015 United Nations Conference on Climate Change; “Partnership Shares” . . . has the meaning given to it in paragraph 8.3 (Share Incentive Plan) of Part 15 (Additional Information); “PCAOB” . . . . . . . . . . . the Public Company Accounting Oversight Board (United States); “Performance Awards” . LTIP Awards which are subject to stretching performance conditions which will determine the extent to which such LTIP Awards shall be capable of vesting; “PLC Articles” . . . . . . . the articles of association of the Company which are proposed to be adopted by the Company in the event of admission; “Pre-Chevron Acquisition Cash Extraction Loan” . . . . has the meaning given to it in paragraph 12.10.3(b) (Pre-Chevron Acquisition Cash Extraction Loan) of Part 15 (Additional Information); “Pre-Chevron Acquisition Restructuring Loan” . . has the meaning given to it in paragraph 12.10.3(a) (Pre-Chevron Acquisition Restructuring Loan) of Part 15 (Additional Information); “Proceeds” . . . . . . . . . . has the meaning given to it in paragraph 5.1 (Summary of the Articles) in Part 15 (Additional Information); “Projected EDITDA Information” . . . . . . . certain financial projections for the Group, including projected EBITDA for each of the years ending 31 December 2022 to 31 December 2042, as included in the Kroll Report; 394
“Proposed Directors” . . the proposed non-executive directors of the Company as at the date of this Registration Document, whose details are set out in paragraph 1.4 (The Proposed Directors) of Part 6 (Directors, Senior Managers and Corporate Governance) and who are intended to be appointed to the Board prior to any admission of the Company to the London Stock Exchange; “Prospectus Regulation Rules” . . . . . . . . . . . the Prospectus Regulation Rules of the FCA made under section 73A of FSMA; “PR Regulation” . . . . . . the UK version of commission delegated regulation (EU) 2019/980 of the European Parliament and of the Council which is part of UK law by virtue of the European Union (Withdrawal) Act 2018 (as may be amended from time to time, including, without limitation, by virtue of the European Union (Withdrawal Agreement) Act 2020); “PRT” . . . . . . . . . . . . . petroleum revenue tax applying in the United Kingdom from time to time; “RBL Facility” . . . . . . . . the facility made available under the RBL Facility Agreement; “RBL Facility Agreement” the secured revolving borrowing base facility agreement dated 29 May 2019, as amended from time to time including by a deed of amendment, restatement and release dated 19 July 2021, entered into between, among others, IEUK as borrower, BNP Paribas as facility agent and the lenders thereunder from time to time; “Registration Document” this document; “Restricted Share Awards” . . . . . . . . . . LTIP Awards which are granted which are not subject to performance conditions and which vest solely on the basis of the participant’s continued employment with the Group; “Retained Decommissioning Liability Arrangements” . . . . . the arrangements pertaining to the Retained Decommissioning Liability Fields pursuant to the Chevron Acquisition Agreement, details of which are set out in paragraph 12.10.2 of Part 15 (Additional Information); “Retained Decommissioning Liability Field” . . . . . . the Cambo field, Heather field or the Strathspey field, and “Retained Decommissioning Liability Fields” means all of them; “RFCT” . . . . . . . . . . . . Ring Fence Corporation Tax; “Ring Fenced Corporation Tax” . . . . has the meaning given to it in paragraph 5.1 (Ring Fence Corporation Tax) of Part 8 (Regulation); “Ring Fenced Losses” . . has the meaning given to it in paragraph 5.1 (Ring Fence Corporation Tax) of Part 8 (Regulation); “Ring Fenced Profits” . . has the meaning given to it in paragraph 5.1 (Ring Fence Corporation Tax) of Part 8 (Regulation); “Secretary of State” . . . the Secretary of State for Business, Energy and Industrial Strategy of the United Kingdom, and any successor in relevant function; “Senior Managers” . . . . those members of the management bodies of the Company and its subsidiaries who are relevant to establishing that the Company has the appropriate expertise and experience for the management of its business for the purposes of item 12.1 of Annex I of the PR Regulation, being those persons named in Part 6 (Directors, Senior Managers and Corporate Governance); 395
“Share Capital Reorganisation” . . . . . the share capital reorganisation of the Group referred to in paragraph 4.3 of Part 15 (Additional Information); “Shareholders” . . . . . . . the holders of shares from time to time; “Shell” . . . . . . . . . . . . . Shell International Trading and Shipping Company Limited; “Siccar Point” or “SPEHL” Ithaca SP (Holdings) Limited (formerly named Siccar Point Energy (Holdings) Limited), a company incorporated in England & Wales with registered number 09102478; “Siccar Point Acquisition” . . . . . . . the acquisition by IEUK from the Siccar Point Seller of the entire issued share capital of SPEHL and certain loan notes issued by SPEFL; “Siccar Point Acquisition Agreement” . . . . . . . . the sale and purchase agreement entered into between the Siccar Point Seller, IEUK and IEEPL in respect of the Siccar Point Acquisition dated 7 April 2022, as amended from time to time; “Siccar Point Adjusted EBITDAX” . . . . . . . . . has the meaning given to it in paragraph 4 of Part 2 (Presentation of Financial and Other Information); “Siccar Point Assets” . . those assets acquired by the Group by way of the Siccar Point Acquisition, being Mariner, Schiehallion, Jade, Cambo, Rosebank, Tornado, Suilven, Blackrock, certain other exploration assets, Glen Lyon FPSO, SIRGE and WOSP; “Siccar Point Bonds” . . the $200,000,000 9.00% senior, unsecured, callable bonds 2021/2026 issued by SPEB; “Siccar Point Group” . . . SPEHL and its Subsidiaries from time to time; “Siccar Point Financial Information” . . . . . . . the audited consolidated financial information of the Siccar Point Group for the six month period ended 30 June 2022 and for the years ended 31 December 2019, 2020 and 2021; “Siccar Point Free Cashflow” . . . . . . . . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “Siccar Point Seller” . . . Siccar Point Energy Luxembourg S.C.A., a partnership limited by shares (société en commandite par actions) incorporated and existing under the laws of the Grand Duchy of Luxembourg, registered with the Luxembourg Trade and Companies Register under number B 189091; “SIF” . . . . . . . . . . . . . . serious incident frequency; “SIP” . . . . . . . . . . . . . . the Ithaca Energy Share Incentive Plan; “SOFR” . . . . . . . . . . . . the Secured Overnight Financing Rate; “SONIA” . . . . . . . . . . . . the Sterling Overnight Index Average; “SPEB” . . . . . . . . . . . . Ithaca SP Bonds plc (formerly named Siccar Point Energy Bonds plc), a company incorporated in England & Wales with registered number 11029537; “SPEEPL” . . . . . . . . . . . Ithaca SP E&P Limited (formerly named Siccar Point Energy E&P Limited), a company incorporated in England & Wales with registered number 01504603; “SPEFL” . . . . . . . . . . . . Ithaca SP Finance Limited (formerly named Siccar Point Energy Finance Limited), a company incorporated in England & Wales with registered number 09102885; 396
“SPEL” . . . . . . . . . . . . Ithaca SPE Limited (formerly named Siccar Point Energy Limited), a company incorporated in England & Wales with registered number 09103084; “SPEL Facility” . . . . . . . has the meaning given to it in paragraph 12.1.6 (SPEL Facility Agreement with, among others, Natixis) of Part 15 (Additional Information); “SPEL Facility Agreement” . . . . . . . . has the meaning given to it in paragraph 12.1.6 (SPEL Facility Agreement with, among others, Natixis) of Part 15 (Additional Information); “SPEUKL” . . . . . . . . . . Ithaca SP O&G Limited (formerly named Siccar Point Energy U.K. Limited), a company incorporated in England & Wales with registered number 09858988; “Sproule” . . . . . . . . . . . Sproule International Limited of 140—4th Avenue SW, Suite 900, Calgary, Alberta, Canada T2P 3N3; “Subordinated Delek Loan” . . . . . . . . . . . . the subordinated shareholder loan in an amount of $250.0 million pursuant to the loan agreement dated 4 November 2019 between DGL, as lender, and IEEPL, as borrower; “Subsidiary” . . . . . . . . . has the meaning given to such term in section 1162 of the 2006 Act and includes group companies included in the consolidated financial statements of the Group from time to time (and “Subsidiaries” shall be construed accordingly); “Subsidiary Undertaking” has the meaning given to such term in section 1162 of the 2006 Act (and “Subsidiary Undertakings” shall be construed accordingly); “Sumitomo” . . . . . . . . . Sumitomo Corporation, a company incorporated in Japan with registered number 0100-01-008692; “Summit” . . . . . . . . . . . Ithaca Zeta Limited (formerly named Summit Exploration and Production Limited), a company incorporated in England & Wales with registered number 08860426; “Summit Acquisition” . . the acquisition by IEUK from Sumitomo of the entire issued share capital of Summit; “Summit Acquisition Agreement” . . . . . . . . the sale and purchase agreement entered into between the Sumitomo, IEUK and IEEPL in respect of the Summit Acquisition dated 28 February 2022, as amended from time to time; “Summit Assets” . . . . . those assets acquired by the Group by way of the Summit Acquisition, being Elgin-Franklin, certain other exploration assets, SEAL and GAEL; “Supplementary Charge” has the meaning given to it in paragraph 5.2 (Supplementary Charge) of Part 8 (Regulation); “Technip” . . . . . . . . . . . Technip UK Limited, a company incorporated in England and Wales with registered number 00200086; “Technip Contract” . . . . the contract between IEUK and Technip for the provision of pipelay and subsea construction services (including flexible and umbilical supply) for the Captain EOR stage 2 project executed on 29 April 2021 and 05 May 2021; “Tracker Loan” . . . . . . . the $198 million intercompany loan agreement between the Company (as borrower) and DKL Energy (as lender) dated 4 November 2019, as amended from time to time; “TSX” . . . . . . . . . . . . . the Toronto Stock Exchange; 397
“UAE” . . . . . . . . . . . . . United Arab Emirates; “UK” or “United Kingdom” . . . . . . . . . the United Kingdom of Great Britain and Northern Ireland; “UKCS” . . . . . . . . . . . . the United Kingdom Continental Shelf; “UK Licence” . . . . . . . . a petroleum exploration and/or production licence in the United Kingdom; “UK MAR” . . . . . . . . . . the Market Abuse Regulation (2014/596/EU) to the extent that it forms part of the domestic law of the United Kingdom by virtue of the European Union (Withdrawal) Act 2018 (as may be amended from time to time, including, without limitation, by virtue of the European Union (Withdrawal Agreement) Act 2020); “UK NS&I Act” . . . . . . . the UK National Security and Investment Act; “UK Prospectus Regulation” . . . . . . . . Regulation (EU) No 2017/1129 of the European Parliament and of the Council of the EU, as amended, which is part of UK law by virtue of the European Union (Withdrawal) Act 2018 (as may be amended from time to time, including, without limitation, by virtue of the European Union (Withdrawal Agreement) Act 2020); “Unaudited Pro Forma Condensed Combined Financial Information” the unaudited pro forma income statements for the six months ended 30 June 2022 and the year ended 31 December 2021 of the Group set out in Part 10 (Unaudited Pro Forma Condensed Combined Financial Information); “unit operating expenditure” . . . . . . . has the meaning given to it in paragraph 4 (Non-IFRS Financial Information) of Part 2 (Presentation of Financial and Other Information) “US” or “United States” . the United States of America; “US GAAS” . . . . . . . . . auditing standards generally accepted in the United States; “US Securities Act” . . . . the US Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder; “VAT” . . . . . . . . . . . . . . value added tax; and “Withdrawal Agreement” the agreement on the withdrawal of the United Kingdom of Great Britain and Northern Ireland from the European Union and the European Atomic Energy Community 2019/C 384 I/01. 398
PART 17—GLOSSARY OF TECHNICAL TERMS The following technical terms or other abbreviations (or variations of them) are used in this Registration Document: “2018 PRMS” . . . . . . . . . . . . . . . the 2018 Petroleum Resources Management System; “2C resources” . . . . . . . . . . . . . . best estimate scenario of contingent resources; “1P reserves” . . . . . . . . . . . . . . . proved reserves; “2P reserves” . . . . . . . . . . . . . . . proved plus probable reserves; “3P reserves” . . . . . . . . . . . . . . . proved plus probable plus possible reserves; “Abigail” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Abigail (formerly known as Hurricane) located in block 29/10b ALL in the UKCS; “AFE” . . . . . . . . . . . . . . . . . . . . authorisation for expenditure; “Alba” . . . . . . . . . . . . . . . . . . . . the oil field commonly known as Alba field located in blocks 16/26a A ALB (Area A Alba Field Area), 16/26a C-10k (Area C Above 10,000 Feet) and 22/1b ALL in the UKCS; “Alba FSU” . . . . . . . . . . . . . . . . . the floating storage unit that is connected to Alba; “Alder” . . . . . . . . . . . . . . . . . . . . the oil field commonly known as Alder field located in blocks 15/29a ALDER (Alder Field) and 15/29a AREA A (Area Outside Britannia) in the UKCS; “Anglia” . . . . . . . . . . . . . . . . . . . the gas field which was commonly known as the Anglia field and which was located in blocks 48/18b and 48/19b in the UKCS; “ANP” . . . . . . . . . . . . . . . . . . . . Alba North Platform; “API” . . . . . . . . . . . . . . . . . . . . . American Petroleum Institute; “Arbroath” . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Arbroath located in blocks 22/17n ALL, 22/17s ALL, 22/18a ALL and 22/22a ALL in the UKCS; “Arkwright” . . . . . . . . . . . . . . . . . the oil field commonly known as Arkwright field located in block 22/23a ALL in the UKCS; “ASM” . . . . . . . . . . . . . . . . . . . . Andrew Sand Member; “Athena” . . . . . . . . . . . . . . . . . . the oil field commonly known as Athena located in block 14/18b ALL in the UKCS; “Austen” . . . . . . . . . . . . . . . . . . the discovery commonly known as Austen located in block 30/13b ALL in the UKCS; “AXS” . . . . . . . . . . . . . . . . . . . . Alba Extreme South; “BBL” . . . . . . . . . . . . . . . . . . . . barrels; “bcm” . . . . . . . . . . . . . . . . . . . . billion cubic meters; “Best Available Techniques” or “BAT” . . . . . . . . . . . . . . . . . the available techniques which are the best for preventing or minimising emissions and impacts on the environment; “Birgitta” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Birgitta located in block 22/19a ALL in the UKCS; “Blackrock” . . . . . . . . . . . . . . . . the oil and gas field commonly known as Blackrock located in blocks 204/4b ALL and 204/5b ALL in the UKCS; “BLP” . . . . . . . . . . . . . . . . . . . . Bridge Linked Platform; 399
“BOE” . . . . . . . . . . . . . . . . . . . . barrels of oil equivalent “boepd” . . . . . . . . . . . . . . . . . . . barrels of oil equivalent per day; “BOPD” . . . . . . . . . . . . . . . . . . . barrels of oil per day; “BPGM” . . . . . . . . . . . . . . . . . . . BP Gas Marketing Limited; “BPOI” . . . . . . . . . . . . . . . . . . . . BP Oil International; “Brechin” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Brechin located in block 22/23a ALL in the UKCS; “Britannia” . . . . . . . . . . . . . . . . . the gas condensate field commonly known as Britannia field located in blocks 15/30a S BRI (Area S—Britannia Field), Area 15/30a L-RST (Area L Non-Britannia), 15/29a AREA B (Britannia UOA), 15/29a AREA C (Non-Britannia UOA), 16/26a B BRI (Area B—Britannia Field), 16/26a D BEL, 16/27b AREA B (Britannia Field) and 16/27b AREA A (Rest of Block—Excluding Britania) in the UKCS; “Brodgar” . . . . . . . . . . . . . . . . . . the oil field commonly known as Brodgar field located in blocks 21/3a ALL, 21/3b ALL and 21/4c ALL in the UKCS; “Broom” . . . . . . . . . . . . . . . . . . the oil field commonly known as Broom located in blocks 2/4a (BROOM) and 2/5a (BROOM) in the UKCS; “BWPD” . . . . . . . . . . . . . . . . . . barrels of water per day; “Cadet” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Cadet located in block 8/15a ALL in the UKCS; “Callanish” . . . . . . . . . . . . . . . . the oil field commonly known as Callanish field located in blocks 21/4a ALL and 15/29b ALL in the UKCS; “Cambo” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Cambo located in blocks 204/9a ALL, 204/10a ALL, 204/4a ALL and 204/5a ALL in the UKCS; “Captain” . . . . . . . . . . . . . . . . . . the oil field commonly known as Captain field located in blocks 13/22a ALL, 13/21b ALL and 13/22b ALL in the UKCS; “Captain EOR” . . . . . . . . . . . . . . the on-going polymer EOR development programme of Captain which commenced in 2010; “Captain EOR II” . . . . . . . . . . . . the second phase of the Captain EOR, which was sanctioned in April 2021 following consent from the NSTA; “Captain FPSO” . . . . . . . . . . . . . the floating production storage and offtake vessel known as the ‘Captain FPSO’ located in block 13/22a in the UKCS; “CATS” . . . . . . . . . . . . . . . . . . . the Central Area Transmission System; “Cayley” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Cayley located in block 22/17s ALL in the UKCS; “CGU” . . . . . . . . . . . . . . . . . . . . a cash generating unit; “CMS” . . . . . . . . . . . . . . . . . . . . Company Management System; “CO 2 ” . . . . . . . . . . . . . . . . . . . . carbon dioxide; “CO 2 e” . . . . . . . . . . . . . . . . . . . carbon dioxide equivalent; “Columba” or “Columba Terraces Area” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Columba located in blocks 3/7a AREA B (Part of Columba B and Columba E Fields), 3/8a COLB (Columba B Reservoir), 3/8a COLD (Columba D Reservoir); 400
“Conrie” . . . . . . . . . . . . . . . . . . the oil field commonly known as Conrie located in block 211/18a (B) (Don South West Area) in the UKCS; “contingent resources” . . . . . . . . quantities of petroleum estimated, as at a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies; “Cook” . . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Cook located in block 21/20a ALL of the UKCS; “Courageous” . . . . . . . . . . . . . . . the oil and gas field commonly known as Courageous located in blocks 30/1e ALL and 30/2e ALL in the UKCS, which was relinquished by the Group with an effective date of 30 September 2022; “cp” . . . . . . . . . . . . . . . . . . . . . . centipoise; “D” . . . . . . . . . . . . . . . . . . . . . . darcy; “Dons” . . . . . . . . . . . . . . . . . . . the Don South West, West Don, Conrie and Ythan fields; “Don South West” . . . . . . . . . . . . the oil field commonly known as Don South West located in block 211/18a (Don South West Area) in the UKCS; “D&P” . . . . . . . . . . . . . . . . . . . . development and production; “DRD” . . . . . . . . . . . . . . . . . . . . decommissioning relief deed; “E&E” . . . . . . . . . . . . . . . . . . . . exploration and evaluation; “Elgin-Franklin” . . . . . . . . . . . . . . the oil and gas field commonly known as Elgin-Franklin located in blocks 22/30b ELGN (Area A—Elgin-Field), 22/30c ALL, 29/5c ALL and 29/5b ALL in the UKCS; “EMS” . . . . . . . . . . . . . . . . . . . . environmental management system; “Enochdhu” . . . . . . . . . . . . . . . . the oil field commonly known as Enochdhu field located in block 21/5a ALL in the UKCS; “EOR” . . . . . . . . . . . . . . . . . . . . enhanced oil recovery; “Erskine” . . . . . . . . . . . . . . . . . . the oil field commonly known as Erskine field located in blocks 23/26a AREA B, 23/26b AREA B, 23/26b AREA C and 23/26d AREA C in the UKCS; “ES” . . . . . . . . . . . . . . . . . . . . . Environmental Stewardship; “ESP” . . . . . . . . . . . . . . . . . . . . electric submersible pump; “Fotla” . . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Fotla located in block 22/1b ALL in the UKCS; “FPF-1” . . . . . . . . . . . . . . . . . . . the offshore floating production facility owned by the Group known as FPF-1; “FPS” . . . . . . . . . . . . . . . . . . . . . the Forties Pipeline System; “FPSO” . . . . . . . . . . . . . . . . . . . a floating production, storage and offloading vessel used by the offshore oil and gas industry for the processing of hydrocarbons and for storage of oil; “FPU” . . . . . . . . . . . . . . . . . . . . a floating production unit used by the offshore oil and gas industry for the processing of hydrocarbons; “GAEL” . . . . . . . . . . . . . . . . . . . the Graben Area Export Line pipeline; “Glen Lyon FPSO” . . . . . . . . . . . the floating production storage and offtake vessel known as the ‘Glen Lyon’ located in block 204/25a (ALL) in the UKCS; 401
“Godwin” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Godwin located in blocks 22/17s ALL and 22/17n ALL in the UKCS; “GOR” . . . . . . . . . . . . . . . . . . . . gas-oil ratio; “Greater Britannia Area” . . . . . . . the Britannia, Brodgar, Callanish, Enochdhu and Alder fields; “Greater Stella Area” ., “GSA” or “GSA Portfolio” . . . . . . . . . . . . the Stella, Harrier, Abigail, Vorlich, Austen and Courageous fields; “Harrier” . . . . . . . . . . . . . . . . . . . the oil and gas field currently known as Harrier located in blocks 30/6a (D) (Rest of Block (Chalk Layers and Younger)) and 29/10a (C) in the UKCS; “Heather” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as the Heather field located in block 2/5a in the UKCS; “IEA” . . . . . . . . . . . . . . . . . . . . . International Energy Agency; “IMO Guidelines” . . . . . . . . . . . . the IMO guidelines and standards for the removal of offshore installations and structures on the continental shelf and in the exclusive economic zone; “Isabella” . . . . . . . . . . . . . . . . . . the oil field commonly known as Isabella located in blocks 30/12d ALL and 30/11a ALL in the UKCS; “Jacky” . . . . . . . . . . . . . . . . . . . the oil field commonly known as Jacky located in block 12/21c ALL in the UKCS; “Jade” . . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Jade located in blocks 30/2c JADE, 30/2c REST and 30/7b JADE SOUTH in the UKCS; “Jade South” . . . . . . . . . . . . . . . the oil and gas field commonly known as Jade South located in block 30/7b JADE SOUTH in the UKCS; “J-Block Facility” . . . . . . . . . . . . the Judy Platform and associated pipeline infrastructure commonly known as the J-Block Gas Pipeline and the J-Block Crude Petroleum Pipeline; “Leverett” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Leverett located in blocks 21/2d ALL and 21/3a ALL in the UKCS; “Marigold” . . . . . . . . . . . . . . . . . the oil field commonly known as Marigold (comprised of the Yeoman and Marigold discoveries) located in block 15/18b ALL in the UKCS; “Mariner” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Mariner located in blocks 9/11a ALL, 9/11c ALL and 9/11g ALL in the UKCS; “Mariner East” . . . . . . . . . . . . . . the oil and gas field commonly known as Mariner East located in block 9/11b ALL in the UKCS; “MCF” . . . . . . . . . . . . . . . . . . . . thousands of cubic feet; “MBBL” . . . . . . . . . . . . . . . . . . . thousands of barrels; “MBOE” . . . . . . . . . . . . . . . . . . . thousands of barrels of oil equivalent; “MCFD” . . . . . . . . . . . . . . . . . . . thousands of cubic feet per day; “MMBBL” . . . . . . . . . . . . . . . . . . millions of barrels; “MMBBL/d” . . . . . . . . . . . . . . . . . million barrels per day; “MMBOE” . . . . . . . . . . . . . . . . . . millions of barrels of oil equivalent; “MMCF” . . . . . . . . . . . . . . . . . . . millions of cubic feet; “MMCFD” . . . . . . . . . . . . . . . . . . millions of cubic feet of gas per day; 402
“model clauses” . . . . . . . . . . . . . the model clauses set out in the statutory instruments deriving from the UK Petroleum Act 1998; “MonArb” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as MonArb located in blocks 22/17n ALL, 22/18A ALL 22/18n ALL, 22/17s ALL, 22/22a ALL, 22/23a ALL and 22/18a ALL in the UKCS; “Montrose” . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Montrose located in blocks 22/17n ALL and 22/18n ALL in the UKCS; “NGL” . . . . . . . . . . . . . . . . . . . . natural gas liquids; “Norsea Facility” . . . . . . . . . . . . . the processing and terminal facilities constructed on sites near Teeside, England commonly known as ‘Norsea’ and operated by ConocoPhillips Petroleum Company UK; “OECD” . . . . . . . . . . . . . . . . . . . the Organisation for Economic Cooperation and Development; “OPEC” . . . . . . . . . . . . . . . . . . . the Organisation of Petroleum Exporting Countries; “OPPC” . . . . . . . . . . . . . . . . . . . the UK Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005; “OPRED” . . . . . . . . . . . . . . . . . . the Offshore Petroleum Regulator for Environment and Decommissioning; “OSPAR” . . . . . . . . . . . . . . . . . . the 1992 Oslo and Paris Convention for the Protection of the Marine Environment of the North East Atlantic; “Petroleum Act” . . . . . . . . . . . . . the Petroleum Act 1998, as amended; “Pickerill” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Pickerill located in block 48/11a in the UKCS; “Pierce” . . . . . . . . . . . . . . . . . . . the oil field commonly known as Pierce located in blocks 23/22a ALL and 23/27a ALL in the UKCS; “possible reserves” . . . . . . . . . . . additional reserves that analysis of geoscience and engineering data indicates are less likely to be recoverable than probable reserves; “PPC” . . . . . . . . . . . . . . . . . . . . the UK Offshore Combustion Installations (Pollution Prevention and Control) Regulations 2013; “probable reserves” . . . . . . . . . . . additional reserves that analysis of geoscience and engineering data indicates are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves; “proved reserves” . . . . . . . . . . . . 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; “R/P” . . . . . . . . . . . . . . . . . . . . . reserves to production; “Renee” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Renee located in block 15/27a in the UKCS; “reserves” . . . . . . . . . . . . . . . . . quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under define conditions; “RFES” . . . . . . . . . . . . . . . . . . . ring fence expenditure supplements; 403
“Rosebank” . . . . . . . . . . . . . . . . the oil and gas field commonly known as Rosebank located in blocks 213/26b ALL, 213/27a ALL, 205/1a ALL, 205/2a ALL in the UKCS; “Rubie” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Rubie located in block 15/28b in the UKCS; “SAGE” . . . . . . . . . . . . . . . . . . . the Scottish Area Gas Evacuation System; “Schiehallion” . . . . . . . . . . . . . . . the oil and gas field commonly known as Schiehallion located in blocks 204/20a and 204/25a ALL in the UKCS; “SEAL” . . . . . . . . . . . . . . . . . . . the Shearwater Elgin Area Line pipeline; “SEGAL” . . . . . . . . . . . . . . . . . . Shell-Esso Gas and Liquids; “Shaw” . . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Shaw located in block 22/22a ALL in the UKCS; “SIRGE” . . . . . . . . . . . . . . . . . . . the Shetland Islands Regional Gas Export System; “SMS” . . . . . . . . . . . . . . . . . . . . Safety Management System; “Stella” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Stella located in blocks 30/6a (D) and 29/10a (C) in the UKCS; “Strathspey” . . . . . . . . . . . . . . . . the oil and gas field commonly known as the Strathspey field located in blocks 3/4a, AREA B and 3/4D, AREA B in the UKCS; “Sulliven” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Sulliven located in blocks 204/19b ALL and 205/20b ALL in the UKCS; “TCFD” . . . . . . . . . . . . . . . . . . . Taskforce on Climate-related Financial Disclosures; “TGLPT” . . . . . . . . . . . . . . . . . . . Teesside Gas and Liquids Processing terminal; “Thundercat” . . . . . . . . . . . . . . . the oil field commonly known as Thundercat field located in blocks 14/23 ALL, 14/24 ALL, 14/28 ALL and 14/29b ALL in the UKCS; “Tornado” . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as Tornado located in blocks 204/13 ALL and 204/14d ALL in the UKCS; “TRIF” . . . . . . . . . . . . . . . . . . . . Total Recorded Injury Frequency; “TVDSS” . . . . . . . . . . . . . . . . . . true vertical depth subsea; “UCS” . . . . . . . . . . . . . . . . . . . . Upper Captain Sandstone; “UK NBP” . . . . . . . . . . . . . . . . . . the UK National Balancing Point; “ullage” . . . . . . . . . . . . . . . . . . . the volume of empty space left in a pipeline, container, cargo tank or storage tanks in cargo ships and oil terminal tanks; “UNCLOS” . . . . . . . . . . . . . . . . . the United Nations Convention on the Law of the Sea 1982; “Vorlich” . . . . . . . . . . . . . . . . . . . the oil and gas field commonly known as the Vorlich field located in blocks 30/1c LOWER 30/1c UPPER and 30/1f ALL in the UKCS; “West Don” . . . . . . . . . . . . . . . . the oil field commonly known as West Don located in blocks 211/18a (West Don Area) and 211/13b in the UKCS; “Wood” . . . . . . . . . . . . . . . . . . . the oil field commonly known as Wood field located in block 22/18a ALL in the UKCS; “WOSPS” . . . . . . . . . . . . . . . . . . the West of Shetland Gas Pipeline; “Ythan” . . . . . . . . . . . . . . . . . . . the oil field commonly known as Ythan located in block 211/18e YTHAN in the UKCS. 404
PART 18—COMPETENT PERSON’S REPORT 405
ESTIMATES of RESERVES AND FUTURE REVENUE AND CONTINGENT RESOURCES AND CASH FLOW to the ITHACA ENERGY (UK) LIMITED INTEREST in CERTAIN OIL AND GAS PROPERTIES located in the UNITED KINGDOM SECTOR OF THE NORTH SEA AND IN THE NORTH ATLANTIC OCEAN as of JUNE 30, 2022 COMPETENT PERSON'S REPORT BASED ON ESCALATED PRICE AND COST PARAMETERS specified by ITHACA ENERGY (UK) LIMITED
October 18, 2022 Mr. John Horsburgh Ithaca Energy (UK) Limited Hill of Rubislaw Aberdeen AB15 6Xl United Kingdom Dear Mr. Horsburgh: In accordance with your request, we have estimated the proved, probable, and possible reserves and future revenue, as of June 30, 2022, to the Ithaca Energy (UK) Limited (referred to herein as "Ithaca") interest in certain oil and gas properties located in the United Kingdom (UK) Sector of the North Sea and in the North Atlantic Ocean. Also as requested, we have estimated the contingent resources and cash flow, as of June 30, 2022, to the Ithaca interest in certain discoveries located in the UK Sector of the North Sea and in the North Atlantic Ocean. We completed our evaluation on August 15, 2022. This Competent Person's Report (report) has been prepared using escalated price and cost parameters specified by Ithaca, as discussed in subsequent paragraphs of this letter. Monetary values shown in this report are expressed in United States dollars ($) or thousands of United States dollars (M$) using Ithaca's estimated exchange rate, which escalates from $1.28 to 1.00 British pound sterling in 2022 to $1.40 to 1.00 British pound sterling in 2025. Working interest volumes shown in this report are after deductions for shrinkage to account for processing, fuel, and flare. The estimates in this report have been prepared in accordance with the definitions and guidelines set forth in the 2018 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE) and in accordance with the recommendations of the Financial Conduct Authority (FCA), as set out in Primary Market Technical Note 619.1 – the Guidelines on disclosure requirements under the Prospectus Regulation and Guidance on specialist issuers published by the FCA. As presented in the 2018 PRMS, petroleum accumulations can be classified, in decreasing order of likelihood of commerciality, as reserves, contingent resources, or prospective resources. Different classifications of petroleum accumulations have varying degrees of technical and commercial risk that are difficult to quantify; thus reserves, contingent resources, and prospective resources should not be aggregated without extensive consideration of these factors. Definitions are presented immediately following this letter. Following the definitions are certificates of qualification for the primary evaluators who contributed to this report, a list of abbreviations used in this report, and portfolio summary tables. This report has been prepared for use by Ithaca in connection with a proposed initial public offering. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. RESERVES ________________________________________________________________________ Reserves are those quantities of petroleum anticipated to be commercially recoverable from known accumulations by application of development projects from a given date forward under defined conditions. Reserves must be discovered, recoverable, commercial, and remaining as of the evaluation date based on the planned development projects to be applied. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be commercially recoverable; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.
October 18, 2022 Page 2 of 6 We estimate the Ithaca working interest reserves and the future net revenue after UK corporate income taxes to the Ithaca interest in these properties, as of June 30, 2022, to be: Working Interest Reserves Future Net Revenue After UK Corporate Income Taxes (M$) Oil Gas NGL Present Worth Category (MBBL) (MMCF) (MBBL) Total at 10% Proved (1P) 114,446.9 223,854.2 05,840.7 4,111,140.2 3,985,975.0 Probable 062,294.7 113,616.6 03,091.0 2,669,142.0 1,841,135.4 Proved + Probable (2P) 176,741.6 337,470.8 08,931.8 6,780,282.2 5,827,110.4 Possible 072,292.6 131,265.7 03,644.8 2,946,963.9 1,812,942.5 Proved + Probable + Possible (3P) 249,034.2 468,736.5 12,576.5 9,727,246.0 7,640,053.0 Totals may not add because of rounding. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Oil equivalent volumes shown in this report are expressed in thousands of barrels of oil equivalent (MBOE), determined using the ratio of 5.8 MCF of gas to 1 barrel of oil. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The 1P reserves are inclusive of proved developed producing, proved developed non-producing, and proved undeveloped reserves. The project maturity subclass for these reserves is on production. The estimates of reserves and future revenue included herein have not been adjusted for risk. Working interest revenue for the reserves is Ithaca's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Ithaca's share of royalties, capital costs, abandonment costs, operating expenses, and estimates of UK corporate income taxes. The UK corporate income taxes have been calculated using a simplified model based on existing tax pools and abandonment tax relief; the values of the tax pools effective June 30, 2022, were provided by Ithaca. The UK corporate income taxes include estimates of the Energy Profits Levy introduced in 2022; it is our understanding that this tax applies to profits earned through 2025. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Ithaca interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Ithaca receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.
October 18, 2022 Page 3 of 6 CONTINGENT RESOURCES __________________________________________________________ Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by the application of development project(s) not currently considered to be commercial owing to one or more contingencies. The contingent resources shown in this report are contingent upon commitment to develop the resources for all fields; finalization of development plans for Alder, Cadet, Callanish, Cambo, Captain, Elgin-Franklin, Erskine, Fotla, Harrier, Isabella, Leverett, Marigold, Mariner, Mariner East, Pierce, Rosebank, Schiehallion, and Tornado Fields; finalization of commercial terms for subsea tieback for Tornado Field; and confirmation of technical feasibility for polymer injection in Mariner Field. The costs required to resolve these contingencies have not been included in this report; estimates of cash flow are based on the assumption that all contingencies will be successfully addressed. If these contingencies are successfully addressed, some portion of the contingent resources estimated in this report may be reclassified as reserves; our estimates have not been risked to account for the possibility that the contingencies are not successfully addressed. The project maturity subclass for these contingent resources is development pending for Alba, Alder, Callanish, Cambo, Captain, Cook, Courageous, Elgin-Franklin, Erskine, Fotla, Harrier, Isabella, Leverett, Marigold, Pierce, Rosebank, Stella, Tornado, and Vorlich Fields. The project maturity subclass for these contingent resources is development unclarified for Cadet, Mariner, Mariner East, and Schiehallion Fields. We estimate the Ithaca working interest contingent resources and the net contingent cash flow after UK corporate income taxes to the Ithaca interest in these properties, as of June 30, 2022, to be: Working Interest Contingent Resources Net Contingent Cash Flow After UK Corporate Income Taxes (M$) Oil Gas NGL Discounted Category (MBBL) (MMCF) (MBBL) Total at 10% Low Estimate (1C) 125,164.4 253,636.8 0,723.6 04,401,099.1 1,958,529.3 Best Estimate (2C) 232,174.4 398,268.5 0,841.5 09,427,221.8 3,994,985.5 High Estimate (3C) 369,382.1 587,234.7 1,324.0 17,723,131.7 6,919,249.3 The oil volumes shown include crude oil and condensate. The contingent resources shown in this report have been estimated using deterministic methods. Once all contingencies have been successfully addressed, the approximate probability that the quantities of contingent resources actually recovered will equal or exceed the estimated amounts is generally inferred to be 90 percent for the low estimate, 50 percent for the best estimate, and 10 percent for the high estimate. For the purposes of this report, the volumes and parameters associated with the low, best, and high estimate scenarios of contingent resources are referred to as 1C, 2C, and 3C, respectively. The estimates of contingent resources included herein have not been adjusted for development risk. Working interest contingent revenue is Ithaca's share of the gross (100 percent) revenue from the properties prior to any deductions. Net contingent cash flow is after deductions for Ithaca's share of royalties, capital costs, abandonment costs, operating expenses, and estimates of UK corporate income taxes. The UK corporate income taxes have been calculated using a simplified model based on existing tax pools and abandonment tax relief; the values of the tax pools effective June 30, 2022, were provided by Ithaca. The UK corporate income taxes include estimates of the Energy Profits Levy introduced in 2022; it is our understanding that this tax applies to profits earned through 2025. The net contingent cash flow has been discounted at an annual rate of 10 percent to indicate the effect of time on the value of money; the contingent cash flow, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
October 18, 2022 Page 4 of 6 ECONOMIC PARAMETERS ___________________________________________________________ As requested, this report has been prepared using oil, NGL, and gas price parameters specified by Ithaca. Oil and NGL prices are based on Brent Crude futures prices and are adjusted by field for quality, transportation fees, and market differentials. Gas prices are based on National Balancing Point futures prices and are adjusted by field for energy content, transportation fees, and market differentials. All prices, before adjustments, along with escalation parameters are shown in the following table: Period Oil/NGL Price Gas Price Ending ($/Barrel) ($/MMBTU) 12-31-2022 103.00 33.796 12-31-2023 095.00 25.321 12-31-2024 085.00 16.371 12-31-2025 078.00 13.079 12-31-2026 079.00 10.867 12-31-2027 080.00 11.084 12-31-2028 082.00 11.307 12-31-2029 083.00 11.533 12-31-2030 085.00 11.762 12-31-2031 087.00 11.998 12-31-2032 090.00 12.238 Period Oil/NGL Price Gas Price Ending ($/Barrel) ($/MMBTU) 12-31-2033 092.00 12.483 12-31-2034 095.00 12.732 12-31-2035 097.00 12.987 12-31-2036 100.00 13.247 12-31-2037 103.00 13.512 12-31-2038 106.00 13.782 12-31-2039 108.00 14.058 12-31-2040 112.00 14.339 Thereafter, escalated 2 percent on January 1 of each year. Operating costs used in this report are based on operating expense records and estimates of Ithaca or the previous operator of the properties. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the area and field levels. Britannia Field and its satellites (Alder, Brodgar, Callanish, and Enochdhu Fields) have a cost sharing agreement to distribute the costs of operating the Britannia platform. Abigail, Courageous, Harrier, Stella, and Vorlich Fields have a cost sharing agreement to distribute the costs of operating FPF-1. Operating costs have been divided into area-level costs, field-level costs, per-well costs, per-unit-of-production costs, and polymer purchase costs for Mariner Field; the cost sharing agreement costs are modeled as field-level costs. Headquarters general and administrative overhead expenses of Ithaca are included to the extent that they are covered under joint operating agreements for the operated properties. As requested, operating costs are escalated 2 percent on January 1 of each year throughout the lives of the properties. Capital costs used in this report were provided by Ithaca and are based on authorizations for expenditure, internal planning budgets, and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, production equipment, and polymer purchase for Captain Field. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Ithaca's or the operators' estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. As requested, capital costs and abandonment costs are escalated 2 percent on January 1 of each year to the date of expenditure.
October 18, 2022 Page 5 of 6 GENERAL INFORMATION ____________________________________________________________ As shown in the Table of Contents, this report includes summary projections of reserves and revenue by reserves category and summary projections of resources and cash flow by resources category. Also included are a technical discussion and pertinent figures. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves and contingent resources have been estimated. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. The reserves and contingent resources shown in this report are estimates only and should not be construed as exact quantities. Estimates may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Ithaca, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the volumes, and that our projections of future production will prove consistent with actual performance. If these volumes are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received, and costs incurred may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves and contingent resources in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A portion of the reserves shown in this report are for non-producing zones and undeveloped locations, and the contingent resources shown in this report are for undeveloped locations. Such volumes are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment. For the purposes of UK Prospectus Regulation Rule 5.3.2R(2)(f), Netherland, Sewell & Associates, Inc. (NSAI) accepts responsibility for the information contained in this report and confirms that, to the best of our knowledge, the information contained in this report is in accordance with the facts and makes no omission likely to affect its import. In connection with our engagement by Ithaca to perform consulting petroleum engineering, geological, geophysical, petrophysical, or property evaluation work, Ithaca indemnifies and holds harmless NSAI, each person who controls it, and each employee of it and each consultant or contractor engaged by it from and against any and all losses, claims, damages, expenses, or liabilities, joint or several, to which they or any of them may become subject in connection with the performance of such consulting work or the preparation of such evaluations or the reliance thereon by Ithaca or any other party. Ithaca does not indemnify NSAI with respect to losses, claims, damages, expenses, or liability arising from the gross negligence or willful misconduct of NSAI.
October 18, 2022 Page 6 of 6 The data used in our estimates were obtained from Ithaca, public data sources, and the nonconfidential files of NSAI and were accepted as accurate. Supporting work data are on file in our office. We have not examined the contractual rights to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 By: C.H. (Scott) Rees III, P.E. Executive Chairman By: By: Derek F. Newton, P.E. 97689 Shane M. Howell, P.G 11276 Senior Vice President Vice President Date Signed: October 18, 2022 Date Signed: October 18, 2022 DFN:NFH
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 1 of 10 This document contains information excerpted from definitions and guidelines prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the SPE, World Petroleum Council, American Association of Petroleum Geologists, Society of Petroleum Evaluation Engineers, Society of Exploration Geophysicists, Society of Petrophysicists and Well Log Analysts, and European Association of Geoscientists & Engineers. Preamble Petroleum resources are the quantities of hydrocarbons naturally occurring on or within the Earth's crust. Resources assessments estimate quantities in known and yet-to-be-discovered accumulations. Resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating projects, and presenting results within a comprehensive classification framework. This updated PRMS provides fundamental principles for the evaluation and classification of petroleum reserves and resources. If there is any conflict with prior SPE and PRMS guidance, approved training, or the Application Guidelines, the current PRMS shall prevail. It is understood that these definitions and guidelines allow flexibility for entities, governments, and regulatory agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein must be clearly identified. The terms "shall" or "must" indicate that a provision herein is mandatory for PRMS compliance, while "should" indicates a recommended practice and "may" indicates that a course of action is permissible. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements. 1.0 Basic Principles and Definitions 1.0.0.1 A classification system of petroleum resources is a fundamental element that provides a common language for communicating both the confidence of a project's resources maturation status and the range of potential outcomes to the various entities. The PRMS provides transparency by requiring the assessment of various criteria that allow for the classification and categorization of a project's resources. The evaluation elements consider the risk of geologic discovery and the technical uncertainties together with a determination of the chance of achieving the commercial maturation status of a petroleum project. 1.0.0.2 The technical estimation of petroleum resources quantities involves the assessment of quantities and values that have an inherent degree of uncertainty. These quantities are associated with exploration, appraisal, and development projects at various stages of design and implementation. The commercial aspects considered will relate the project's maturity status (e.g., technical, economical, regulatory, and legal) to the chance of project implementation. 1.0.0.3 The use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios. The application of PRMS must consider both technical and commercial factors that impact the project's feasibility, its productive life, and its related cash flows. 1.1 Petroleum Resources Classification Framework 1.1.0.1 Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid state. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide, and sulfur. In rare cases, non-hydrocarbon content can be greater than 50%. 1.1.0.2 The term resources as used herein is intended to encompass all quantities of petroleum naturally occurring within the Earth's crust, both discovered and undiscovered (whether recoverable or unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered as conventional or unconventional resources. 1.1.0.3 Figure 1.1 graphically represents the PRMS resources classification system. The system classifies resources into discovered and undiscovered and defines the recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable Petroleum. 1.1.0.4 The horizontal axis reflects the range of uncertainty of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the chance of commerciality, P c , which is the chance that a project will be committed for development and reach commercial producing status.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 2 of 10 1.1.0.5 The following definitions apply to the major subdivisions within the resources classification: A. Total Petroleum Initially-In-Place (PIIP) is all quantities of petroleum that are estimated to exist originally in naturally occurring accumulations, discovered and undiscovered, before production. B. Discovered PIIP is the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations before production. C. Production is the cumulative quantities of petroleum that have been recovered at a given date. While all recoverable resources are estimated, and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Section 3.2, Production Measurement). 1.1.0.6 Multiple development projects may be applied to each known or unknown accumulation, and each project will be forecast to recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into commercial, sub-commercial, and undiscovered, with the estimated recoverable quantities being classified as Reserves, Contingent Resources, or Prospective Resources respectively, as defined below. A. 1. Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: discovered, recoverable, commercial, and remaining (as of the evaluation's effective date) based on the development project(s) applied. 2. Reserves are recommended as sales quantities as metered at the reference point. Where the entity also recognizes quantities consumed in operations (CiO) (see Section 3.2.2), as Reserves these quantities must be recorded separately. Non- hydrocarbon quantities are recognized as Reserves only when sold together with hydrocarbons or CiO associated with petroleum production. If the non-hydrocarbon is separated before sales, it is excluded from Reserves. 3. Reserves are further categorized in accordance with the range of uncertainty and should be sub-classified based on project maturity and/or characterized by development and production status. B. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, by the application of development project(s) not currently considered to be commercial owing to one or more contingencies. Contingent Resources have an associated chance of development. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the range of uncertainty associated with the estimates and should be sub-classified based on project maturity and/or economic status. C. Undiscovered PIIP is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered. D. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of geologic discovery and a chance of development. Prospective Resources are further categorized in accordance with the range of uncertainty associated with recoverable estimates, assuming discovery and development, and may be sub- classified based on project maturity. E. Unrecoverable Resources are that portion of either discovered or undiscovered PIIP evaluated, as of a given date, to be unrecoverable by the currently defined project(s). A portion of these quantities may become recoverable in the future as commercial circumstances change, technology is developed, or additional data are acquired. The remaining portion may never be recovered because of physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. 1.1.0.7 The sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as "remaining recoverable resources." Importantly, these quantities should not be aggregated without due consideration of the technical and commercial risk involved with their classification. When such terms are used, each classification component of the summation must be provided. 1.1.0.8 Other terms used in resource assessments include the following: A. Estimated Ultimate Recovery (EUR) is not a resources category or class, but a term that can be applied to an accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable plus those quantities already produced from the accumulation or group of accumulations. For clarity, EUR must reference the associated technical and commercial conditions for the resources; for example, proved EUR is Proved Reserves plus prior production. B. Technically Recoverable Resources (TRR) are those quantities of petroleum producible using currently available technology and industry practices, regardless of commercial considerations. TRR may be used for specific Projects or for groups of Projects, or, can be an undifferentiated estimate within an area (often basin-wide) of recovery potential.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 3 of 10 PROJECT (production/cash flow) Net Recoverable Resources Entitlement PROPERTY (ownership/contract terms) RESERVOIR (in-place volumes) Figure 1.2—Resources evaluation 1.2 Project-Based Resources Evaluations 1.2.0.1 The resources evaluation process consists of identifying a recovery project or projects associated with one or more petroleum accumulations, estimating the quantities of PIIP, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on maturity status or chance of commerciality. 1.2.0.2 The concept of a project-based classification system is further clarified by examining the elements contributing to an evaluation of net recoverable resources (see Figure 1.2). 1.2.0.3 The reservoir (contains the petroleum accumulation): Key attributes include the types and quantities of PIIP and the fluid and rock properties that affect petroleum recovery. 1.2.0.4 The project: A project may constitute the development of a well, a single reservoir, or a small field; an incremental development in a producing field; or the integrated development of a field or several fields together with the associated processing facilities (e.g., compression). Within a project, a specific reservoir's development generates a unique production and cash-flow schedule at each level of certainty. The integration of these schedules taken to the project's earliest truncation caused by technical, economic, or the contractual limit defines the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to total PIIP quantities defines the project's recovery efficiency. Each project should have an associated recoverable resources range (low, best, and high estimate). 1.2.0.5 The property (lease or license area): Each property may have unique associated contractual rights and obligations, including the fiscal terms. This information allows definition of each participating entity's share of produced quantities (entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A property may contain both discovered and undiscovered accumulations that may be spatially unrelated to a potential single field designation. 1.2.0.6 An entity's net recoverable resources are the entitlement share of future production legally accruing under the terms of the development and production contract or license. 1.2.0.7 In the context of this relationship, the project is the primary element considered in the resources classification, and the net recoverable resources are the quantities derived from each project. A project represents a defined activity or set of activities to develop the petroleum accumulation(s) and the decisions taken to mature the resources to reserves. In general, it is recommended that an individual project has assigned to it a specific maturity level sub-class (See Section 2.1.3.5, Project Maturity Sub-Classes) at which a decision is made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable quantities for the project (See Section 2.2.1, Range of Uncertainty). For completeness, a developed field is also considered to be a project. 1.2.0.8 An accumulation or potential accumulation of petroleum is often subject to several separate and distinct projects that are at different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resources classes simultaneously. 1.2.0.10 Not all technically feasible development projects will be commercial. The commercial viability of a development project within a field's development plan is dependent on a forecast of the conditions that will exist during the time period encompassed by the project (see Section 3.1, Assessment of Commerciality). Conditions include technical, economic (e.g., hurdle rates, commodity prices), operating and capital costs, marketing, sales route(s), and legal, environmental, social, and governmental factors forecast to exist and impact the project during the time period being evaluated. While economic factors can be summarized as forecast costs and product prices, the underlying influences include, but are not limited to, market conditions (e.g., inflation, market factors, and contingencies), exchange rates, transportation and processing infrastructure, fiscal terms, and taxes. 1.2.0.11 The resources being estimated are those quantities producible from a project as measured according to delivery specifications at the point of sale or custody transfer (see Section 3.2.1, Reference Point) and may permit forecasts of CiO quantities (see Section 3.2.2., Consumed in Operations). The cumulative production forecast from the effective date forward to cessation of production is the remaining recoverable resources quantity (see Section 3.1.1, Net Cash-Flow Evaluation).
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 4 of 10 1.2.0.12 The supporting data, analytical processes, and assumptions describing the technical and commercial basis used in an evaluation must be documented in sufficient detail to allow, as needed, a qualified reserves evaluator or qualified reserves auditor to clearly understand each project's basis for the estimation, categorization, and classification of recoverable resources quantities and, if appropriate, associated commercial assessment. 2.0 Classification and Categorization Guidelines 2.1 Resources Classification 2.1.0.1 The PRMS classification establishes criteria for the classification of the total PIIP. A determination of a discovery differentiates between discovered and undiscovered PIIP. The application of a project further differentiates the recoverable from unrecoverable resources. The project is then evaluated to determine its maturity status to allow the classification distinction between commercial and sub-commercial projects. PRMS requires the project's recoverable resources quantities to be classified as either Reserves, Contingent Resources, or Prospective Resources. 2.1.1 Determination of Discovery Status 2.1.1.1 A discovered petroleum accumulation is determined to exist when one or more exploratory wells have established through testing, sampling, and/or logging the existence of a significant quantity of potentially recoverable hydrocarbons and thus have established a known accumulation. In the absence of a flow test or sampling, the discovery determination requires confidence in the presence of hydrocarbons and evidence of producibility, which may be supported by suitable producing analogs (see Section 4.1.1, Analogs). In this context, "significant" implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place quantity demonstrated by the well(s) and for evaluating the potential for commercial recovery. 2.1.1.2 Where a discovery has identified potentially recoverable hydrocarbons, but it is not considered viable to apply a project with established technology or with technology under development, such quantities may be classified as Discovered Unrecoverable with no Contingent Resources. In future evaluations, as appropriate for petroleum resources management purposes, a portion of these unrecoverable quantities may become recoverable resources as either commercial circumstances change or technological developments occur. 2.1.2 Determination of Commerciality 2.1.2.1 Discovered recoverable quantities (Contingent Resources) may be considered commercially mature, and thus attain Reserves classification, if the entity claiming commerciality has demonstrated a firm intention to proceed with development. This means the entity has satisfied the internal decision criteria (typically rate of return at or above the weighted average cost-of-capital or the hurdle rate). Commerciality is achieved with the entity's commitment to the project and all of the following criteria: A. Evidence of a technically mature, feasible development plan. B. Evidence of financial appropriations either being in place or having a high likelihood of being secured to implement the project. C. Evidence to support a reasonable time-frame for development. D. A reasonable assessment that the development projects will have positive economics and meet defined investment and operating criteria. This assessment is performed on the estimated entitlement forecast quantities and associated cash flow on which the investment decision is made (see Section 3.1.1, Net Cash-Flow Evaluation). E. A reasonable expectation that there will be a market for forecast sales quantities of the production required to justify development. There should also be similar confidence that all produced streams (e.g., oil, gas, water, CO2) can be sold, stored, re-injected, or otherwise appropriately disposed. F. Evidence that the necessary production and transportation facilities are available or can be made available. G. Evidence that legal, contractual, environmental, regulatory, and government approvals are in place or will be forthcoming, together with resolving any social and economic concerns. 2.1.2.2 The commerciality test for Reserves determination is applied to the best estimate (P50) forecast quantities, which upon qualifying all commercial and technical maturity criteria and constraints become the 2P Reserves. Stricter cases [e.g., low estimate (P90)] may be used for decision purposes or to investigate the range of commerciality (see Section 3.1.2, Economic Criteria). Typically, the low- and high-case project scenarios may be evaluated for sensitivities when considering project risk and upside opportunity. 2.1.2.3 To be included in the Reserves class, a project must be sufficiently defined to establish both its technical and commercial viability as noted in Section 2.1.2.1. There must be a reasonable expectation that all required internal and external approvals will be forthcoming and evidence of firm intention to proceed with development within a reasonable time-frame. A reasonable time-frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a benchmark, a longer time-frame could be applied where justifiable; for example, development of economic projects that take longer than five years to be developed or are deferred to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 5 of 10 2.1.2.4 While PRMS guidelines require financial appropriations evidence, they do not require that project financing be confirmed before classifying projects as Reserves. However, this may be another external reporting requirement. In many cases, financing is conditional upon the same criteria as above. In general, if there is not a reasonable expectation that financing or other forms of commitment (e.g., farm-outs) can be arranged so that the development will be initiated within a reasonable time-frame, then the project should be classified as Contingent Resources. If financing is reasonably expected to be in place at the time of the final investment decision (FID), the project's resources may be classified as Reserves. 2.2 Resources Categorization 2.2.0.1 The horizontal axis in the resources classification in Figure 1.1 defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project or group of projects. These estimates include the uncertainty components as follows: A. The total petroleum remaining within the accumulation (in-place resources). B. The technical uncertainty in the portion of the total petroleum that can be recovered by applying a defined development project or projects (i.e., the technology applied). C. Known variations in the commercial terms that may impact the quantities recovered and sold (e.g., market availability; contractual changes, such as production rate tiers or product quality specifications) are part of project's scope and are included in the horizontal axis, while the chance of satisfying the commercial terms is reflected in the classification (vertical axis). 2.2.0.2 The uncertainty in a project's recoverable quantities is reflected by the 1P, 2P, 3P, Proved (P1), Probable (P2), Possible (P3), 1C, 2C, 3C, C1, C2, and C3; or 1U, 2U, and 3U resources categories. The commercial chance of success is associated with resources classes or sub-classes and not with the resources categories reflecting the range of recoverable quantities. 2.2.1 Range of Uncertainty 2.2.1.1 Uncertainty is inherent in a project's resources estimation and is communicated in PRMS by reporting a range of category outcomes. The range of uncertainty of the recoverable and/or potentially recoverable quantities may be represented by either deterministic scenarios or by a probability distribution (see Section 4.2, Resources Assessment Methods). 2.2.1.2 When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that: A. There should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate. B. There should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate. C. There should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate. 2.2.1.3 In some projects, the range of uncertainty may be limited, and the three scenarios may result in resources estimates that are not significantly different. In these situations, a single value estimate may be appropriate to describe the expected result. 2.2.1.4 When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental method, quantities for each confidence segment are estimated discretely (see Section 2.2.2, Category Definitions and Guidelines). 2.2.1.5 Project resources are initially estimated using the above uncertainty range forecasts that incorporate the subsurface elements together with technical constraints related to wells and facilities. The technical forecasts then have additional commercial criteria applied (e.g., economics and license cutoffs are the most common) to estimate the entitlement quantities attributed and the resources classification status: Reserves, Contingent Resources, and Prospective Resources. 2.2.2 Category Definitions and Guidelines 2.2.2.1 Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental method, the deterministic scenario (cumulative) method, geostatistical methods, or probabilistic methods (see Section 4.2, Resources Assessment Methods). Also, combinations of these methods may be used. 2.2.2.2 Use of consistent terminology (Figures 1.1 and 2.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high forecasts are used to estimate the resulting 1P/2P/3P quantities, respectively. The associated incremental quantities are termed Proved (P1), Probable (P2) and Possible (P3). Reserves are a subset of, and must be viewed within the context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, the criteria can be equally applied to Contingent and Prospective Resources. Upon satisfying the commercial maturity criteria for discovery and/or development, the project quantities will then move to the appropriate resources sub-class. Table 3 provides criteria for the Reserves categories determination. 2.2.2.3 For Contingent Resources, the general cumulative terms low/best/high estimates are used to estimate the resulting 1C/2C/3C quantities, respectively. The terms C1, C2, and C3 are defined for incremental quantities of Contingent Resources.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 6 of 10 2.2.2.4 For Prospective Resources, the general cumulative terms low/best/high estimates also apply and are used to estimate the resulting 1U/2U/3U quantities. No specific terms are defined for incremental quantities within Prospective Resources. 2.2.2.5 Quantities in different classes and sub-classes cannot be aggregated without considering the varying degrees of technical uncertainty and commercial likelihood involved with the classification(s) and without considering the degree of dependency between them (see Section 4.2.1, Aggregating Resources Classes). 2.2.2.6 Without new technical information, there should be no change in the distribution of technically recoverable resources and the categorization boundaries when conditions are satisfied to reclassify a project from Contingent Resources to Reserves. 2.2.2.7 All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Section 3.1, Assessment of Commerciality). Table 1—Recoverable Resources Classes and Sub-Classes Class/Sub-Class Definition Guidelines Reserves Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria: discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by the development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability (see Section 2.1.2, Determination of Commerciality). This includes the requirement that there is evidence of firm intention to proceed with development within a reasonable time-frame. A reasonable time-frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While five years is recommended as a benchmark, a longer time-frame could be applied where, for example, development of an economic project is deferred at the option of the producer for, among other things, market-related reasons or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial maturity and economic producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. On Production The development project is currently producing or capable of producing and selling petroleum to market. The key criterion is that the project is receiving income from sales, rather than that the approved development project is necessarily complete. Includes Developed Producing Reserves. The project decision gate is the decision to initiate or continue economic production from the project. Approved for Development All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is ready to begin or is under way. At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies, such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity's current or following year's approved budget. The project decision gate is the decision to start investing capital in the construction of production facilities and/or drilling development wells.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 7 of 10 Class/Sub-Class Definition Guidelines Justified for Development Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. To move to this level of project maturity, and hence have Reserves associated with it, the development project must be commercially viable at the time of reporting (see Section 2.1.2, Determination of Commerciality) and the specific circumstances of the project. All participating entities have agreed and there is evidence of a committed project (firm intention to proceed with development within a reasonable time-frame). There must be no known contingencies that could preclude the development from proceeding (see Reserves class). The project decision gate is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. Contingent Resources Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, where commercial recovery is dependent on technology under development, where evaluation of the accumulation is insufficient to clearly assess commerciality, where the development plan is not yet approved, or where regulatory or social acceptance issues may exist. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub- classified based on project maturity and/or characterized by the economic status. Development Pending A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g., drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time-frame. Note that disappointing appraisal/evaluation results could lead to a reclassification of the project to On Hold or Not Viable status. The project decision gate is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. Development on Hold A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. The project is seen to have potential for commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a probable chance that a critical contingency can be removed in the foreseeable future, could lead to a reclassification of the project to Not Viable status. The project decision gate is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. Development Unclarified A discovered accumulation where project activities are under evaluation and where justification as a commercial development is unknown based on available information. The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are ongoing to clarify the potential for eventual commercial development. This sub-class requires active appraisal or evaluation and should not be maintained without a plan for future evaluation. The sub-class should reflect the actions required to move a project toward commercial maturity and economic production.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 8 of 10 Class/Sub-Class Definition Guidelines Development Not Viable A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time because of limited production potential. The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project decision gate is the decision not to undertake further data acquisition or studies on the project for the foreseeable future. Prospective Resources Those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Potential accumulations are evaluated according to the chance of geologic discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. Prospect A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. Project activities are focused on assessing the chance of geologic discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. Lead A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation to be classified as a Prospect. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the Lead can be matured into a Prospect. Such evaluation includes the assessment of the chance of geologic discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. Play A project associated with a prospective trend of potential prospects, but that requires more data acquisition and/or evaluation to define specific Leads or Prospects. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific Leads or Prospects for more detailed analysis of their chance of geologic discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. Table 2—Reserves Status Definitions and Guidelines Status Definition Guidelines Developed Reserves Expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-producing. Developed Producing Reserves Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing Reserves Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 9 of 10 Status Definition Guidelines Undeveloped Reserves Quantities expected to be recovered through future significant investments. Undeveloped Reserves are to be produced (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g., when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. Table 3—Reserves Category Definitions and Guidelines Category Definition Guidelines Proved Reserves Those quantities of petroleum that, 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. If deterministic methods are used, the term "reasonable certainty" is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the LKH as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves. Reserves in undeveloped locations may be classified as Proved provided that: A. The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially mature and economically productive. B. Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program. Probable Reserves Those additional Reserves that analysis of geoscience and engineering data indicates are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.
PETROLEUM RESERVES AND RESOURCES CLASSIFICATION AND DEFINITIONS Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, June 2018 Definitions - Page 10 of 10 Category Definition Guidelines Possible Reserves Those additional reserves that analysis of geoscience and engineering data indicates are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high-estimate scenario. When probabilistic methods are used, there should be at least a 10% probability (P10) that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of economic production from the reservoir by a defined, commercially mature project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable. Probable and Possible Reserves See above for separate criteria for Probable Reserves and Possible Reserves. The 2P and 3P estimates may be based on reasonable alternative technical interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing faults until this reservoir is penetrated and evaluated as commercially mature and economically productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil elevation and there exists the potential for an associated gas cap, Proved Reserves of oil should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.
CERTIFICATE OF QUALIFICATION I, Derek F. Newton, Licensed Professional Engineer, 1301 McKinney Street, Suite 3200, Houston, Texas 77010, hereby certify: I am an employee of Netherland, Sewell & Associates, Inc., which prepared a Competent Person's Report for Ithaca Energy (UK) Limited. The effective date of this evaluation is June 30, 2022. I consider myself to be independent of Ithaca Energy (UK) Limited, its directors, senior management, and other advisers. I do not have at the date of this report, have not had within the previous two years, nor do I expect to receive, any economic or beneficial interest (present or contingent) in the securities of Ithaca Energy (UK) Limited or in any of the assets being evaluated in this report. Additionally, our fees are not contingent upon the results of our evaluation. I attended University College, Cardiff, Wales, and I graduated in 1983 with a Bachelor of Science Degree in Mechanical Engineering; I attended Strathclyde University, Scotland, and I graduated in 1986 with a Master of Science Degree in Petroleum Engineering; I am a Licensed Professional Engineer in the State of Texas, United States of America; and I have in excess of 39 years of experience in petroleum engineering studies and evaluations. By: _________________________________________ Derek F. Newton, P.E. Senior Vice President Texas License No. 97689 October 18, 2022 Houston, Texas
CERTIFICATE OF QUALIFICATION I, Shane M. Howell, Licensed Professional Geoscientist, 1301 McKinney Street, Suite 3200, Houston, Texas 77010, hereby certify: I am an employee of Netherland, Sewell & Associates, Inc., which prepared a Competent Person's Report for Ithaca Energy (UK) Limited. The effective date of this evaluation is June 30, 2022. I consider myself to be independent of Ithaca Energy (UK) Limited, its directors, senior management, and other advisers. I do not have at the date of this report, have not had within the previous two years, nor do I expect to receive, any economic or beneficial interest (present or contingent) in the securities of Ithaca Energy (UK) Limited or in any of the assets being evaluated in this report. Additionally, our fees are not contingent upon the results of our evaluation. I attended San Diego State University, I graduated in 1997 with a Bachelor of Science Degree in Geological Sciences, and I graduated in 1998 with a Master of Science Degree in Geological Sciences; I am a Licensed Professional Geoscientist in the State of Texas, United States of America; and I have in excess of 24 years of experience in geological and geophysical studies and evaluations. By: _________________________________________ Shane M. Howell, P.G. Vice President Texas License No. 11276 October 18, 2022 Houston, Texas
ABBREVIATIONS $ United States dollars % percent °F degrees Fahrenheit 1C low estimate scenario of contingent resources 2C best estimate scenario of contingent resources 3C high estimate scenario of contingent resources 1P proved 2P proved plus probable 3P proved plus probable plus possible AFE authorization for expenditure Anasuria Hibiscus Anasuria Hibiscus Petroleum UK Limited Ancala Ancala Midstream Acquisitions Limited ANP Alba North Platform API American Petroleum Institute ASM Andrew Sand Member AXS Alba Extreme South BBL barrels BBL/MMCF barrels per million cubic feet BBL/mo barrels per month BLP bridge-linked platform BOE barrels of oil equivalent BOPD barrels of oil per day BP British Petroleum BWPD barrels of water per day CATS Central Area Transmission System CF/BBL cubic feet per barrel CGR condensate-gas ratio Chevron Chevron North Sea Limited CNRL Canadian Natural Resources Limited cP centipoise D darcy DCA decline curve analysis DST drillstem test EOR enhanced oil recovery EOS equation of state Equinor Equinor UK Limited ESP electric submersible pump EUR estimated ultimate recovery FBHP flowing bottomhole pressure FCA Financial Conduct Authority FDP field development plan FID final investment decision FPF floating production facility FPS Forties Pipeline System
ABBREVIATIONS FPSO floating production storage and offloading ft feet ft 3 /ft 3 cubic feet per cubic foot g/cm 3 grams per cubic centimeter GBA Greater Britannia Area GOC gas-oil contact GOR gas-oil ratio GRV gross rock volume GSA Greater Stella Area GWC gas-water contact Harbour Harbour Energy plc HKO highest known oil IHS IHS Markit Ithaca Ithaca Energy (UK) Limited km kilometers LCS Lower Captain Sandstone LKO lowest known oil LP Low Pressure LLP Low Low Pressure M$ thousands of United States dollars MBBL thousands of barrels MBOE thousands of barrels of oil equivalent MBOPD thousands of barrels of oil per day MBWPD thousands of barrels of water per day MCF thousands of cubic feet MCFD thousands of cubic feet per day MCF/mo thousands of cubic feet per month mD millidarcies MDT modular dynamics test MMBTU millions of British thermal units MMBTU/MCF millions of British thermal units per thousands of cubic feet MMCF millions of cubic feet MMCFD millions of cubic feet of gas per day MonArb Montrose-Arbroath MTR meters NGL natural gas liquids NRV net rock volume NSAI Netherland, Sewell & Associates, Inc. NSTA North Sea Transition Authority NTG net-to-gross ratio NUI normally unattended installation ohm-m ohm-meters OOIP original oil-in-place OWC oil-water contact
ABBREVIATIONS P/Z material balance PDP proved developed producing post-COP post-cessation of production PFG polymer flood group PRMS Petroleum Resources Management System psi pounds per square inch psia pounds per square inch absolute PVT pressure-volume-temperature report Competent Person's Report Repsol Repsol Sinopec Resources UK Limited RFT repeat formation test Ross Ross and Burns Sandstones S1b Sele SADIE Southern Area Development Injection Equipment SAGE Scottish Area Gas Evacuation SCF/STB standard cubic feet per stock tank barrel SEGAL Shell-Esso Gas and Liquids Shell Shell UK Exploration & Production Siccar Point Siccar Point Energy Limited SMDC Stella Main Drill Center SPE Society of Petroleum Engineers SPE Standards Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE STOIIP stock tank oil initially in-place SUCS Southern Upper Captain Sandstone Swi initial water saturation Total Total E&P U.K. Limited TVDSS true vertical depth subsea UCS Upper Captain Sandstone UK United Kingdom Unocal Union Oil Company of California UTM Unitised Template Manifold WOR water-oil ratio
Gross (100%) Reserves (1) Working Interest Reserves (1) Oil (2) Gas (2) Oil Gas NGL Equivalent (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MBOE) DEVELOPED Proved Developed 291,180.3 1,249,611.1 57,781.6 203,349.8 5,313.1 98,155.0 Proved + Probable Developed 447,559.6 1,748,117.4 95,642.5 295,283.9 7,862.6 154,416.1 Proved + Probable + Possible Developed 607,685.0 2,336,418.2 139,201.9 403,393.9 10,953.6 219,706.2 UNDEVELOPED Proved Undeveloped 162,635.6 38,726.8 56,665.4 20,504.4 527.6 60,728.3 Proved + Probable Undeveloped 249,183.7 75,961.6 81,099.2 42,186.9 1,069.1 89,441.9 Proved + Probable + Possible Undeveloped 337,945.7 117,444.9 109,832.3 65,342.6 1,622.9 122,721.2 TOTAL Proved (1P) 453,815.9 1,288,337.9 114,446.9 223,854.2 5,840.7 158,883.2 Proved + Probable (2P) 696,743.3 1,824,079.0 176,741.6 337,470.8 8,931.8 243,858.0 Proved + Probable + Possible (3P) 945,630.7 2,453,863.1 249,034.2 468,736.5 12,576.5 342,427.4 Totals may not add because of rounding. Note: (1) Working interest volumes are after deductions for shrinkage to account for processing, fuel, and flare. (2) Development Status/Category Gross gas volumes are the wet gas volumes prior to extracting natural gas liquids (NGL) and deducting volumes flared or consumed for fuel; therefore, gross NGL volumes are not shown separately because they would be misleading. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk. SUMMARY OF RESERVES UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN ITHACA ENERGY (UK) LIMITED INTEREST AS OF JUNE 30, 2022 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Gross (100%) Contingent Resources (1) Working Interest Contingent Resources (1) Oil (2) Gas (2) Oil Gas NGL Equivalent (MBBL) (MMCF) (MBBL) (MMCF) (MBBL) (MBOE) Low Estimate (1C) 347,278.0 641,593.6 125,164.4 253,636.8 723.6 169,618.5 Best Estimate (2C) 676,879.8 1,116,961.6 232,174.4 398,268.5 841.5 301,682.9 High Estimate (3C) 1,153,169.1 1,749,309.9 369,382.1 587,234.7 1,324.0 471,953.4 (1) Working interest volumes are after deductions for shrinkage to account for processing, fuel, and flare. (2) Gross gas volumes are the wet gas volumes prior to extracting natural gas liquids (NGL) and deducting volumes flared or consumed for fuel; therefore, gross NGL volumes are not shown separately because they would be misleading. SUMMARY OF CONTINGENT RESOURCES UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN ITHACA ENERGY (UK) LIMITED INTEREST AS OF JUNE 30, 2022 Category All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Future Net Revenue After UK Corporate Income Taxes (M$) Present Worth Category Undiscounted at 10% Proved (1P) 4,111,140.2 3,985,975.0 Probable 2,669,142.0 1,841,135.4 Proved + Probable (2P) 6,780,282.2 5,827,110.4 Possible 2,946,963.9 1,812,942.5 Proved + Probable + Possible (3P) 9,727,246.0 7,640,053.0 Totals may not add because of rounding. Note: SUMMARY OF FUTURE NET REVENUE AFTER UK CORPORATE INCOME TAXES UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN ITHACA ENERGY (UK) LIMITED INTEREST AS OF JUNE 30, 2022 Reserves categorization conveys the relative degree of certainty. The estimates of future revenue included herein have not been adjusted for risk. All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
Net Contingent Cash Flow After UK Corporate Income Taxes (M$) Discounted Category Undiscounted at 10% Low Estimate (1C) 4,401,099.1 1,958,529.3 Best Estimate (2C) 9,427,221.8 3,994,985.5 High Estimate (3C) 17,723,131.7 6,919,249.3 SUMMARY OF NET CONTINGENT CASH FLOW AFTER UK CORPORATE INCOME TAXES UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN ITHACA ENERGY (UK) LIMITED INTEREST AS OF JUNE 30, 2022 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
TABLE OF CONTENTS SUMMARY PROJECTIONS OF RESERVES AND REVENUE Proved (1P) Reserves I Probable Reserves II Proved + Probable (2P) Reserves III Possible Reserves IV Proved + Probable + Possible (3P) Reserves V SUMMARY PROJECTIONS OF RESOURCES AND CASH FLOW Low Estimate (1C) Contingent Resources VI Best Estimate (2C) Contingent Resources VII High Estimate (3C) Contingent Resources VIII TECHNICAL DISCUSSION 1.0 Overview 1 1.1 Figures 2.0 Captain Field 4 2.1 Overview 4 2.2 Geology 5 2.3 Methodology 6 2.4 Reserves and Contingent Resources by Project 8 2.5 Figures 3.0 Greater Stella Area 10 3.1 Stella Field 11 3.1.1.1 Andrew Sand Member 11 3.1.1.2 Ekofisk Formation 12 3.2 Harrier Field 12
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 3.0 Greater Stella Area (Continued) 3.3 Vorlich Field 14 3.4 Abigail Field 15 3.5 Courageous Field 16 3.6 Figures 4.0 Schiehallion Field 18 4.1 Geology 18 4.2 Methodology 19 4.3 Reserves and Contingent Resources by Project 19 4.4 Figures 5.0 Greater Britannia Area 21 5.1 Britannia Field 22 5.2 Alder Field 22 5.3 Brodgar Field 24
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 5.0 Greater Britannia Area (Continued) 5.4 Callanish Field 25 5.5 Enochdhu Field 26 5.6 Figures 6.0 MonArb Area 27 6.1 Montrose Field 28 6.2 Arbroath Field 29 6.3 Arkwright Field 30 6.4 Brechin Field 31 6.5 Cayley Field 32 6.6 Godwin Field 32 6.7 Shaw Field 33
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 6.0 MonArb Area (Continued) 6.8 Wood Field 34 6.9 Figures 7.0 Mariner Area 36 7.1 Mariner Field 37 7.2 Mariner East Field 40 7.3 Cadet Field 41 7.4 Figures 8.0 Jade and Jade South Fields 42 8.1 Geology 42 8.2 Methodology 42 8.3 Reserves by Project 43 8.4 Figures
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 9.0 Cook Field 44 9.1 Geology 44 9.2 Methodology 45 9.3 Contingent Resources by Project 45 9.4 Figures 10.0 Erskine Field 47 10.1 Geology 47 10.2 Methodology 47 10.3 Contingent Resources by Project 48 10.4 Figures 11.0 Elgin-Franklin Field 49 11.1 Elgin Area 50 11.2 Franklin Area 50 11.3 West Franklin Area 51 11.4 Compression Projects 51 11.5 Reserves and Contingent Resources by Project 51 11.6 Figures 12.0 Alba Field 53 12.1 Geology 53 12.2 Methodology 53 12.3 Reserves and Contingent Resources by Project 54 12.4 Figures 13.0 Pierce Field 56 13.1 Geology 56 13.2 Methodology 57 13.3 Contingent Resources by Project 57 13.4 Figures 14.0 Columba Terraces Area 58 14.1 Geology 58 14.2 Methodology 58 14.3 Figures
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 15.0 Cambo Field 59 15.1 Geology 59 15.2 Methodology 59 15.3 Contingent Resources by Project 60 15.4 Figures 16.0 Rosebank Field 62 16.1 Geology 62 16.2 Methodology 63 16.3 Contingent Resources by Project 63 16.4 Figures 17.0 Tornado Field 64 17.1 Geology 64 17.2 Methodology 64 17.3 Contingent Resources by Project 65 17.4 Figures 18.0 Marigold Field 66 18.1 Geology 66 18.2 Methodology 67 18.3 Contingent Resources by Project 67 18.4 Figures 19.0 Fotla Field 68 19.1 Geology 68 19.2 Methodology 68 19.3 Contingent Resources by Project 69 19.4 Figures 20.0 Isabella Field 70 20.1 Geology 70 20.2 Methodology 70 20.3 Contingent Resources by Project 71 20.4 Figures 21.0 Leverett Field 72 21.1 Geology 72 21.2 Methodology 72 21.3 Contingent Resources by Project 73 21.4 Figures 22.0 Decommissioning Assets 74
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 23.0 Economic Analysis 75 23.1 Prices and Price Adjustments 75 23.2 Sales Conversion Factors 76 23.3 Operating, Capital, and Abandonment Costs 78 23.3.2.1 Operating Costs 79 23.3.2.2 Capital Costs 79 23.3.2.3 Abandonment Costs 80 23.3.4.1 Operating Costs 80 23.3.4.2 Capital Costs 80 23.3.4.3 Abandonment Costs 80 23.4 Figures 24.0 Summary of Reserves, Contingent Resources, and Recovery 85 24.1 Figures – Summary Projections of Reserves and Revenue by Area and Field – Before UK Corporate Income Taxes
TABLE OF CONTENTS TECHNICAL DISCUSSION (Continued) 24.0 Summary of Reserves, Contingent Resources, and Recovery (Continued) 24.2 Figures – Summary Projections of Resources and Cash Flow by Area and Field – Before UK Corporate Income Taxes 24.3 Figures – Summary of Estimated Ultimate Recovery and Recovery Factors by Field 25.0 Reconciliation with Previous NSAI Estimates 86
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE PROVED (1P) RESERVES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESERVES WORKING INTEREST RESERVES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 33,477.2 142,284.2 8,632.7 26,921.2 682.4 13,956.7 102.26 33.213 71.71 882,809.2 1,825,889.6 12-31-2023 59,167.2 245,482.5 14,993.7 44,879.9 1,227.3 23,958.9 94.08 24.684 66.38 1,410,537.1 2,599,848.9 12-31-2024 52,975.5 197,125.4 13,512.7 37,693.4 1,050.2 21,061.8 84.00 15.907 59.37 1,135,111.2 1,797,039.8 12-31-2025 54,581.3 159,210.0 19,351.5 31,750.1 866.5 25,692.1 77.60 12.689 54.27 1,501,738.1 1,951,619.4 12-31-2026 47,110.8 120,379.4 16,654.5 22,916.0 600.6 21,206.1 78.79 10.406 53.89 1,312,226.1 1,583,068.2 12-31-2027 36,864.2 96,103.0 10,850.2 14,456.5 350.6 13,693.4 79.89 10.390 52.08 866,830.9 1,035,295.4 12-31-2028 31,417.3 78,338.0 8,619.6 12,353.8 287.2 11,036.8 81.89 10.575 52.80 705,866.3 851,678.1 12-31-2029 28,059.4 64,083.9 7,455.0 10,472.1 237.5 9,498.0 82.90 10.763 53.03 618,054.4 743,357.9 12-31-2030 22,142.6 49,581.4 4,690.7 8,317.7 198.9 6,323.6 84.55 10.892 54.15 396,615.7 497,979.2 12-31-2031 18,884.9 40,773.6 2,938.9 6,798.4 160.5 4,271.6 86.04 11.015 54.69 252,873.0 336,540.1 12-31-2032 14,665.5 22,258.3 1,407.5 2,780.8 58.8 1,945.8 87.84 11.120 54.68 123,638.5 157,775.4 12-31-2033 11,994.6 14,613.8 1,129.2 900.6 25.4 1,309.8 89.81 11.645 61.82 101,418.3 113,474.0 12-31-2034 10,415.1 13,664.5 985.9 842.4 23.7 1,154.8 92.91 11.871 63.84 91,607.7 103,118.5 12-31-2035 9,205.6 12,789.4 875.8 788.8 22.1 1,033.9 95.00 12.101 65.18 83,203.6 94,188.0 12-31-2036 8,330.5 11,981.4 795.6 739.3 20.6 943.7 98.06 12.334 67.20 78,020.2 88,524.8 SUBTOTAL 439,291.8 1,268,668.7 112,893.7 222,610.8 5,812.3 157,087.2 84.69 17.394 59.67 9,560,550.4 13,779,397.4 REMAINING 14,524.1 19,669.2 1,553.3 1,243.4 28.4 1,796.1 104.80 12.114 69.86 162,777.8 179,824.4 TOTAL 453,815.9 1,288,337.9 114,446.9 223,854.2 5,840.7 158,883.2 84.96 17.364 59.72 9,723,328.2 13,959,221.8 CUM PROD 2,543,413.8 8,704,724.1 ULTIMATE 2,997,229.6 9,993,062.0 FUTURE NET REVENUE NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% PRESENT WORTH PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CUM PW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 201 72.2 0.0 295,373.5 214,509.0 272.4 258,279.3 1,057,455.4 1,057,455.4 1,031,399.2 12-31-2023 212 73.9 0.0 351,473.9 368,048.9 6,585.4 531,465.3 1,342,275.4 2,399,730.8 2,256,337.1 12-31-2024 217 74.3 0.0 147,479.5 367,886.8 2,890.9 544,925.6 733,857.0 3,133,587.8 2,862,738.8 12-31-2025 225 81.2 0.0 202,476.9 321,477.2 3,923.3 563,053.0 860,689.0 3,994,276.8 3,505,209.6 12-31-2026 211 75.2 0.0 159,585.6 205,195.1 11,674.9 519,019.2 687,593.3 4,681,870.2 3,978,819.4 12-31-2027 199 66.9 0.0 108,342.3 231,444.7 69,420.3 373,289.3 252,798.7 4,934,668.9 4,136,019.7 12-31-2028 161 51.2 0.0 109,904.1 69,519.3 69,107.9 346,704.0 256,442.8 5,191,111.7 4,279,430.3 12-31-2029 158 49.1 0.0 75,334.7 51,296.8 101,057.4 339,888.2 175,780.8 5,366,892.6 4,368,750.7 12-31-2030 150 44.3 0.0 -4,652.6 36,502.8 191,171.1 285,814.1 -10,856.2 5,356,036.4 4,362,916.2 12-31-2031 132 35.5 0.0 -61,183.3 22,959.4 279,031.9 238,493.2 -142,761.1 5,213,275.3 4,300,496.1 12-31-2032 101 15.4 0.0 -84,380.6 610.3 343,612.2 94,821.7 -196,888.1 5,016,387.2 4,225,812.7 12-31-2033 71 6.9 0.0 -93,053.0 863.6 352,738.8 70,048.3 -217,123.6 4,799,263.6 4,149,952.3 12-31-2034 71 6.9 0.0 -72,348.7 972.6 272,783.3 70,524.9 -168,813.7 4,630,449.9 4,096,164.9 12-31-2035 67 6.6 0.0 -39,791.6 473.0 155,474.0 70,879.8 -92,847.1 4,537,602.8 4,068,645.3 12-31-2036 65 6.4 0.0 -37,255.6 912.1 140,059.9 71,738.1 -86,929.7 4,450,673.1 4,045,028.6 SUBTOTAL 0.0 1,057,305.0 1,892,671.6 1,999,803.7 4,378,944.0 4,450,673.1 4,450,673.1 4,045,028.6 REMAINING 0.0 -60,501.2 3,482.0 419,970.9 156,405.6 -339,532.9 4,111,140.2 3,985,975.0 TOTAL OF 18.0 YRS 0.0 996,803.8 1,896,153.7 2,419,774.6 4,535,349.6 4,111,140.2 4,111,140.2 3,985,975.0 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 599,576.2 62,352.3 894,144.2 48,936.2 1,107,835.8 81,476.0 402,862.1 47,019.2 238,472.8 32,369.3 150,202.1 18,262.4 130,646.6 15,165.2 112,710.3 12,593.2 90,594.4 10,769.1 74,887.4 8,779.7 30,921.0 3,215.9 10,488.1 1,567.6 3,887,067.3 348,826.3 10,000.7 1,510.1 9,545.0 1,439.4 9,118.3 1,386.3 3,872,005.1 346,841.9 15,062.2 1,984.4 05.000 4,138,102.9 10.000 3,985,975.0 15.000 3,780,450.1 20.000 3,569,394.1 25.000 3,370,554.8 30.000 3,189,576.9 50.000 2,637,316.3 35.000 3,027,199.1 40.000 2,882,250.0 45.000 2,752,922.9 Table I
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE PROBABLE RESERVES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESERVES WORKING INTEREST RESERVES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 4,519.9 15,854.0 1,357.2 2,969.3 64.3 1,933.4 101.81 35.129 72.59 138,176.4 247,149.7 12-31-2023 12,037.3 41,876.3 3,922.5 8,751.4 208.4 5,639.8 93.92 26.311 67.92 368,419.4 612,836.4 12-31-2024 17,725.6 43,639.2 4,786.0 11,801.1 322.5 7,143.2 83.70 16.711 62.17 400,609.2 617,867.3 12-31-2025 19,635.9 47,870.7 6,055.5 12,566.0 348.5 8,570.6 77.27 13.201 57.02 467,895.4 653,647.8 12-31-2026 20,932.2 58,463.2 7,283.0 12,805.5 375.6 9,866.5 78.03 10.932 57.82 568,299.2 730,005.5 12-31-2027 20,317.0 57,578.2 6,889.7 15,530.7 468.2 10,035.6 78.66 11.158 58.71 541,910.1 742,686.0 12-31-2028 18,798.0 50,168.9 5,920.9 12,137.5 374.5 8,388.1 80.66 11.348 59.94 477,599.4 637,780.6 12-31-2029 14,837.1 35,037.6 4,263.2 6,681.6 214.4 5,629.7 82.22 11.278 59.46 350,541.7 438,650.3 12-31-2030 13,734.6 30,263.7 3,704.2 3,967.7 100.2 4,488.5 84.41 11.260 58.42 312,665.9 363,196.7 12-31-2031 12,964.5 28,616.0 3,428.1 3,996.1 103.1 4,220.2 86.42 11.563 60.16 296,247.5 348,653.9 12-31-2032 13,147.2 38,633.2 3,921.9 6,765.6 175.3 5,263.7 89.67 11.551 60.10 351,680.4 440,366.7 12-31-2033 10,337.6 34,184.1 3,005.9 6,996.0 162.8 4,374.9 91.86 11.619 59.05 276,125.0 367,019.5 12-31-2034 7,038.6 25,746.7 1,636.1 5,654.4 131.7 2,742.7 94.80 11.785 60.23 155,112.2 229,684.4 12-31-2035 4,395.8 7,877.5 461.9 1,611.8 35.1 774.9 94.98 12.144 62.25 43,872.4 65,627.4 12-31-2036 3,638.0 2,056.3 358.5 130.8 2.8 383.8 97.71 11.579 67.20 35,023.7 36,727.7 SUBTOTAL 194,059.3 517,865.7 56,994.9 112,365.5 3,087.4 79,455.7 83.94 13.902 60.13 4,784,177.7 6,531,899.7 REMAINING 48,868.1 17,875.4 5,299.8 1,251.1 3.6 5,519.1 113.69 10.689 69.86 602,530.9 616,155.4 TOTAL 242,927.4 535,741.1 62,294.7 113,616.6 3,091.0 84,974.8 86.47 13.866 60.14 5,386,708.6 7,148,055.1 CUM PROD 3,099. ULTIMATE 538,840. FUTURE NET REVENUE NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% PRESENT WORTH PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CUM PW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 5 2.7 0.0 60,482.1 579.2 0.0 4,178.8 181,909.6 181,909.6 176,793.0 12-31-2023 9 5.1 0.0 149,589.4 0.0 -6,391.0 14,478.6 455,159.3 637,069.0 589,880.3 12-31-2024 14 7.1 0.0 155,230.4 13,928.8 -2,885.0 28,436.0 423,157.1 1,060,226.1 938,179.8 12-31-2025 15 6.5 0.0 655,277.7 0.0 2,760.1 40,637.0 -45,027.0 1,015,199.0 903,273.6 12-31-2026 29 11.9 0.0 415,656.9 1,875.1 -9,684.6 82,642.6 239,515.5 1,254,714.5 1,067,116.4 12-31-2027 37 16.9 0.0 257,364.1 4,261.6 -63,396.7 211,867.0 332,590.0 1,587,304.5 1,273,986.9 12-31-2028 67 26.7 0.0 217,337.9 1,445.4 -59,446.7 232,935.9 245,508.3 1,832,812.8 1,414,154.8 12-31-2029 66 25.1 0.0 179,601.4 0.0 -69,992.3 114,402.8 214,638.3 2,047,451.1 1,526,044.8 12-31-2030 33 12.0 0.0 130,105.0 2,081.9 -81,789.2 107,735.4 205,063.5 2,252,514.6 1,622,623.7 12-31-2031 43 15.2 0.0 132,736.5 1,373.6 -187,316.0 147,966.9 253,892.9 2,506,407.5 1,731,285.5 12-31-2032 68 33.4 0.0 141,096.3 1,401.3 -278,692.1 294,285.3 282,275.9 2,788,683.4 1,839,133.7 12-31-2033 92 40.0 0.0 86,671.0 952.9 -203,231.4 275,076.3 207,550.6 2,996,234.0 1,912,430.0 12-31-2034 67 29.5 0.0 -10,131.8 0.0 19,135.8 175,587.5 45,092.9 3,041,326.9 1,927,925.3 12-31-2035 43 10.1 0.0 -75,884.4 0.0 194,875.6 27,303.2 -80,667.0 2,960,659.9 1,905,610.5 12-31-2036 9 0.8 0.0 -92,554.2 0.0 234,850.4 2,216.3 -107,784.9 2,852,875.0 1,877,895.1 SUBTOTAL 0.0 2,402,578.1 27,899.9 -511,203.0 1,759,749.7 2,852,875.0 2,852,875.0 1,877,895.1 REMAINING 0.0 -289,494.4 3,398.7 660,902.3 425,081.8 -183,733.0 2,669,142.0 1,841,135.4 TOTAL OF 25.5 YRS 0.0 2,113,083.8 31,298.7 149,699.3 2,184,831.5 2,669,142.0 2,669,142.0 1,841,135.4 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 197,205.6 20,052.5 104,306.7 4,666.7 230,260.3 14,156.7 165,881.0 19,871.4 139,987.8 21,718.5 173,288.2 27,487.7 137,735.2 22,446.0 75,358.2 12,750.3 44,677.0 5,853.8 46,206.7 6,199.7 78,148.7 10,537.6 81,283.6 9,610.8 1,575,439.4 185,907.1 66,639.7 7,932.6 19,572.9 2,182.1 1,515.0 188.9 1,562,066.5 185,655.5 13,372.9 251.6 05.000 2,203,399.0 10.000 1,841,135.4 15.000 1,568,987.1 20.000 1,363,499.3 25.000 1,205,887.5 30.000 1,082,748.3 50.000 785,213.0 35.000 984,737.5 40.000 905,328.8 45.000 839,917.9 Table II
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE PROVED + PROBABLE (2P) RESERVES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESERVES WORKING INTEREST RESERVES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 37,997.2 158,138.2 9,989.9 29,890.5 746.7 15,890.1 102.20 33.404 71.79 1,020,985.6 2,073,039.4 12-31-2023 71,204.5 287,358.8 18,916.2 53,631.3 1,435.8 29,598.8 94.04 24.950 66.61 1,778,956.5 3,212,685.2 12-31-2024 70,701.0 240,764.6 18,298.7 49,494.5 1,372.7 28,205.0 83.93 16.098 60.03 1,535,720.4 2,414,907.0 12-31-2025 74,217.2 207,080.7 25,407.0 44,316.1 1,215.0 34,262.7 77.52 12.834 55.06 1,969,633.5 2,605,267.2 12-31-2026 68,043.0 178,842.5 23,937.5 35,721.5 976.2 31,072.6 78.56 10.595 55.40 1,880,525.3 2,313,073.7 12-31-2027 57,181.1 153,681.2 17,739.9 29,987.2 818.8 23,729.0 79.41 10.788 55.87 1,408,741.0 1,777,981.4 12-31-2028 50,215.2 128,506.8 14,540.5 24,491.3 661.7 19,424.9 81.39 10.958 56.84 1,183,465.7 1,489,458.7 12-31-2029 42,896.5 99,121.5 11,718.3 17,153.7 451.9 15,127.7 82.66 10.964 56.08 968,596.1 1,182,008.1 12-31-2030 35,877.2 79,845.1 8,394.9 12,285.4 299.1 10,812.2 84.49 11.011 55.58 709,281.6 861,175.8 12-31-2031 31,849.4 69,389.6 6,367.1 10,794.5 263.6 8,491.8 86.24 11.218 56.83 549,120.4 685,194.0 12-31-2032 27,812.7 60,891.4 5,329.4 9,546.4 234.1 7,209.5 89.19 11.425 58.74 475,318.9 598,142.2 12-31-2033 22,332.2 48,798.0 4,135.2 7,896.6 188.1 5,684.8 91.30 11.622 59.42 377,543.4 480,493.5 12-31-2034 17,453.7 39,411.1 2,622.1 6,496.8 155.4 3,897.6 94.09 11.797 60.78 246,719.8 332,802.9 12-31-2035 13,601.5 20,666.9 1,337.8 2,400.5 57.1 1,808.8 94.99 12.130 63.39 127,076.0 159,815.5 12-31-2036 11,968.6 14,037.7 1,154.1 870.1 23.4 1,327.6 97.95 12.221 67.20 113,043.9 125,252.5 SUBTOTAL 633,351.1 1,786,534.3 169,888.6 334,976.4 8,899.8 236,542.8 84.44 16.222 59.83 14,344,728.1 20,311,297.2 REMAINING 63,392.2 37,544.6 6,853.1 2,494.5 32.0 7,315.2 111.67 11.399 69.86 765,308.7 795,979.8 TOTAL 696,743.3 1,824,079.0 176,741.6 337,470.8 8,931.8 243,858.0 85.49 16.187 59.87 15,110,036.8 21,107,276.9 CUM PROD 8,707,823. ULTIMATE 10,531,902. FUTURE NET REVENUE NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% PRESENT WORTH PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CUM PW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 206 74.8 0.0 355,855.6 215,088.2 272.4 262,458.2 1,239,365.0 1,239,365.0 1,208,192.1 12-31-2023 221 79.0 0.0 501,063.3 368,048.9 194.4 545,943.9 1,797,434.7 3,036,799.7 2,846,217.4 12-31-2024 231 81.4 0.0 302,709.9 381,815.6 5.9 573,361.6 1,157,014.1 4,193,813.8 3,800,918.6 12-31-2025 240 87.7 0.0 857,754.5 321,477.2 6,683.5 603,689.9 815,662.0 5,009,475.9 4,408,483.2 12-31-2026 240 87.1 0.0 575,242.5 207,070.2 1,990.3 601,661.8 927,108.8 5,936,584.7 5,045,935.9 12-31-2027 236 83.7 0.0 365,706.4 235,706.3 6,023.6 585,156.3 585,388.7 6,521,973.4 5,410,006.6 12-31-2028 228 77.8 0.0 327,241.9 70,964.7 9,661.2 579,639.9 501,951.1 7,023,924.5 5,693,585.1 12-31-2029 224 74.2 0.0 254,936.0 51,296.8 31,065.1 454,291.1 390,419.1 7,414,343.6 5,894,795.6 12-31-2030 183 56.3 0.0 125,452.3 38,584.8 109,381.9 393,549.5 194,207.4 7,608,551.0 5,985,539.9 12-31-2031 175 50.7 0.0 71,553.2 24,333.0 91,715.9 386,460.1 111,131.8 7,719,682.8 6,031,781.6 12-31-2032 169 48.8 0.0 56,715.6 2,011.6 64,920.1 389,107.0 85,387.8 7,805,070.6 6,064,946.4 12-31-2033 163 47.0 0.0 -6,382.0 1,816.5 149,507.4 345,124.5 -9,573.0 7,795,497.6 6,062,382.3 12-31-2034 138 36.4 0.0 -82,480.5 972.6 291,919.2 246,112.5 -123,720.8 7,671,776.8 6,024,090.1 12-31-2035 110 16.6 0.0 -115,676.1 473.0 350,349.6 98,183.1 -173,514.1 7,498,262.7 5,974,255.8 12-31-2036 74 7.2 0.0 -129,809.7 912.1 374,910.4 73,954.4 -194,714.6 7,303,548.1 5,922,923.7 SUBTOTAL 0.0 3,459,883.1 1,920,571.6 1,488,600.7 6,138,693.7 7,303,548.1 7,303,548.1 5,922,923.7 REMAINING 0.0 -349,995.5 6,880.8 1,080,873.1 581,487.3 -523,265.9 6,780,282.2 5,827,110.4 TOTAL OF 25.5 YRS 0.0 3,109,887.6 1,927,452.3 2,569,473.8 6,720,181.1 6,780,282.2 6,780,282.2 5,827,110.4 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 796,781.8 82,404.8 998,450.9 53,602.9 1,338,096.0 95,632.7 568,743.1 66,890.6 378,460.6 54,087.8 323,490.3 45,750.1 268,381.8 37,611.2 188,068.5 25,343.5 135,271.4 16,622.8 121,094.1 14,979.5 109,069.7 13,753.6 91,771.7 11,178.5 5,462,506.7 534,733.4 76,640.4 9,442.7 29,118.0 3,621.5 10,633.3 1,575.2 5,434,071.6 532,497.5 28,435.1 2,236.0 05.000 6,341,502.0 10.000 5,827,110.4 15.000 5,349,437.2 20.000 4,932,893.4 25.000 4,576,442.3 30.000 4,272,325.2 50.000 3,422,529.3 35.000 4,011,936.6 40.000 3,787,578.8 45.000 3,592,840.9 Table III
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE POSSIBLE RESERVES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESERVES WORKING INTEREST RESERVES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 4,107.2 9,158.5 886.4 1,737.7 37.6 1,223.6 102.22 34.544 74.00 90,611.8 153,417.8 12-31-2023 12,746.6 29,623.5 3,464.2 5,578.0 127.8 4,553.7 94.44 25.865 67.26 327,174.4 480,043.1 12-31-2024 19,281.4 39,748.0 4,895.9 6,785.1 165.7 6,231.4 84.18 16.333 60.22 412,131.6 532,928.1 12-31-2025 20,166.7 48,034.0 6,546.9 12,232.4 339.2 8,995.1 77.58 13.084 56.48 507,873.8 687,082.8 12-31-2026 17,264.3 39,819.4 6,119.7 10,570.3 280.0 8,222.1 78.59 10.849 57.39 480,964.9 611,716.1 12-31-2027 17,095.4 40,348.1 6,132.2 9,633.5 255.9 8,049.1 79.15 10.991 57.84 485,374.6 606,053.5 12-31-2028 15,066.4 42,488.4 4,966.6 9,424.5 273.2 6,864.7 81.17 11.250 59.40 403,117.1 520,373.5 12-31-2029 15,933.2 52,423.0 5,008.7 12,674.2 377.7 7,571.6 81.61 11.654 60.71 408,763.0 579,395.4 12-31-2030 14,864.7 46,340.3 4,262.4 11,451.8 372.3 6,609.2 83.94 11.738 61.75 357,779.4 515,195.4 12-31-2031 13,579.6 40,904.1 3,637.5 9,480.2 313.9 5,585.9 86.04 11.889 62.78 312,949.5 445,363.5 12-31-2032 10,653.6 32,321.2 2,666.6 6,191.4 195.3 3,929.4 89.56 12.040 64.13 238,820.9 325,890.6 12-31-2033 10,603.9 31,050.5 2,658.7 4,023.7 126.5 3,478.9 91.52 12.027 64.10 243,326.7 299,828.9 12-31-2034 11,428.3 30,506.9 3,366.9 4,176.1 116.4 4,203.3 94.66 12.229 65.62 318,710.5 377,419.1 12-31-2035 11,935.8 42,954.8 3,785.0 7,328.0 192.5 5,240.9 97.10 12.225 64.31 367,521.2 469,481.6 12-31-2036 10,975.2 42,296.9 3,391.6 7,858.6 196.0 4,942.5 100.12 12.463 65.71 339,564.5 450,389.6 SUBTOTAL 205,702.3 568,017.7 61,789.1 119,145.4 3,370.1 85,701.5 85.69 13.077 61.36 5,294,683.8 7,054,579.1 REMAINING 43,185.1 61,766.4 10,503.5 12,120.2 274.7 12,867.9 108.17 13.045 70.13 1,136,152.1 1,313,527.5 TOTAL 248,887.4 629,784.1 72,292.6 131,265.7 3,644.8 98,569.3 88.96 13.075 62.02 6,430,835.9 8,368,106.6 CUM PROD ULTIMATE 632,77. FUTURE NET REVENUE NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% PRESENT WORTH PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CUM PW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 1 0.3 0.0 38,071.5 0.0 0.0 1,132.0 114,214.4 114,214.4 111,564.4 12-31-2023 2 1.2 0.0 117,630.7 0.0 0.0 9,520.5 352,891.9 467,106.3 430,349.1 12-31-2024 7 5.0 0.0 473,099.2 0.0 0.0 12,461.4 47,367.5 514,473.8 469,218.8 12-31-2025 12 6.4 0.0 529,308.9 0.0 -6,683.5 33,138.1 131,319.3 645,793.1 566,982.4 12-31-2026 15 7.8 0.0 241,630.6 853.0 -1,990.3 40,533.8 330,689.0 976,482.1 793,609.3 12-31-2027 20 10.1 0.0 223,114.8 4,016.5 537.2 43,085.2 335,299.8 1,311,781.9 1,001,632.7 12-31-2028 24 10.9 0.0 194,697.7 0.0 -5,506.0 39,135.3 292,046.5 1,603,828.4 1,167,258.9 12-31-2029 20 8.7 0.0 180,412.5 1,179.4 -24,840.5 151,840.9 270,803.1 1,874,631.5 1,306,853.9 12-31-2030 59 24.5 0.0 180,212.3 1,203.0 -105,799.9 169,073.5 270,506.4 2,145,137.9 1,434,355.2 12-31-2031 62 23.8 0.0 149,306.0 612.8 -82,939.1 154,328.9 224,054.8 2,369,192.8 1,530,735.7 12-31-2032 59 22.3 0.0 115,882.6 -1.1 -37,272.2 73,457.5 173,823.8 2,543,016.5 1,597,603.7 12-31-2033 25 7.9 0.0 108,196.5 475.4 -37,231.1 65,735.2 162,652.9 2,705,669.4 1,653,180.9 12-31-2034 42 15.6 0.0 154,569.1 1,456.8 -174,260.4 163,420.2 232,233.3 2,937,902.7 1,724,974.8 12-31-2035 65 33.7 0.0 189,863.6 1,486.0 -297,995.5 291,026.1 285,101.5 3,223,004.2 1,806,839.9 12-31-2036 95 39.8 0.0 179,159.7 1,515.7 -309,581.7 310,177.1 269,118.9 3,492,123.0 1,877,778.0 SUBTOTAL 0.0 3,075,155.7 12,797.6 -1,083,563.0 1,558,065.8 3,492,123.0 3,492,123.0 1,877,778.0 REMAINING 0.0 -363,220.4 2,071.7 1,285,336.5 934,498.9 -545,159.1 2,946,963.9 1,812,942.5 TOTAL OF 25.5 YRS 0.0 2,711,935.3 14,869.3 201,773.5 2,492,564.6 2,946,963.9 2,946,963.9 1,812,942.5 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 110,818.6 9,977.9 60,026.3 2,779.6 144,271.6 8,597.1 160,049.7 19,159.3 114,681.7 16,069.5 105,878.0 14,800.9 106,028.3 16,228.0 147,704.1 22,928.3 134,424.2 22,991.8 112,705.4 19,708.6 74,542.5 12,527.2 48,393.7 8,108.5 1,716,235.0 226,035.7 51,070.5 7,638.1 89,582.4 12,378.0 97,945.4 12,879.8 1,558,122.5 206,772.8 158,112.5 19,262.9 05.000 2,307,240.2 10.000 1,812,942.5 15.000 1,455,685.2 20.000 1,199,403.0 25.000 1,013,084.5 30.000 874,771.1 50.000 571,195.1 35.000 769,722.8 40.000 688,140.0 45.000 623,454.6 Table IV
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE PROVED + PROBABLE + POSSIBLE (3P) RESERVES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESERVES WORKING INTEREST RESERVES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 42,104.4 167,296.7 10,876.3 31,628.2 784.3 17,113.7 102.20 33.466 71.89 1,111,597.4 2,226,457.2 12-31-2023 83,951.0 316,982.4 22,380.4 59,209.3 1,563.6 34,152.5 94.11 25.036 66.66 2,106,130.9 3,692,728.4 12-31-2024 89,982.4 280,512.7 23,194.6 56,279.5 1,538.4 34,436.4 83.98 16.127 60.05 1,947,851.9 2,947,835.1 12-31-2025 94,383.9 255,114.7 31,953.9 56,548.5 1,554.2 43,257.8 77.53 12.888 55.37 2,477,507.3 3,292,350.0 12-31-2026 85,307.3 218,662.0 30,057.2 46,291.8 1,256.3 39,294.8 78.57 10.653 55.85 2,361,490.2 2,924,789.8 12-31-2027 74,276.5 194,029.3 23,872.2 39,620.7 1,074.7 31,778.0 79.34 10.837 56.34 1,894,115.6 2,384,034.9 12-31-2028 65,281.6 170,995.2 19,507.1 33,915.9 934.9 26,289.6 81.33 11.039 57.59 1,586,582.9 2,009,832.2 12-31-2029 58,829.7 151,544.5 16,727.0 29,827.9 829.6 22,699.3 82.34 11.257 58.18 1,377,359.1 1,761,403.6 12-31-2030 50,741.9 126,185.4 12,657.3 23,737.2 671.4 17,421.4 84.30 11.362 59.00 1,067,060.9 1,376,371.2 12-31-2031 45,429.1 110,293.7 10,004.5 20,274.7 577.5 14,077.7 86.17 11.532 60.06 862,070.0 1,130,557.5 12-31-2032 38,466.4 93,212.7 7,996.0 15,737.8 429.5 11,138.9 89.31 11.667 61.19 714,139.8 924,032.7 12-31-2033 32,936.1 79,848.5 6,793.8 11,920.3 314.6 9,163.7 91.39 11.759 61.30 620,870.1 780,322.5 12-31-2034 28,882.1 69,918.0 5,988.9 10,672.9 271.8 8,100.9 94.41 11.966 62.85 565,430.3 710,222.0 12-31-2035 25,537.3 63,621.7 5,122.7 9,728.5 249.6 7,049.7 96.55 12.201 64.10 494,597.1 629,297.1 12-31-2036 22,943.8 56,334.7 4,545.7 8,728.7 219.5 6,270.1 99.57 12.439 65.87 452,608.4 575,642.1 SUBTOTAL 839,053.4 2,354,552.0 231,677.6 454,121.8 12,269.9 322,244.3 84.77 15.397 60.25 19,639,412.0 27,365,876.3 REMAINING 106,577.3 99,311.0 17,356.6 14,614.7 306.7 20,183.0 109.55 12.764 70.10 1,901,460.7 2,109,507.3 TOTAL 945,630.7 2,453,863.1 249,034.2 468,736.5 12,576.5 342,427.4 86.50 15.315 60.49 21,540,872.7 29,475,383.5 CUM PROD 8,710,81 ULTIMATE 11,164,67 FUTURE NET REVENUE NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% PRESENT WORTH PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CUM PW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 207 75.2 0.0 393,927.1 215,088.2 272.4 263,590.1 1,353,579.4 1,353,579.4 1,319,756.5 12-31-2023 223 80.2 0.0 618,694.0 368,048.9 194.4 555,464.4 2,150,326.6 3,503,906.1 3,276,566.5 12-31-2024 238 86.4 0.0 775,809.1 381,815.6 5.9 585,823.0 1,204,381.6 4,708,287.6 4,270,137.3 12-31-2025 252 94.1 0.0 1,387,063.4 321,477.2 0.0 636,828.0 946,981.4 5,655,269.0 4,975,465.7 12-31-2026 255 94.9 0.0 816,873.2 207,923.2 0.0 642,195.6 1,257,797.8 6,913,066.8 5,839,545.1 12-31-2027 256 93.8 0.0 588,821.2 239,722.9 6,560.8 628,241.5 920,688.5 7,833,755.3 6,411,639.3 12-31-2028 252 88.7 0.0 521,939.6 70,964.7 4,155.2 618,775.2 793,997.6 8,627,752.9 6,860,844.0 12-31-2029 244 82.9 0.0 435,348.5 52,476.2 6,224.6 606,132.0 661,222.2 9,288,975.1 7,201,649.5 12-31-2030 242 80.8 0.0 305,664.6 39,787.8 3,582.0 562,623.0 464,713.8 9,753,688.9 7,419,895.1 12-31-2031 237 74.5 0.0 220,859.2 24,945.8 8,776.8 540,789.0 335,186.6 10,088,875.5 7,562,517.3 12-31-2032 228 71.1 0.0 172,598.3 2,010.5 27,647.9 462,564.5 259,211.6 10,348,087.1 7,662,550.1 12-31-2033 188 54.8 0.0 101,814.6 2,291.9 112,276.3 410,859.8 153,079.9 10,501,167.0 7,715,563.2 12-31-2034 180 52.0 0.0 72,088.6 2,429.5 117,658.8 409,532.7 108,512.5 10,609,679.5 7,749,064.9 12-31-2035 175 50.3 0.0 74,187.5 1,959.0 52,354.0 389,209.2 111,587.4 10,721,266.9 7,781,095.7 12-31-2036 169 47.0 0.0 49,349.9 2,427.8 65,328.7 384,131.5 74,404.2 10,795,671.1 7,800,701.7 SUBTOTAL 0.0 6,535,038.8 1,933,369.2 405,037.7 7,696,759.5 10,795,671.1 10,795,671.1 7,800,701.7 REMAINING 0.0 -713,215.9 8,952.5 2,366,209.6 1,515,986.2 -1,068,425.1 9,727,246.0 7,640,053.0 TOTAL OF 25.5 YRS 0.0 5,821,822.9 1,942,321.6 2,771,247.3 9,212,745.7 9,727,246.0 9,727,246.0 7,640,053.0 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 907,600.4 92,382.7 1,058,477.2 56,382.6 1,482,367.6 104,229.8 728,792.8 86,049.9 493,142.3 70,157.3 429,368.2 60,551.0 374,410.1 53,839.3 335,772.6 48,271.8 269,695.6 39,614.6 233,799.5 34,688.1 183,612.2 26,280.8 140,165.4 19,287.0 7,178,741.7 760,769.1 127,710.9 17,080.8 118,700.4 15,999.6 108,578.7 14,455.0 6,992,194.1 739,270.2 186,547.6 21,498.9 05.000 8,648,742.2 10.000 7,640,053.0 15.000 6,805,122.4 20.000 6,132,296.4 25.000 5,589,526.7 30.000 5,147,096.3 50.000 3,993,724.4 35.000 4,781,659.4 40.000 4,475,718.8 45.000 4,216,295.5 Table V
SUMMARY PROJECTION OF RESOURCES AND CASH FLOW AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE LOW ESTIMATE (1C) CONTINGENT RESOURCES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESOURCES WORKING INTEREST RESOURCES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.000 0.00 0.0 0.0 12-31-2023 349.0 2,327.0 13.2 139.5 4.7 42.0 96.00 24.956 63.84 1,264.7 5,050.0 12-31-2024 3,978.2 14,028.2 1,304.6 4,587.9 67.0 2,162.6 84.00 16.429 62.26 109,587.1 189,135.5 12-31-2025 11,115.0 32,327.4 6,424.4 13,019.3 140.1 8,809.1 77.89 13.152 57.69 500,420.3 679,729.5 12-31-2026 22,788.7 59,241.7 9,284.0 24,359.6 99.5 13,583.5 78.70 10.850 59.95 730,646.6 1,000,922.2 12-31-2027 41,467.1 91,657.1 10,746.8 34,690.3 175.9 16,903.7 79.68 10.952 59.84 856,342.2 1,246,802.0 12-31-2028 44,950.1 79,912.2 14,112.1 30,488.6 133.9 19,502.6 81.79 11.208 61.28 1,154,284.0 1,504,212.9 12-31-2029 45,923.4 67,161.5 17,166.0 26,088.9 82.0 21,746.1 82.90 11.477 61.79 1,423,062.9 1,727,545.0 12-31-2030 38,083.7 50,219.0 14,233.9 18,325.1 10.2 17,403.6 84.95 11.522 62.67 1,209,136.5 1,420,908.9 12-31-2031 29,957.0 43,889.5 10,871.6 16,562.9 8.9 13,736.2 86.92 11.597 64.12 944,976.5 1,137,630.9 12-31-2032 23,615.2 38,047.9 8,084.7 15,154.2 1.4 10,698.9 89.87 11.688 66.33 726,531.5 903,752.9 12-31-2033 18,701.8 33,921.4 6,251.3 13,938.5 0.0 8,654.5 91.84 11.841 0.00 574,128.5 739,178.5 12-31-2034 15,720.4 28,014.5 5,231.1 11,558.9 0.0 7,224.0 94.81 12.127 0.00 495,942.2 636,113.0 12-31-2035 13,102.3 22,823.0 4,358.5 9,398.6 0.0 5,979.0 96.79 12.428 0.00 421,866.4 538,672.3 12-31-2036 10,305.5 19,332.0 3,425.9 8,124.4 0.0 4,826.6 99.80 12.913 0.00 341,911.0 446,820.9 SUBTOTAL 320,057.6 582,902.5 111,508.0 226,436.7 723.6 151,272.4 85.11 11.671 60.28 9,490,100.2 12,176,474.5 REMAINING 27,220.5 58,691.1 13,656.4 27,200.1 0.0 18,346.1 112.08 13.936 0.00 1,530,616.1 1,909,670.8 TOTAL 347,278.0 641,593.6 125,164.4 253,636.8 723.6 169,618.5 88.05 11.914 60.28 11,020,716.3 14,086,145.3 CUM PROD .0 ULTIMATE 347, FUTURE NET CASH FLOW NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% DISCOUNTED CASH FLOW PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CASH FLOW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 0 0.0 0.0 -40,294.4 89,543.0 0.0 0.0 -49,248.7 -49,248.7 -48,157.4 12-31-2023 1 0.1 0.0 -351,473.9 547,739.5 -5,502.5 282.0 -185,995.0 -235,243.7 -206,957.3 12-31-2024 7 2.5 0.0 -147,479.5 720,181.8 -1,978.8 3,746.3 -385,334.4 -620,578.0 -522,390.9 12-31-2025 16 9.1 0.0 -202,476.9 782,461.6 3,728.3 35,679.8 60,336.6 -560,241.5 -480,110.6 12-31-2026 34 14.2 0.0 -159,585.6 685,880.6 -3,456.2 134,560.3 343,523.1 -216,718.4 -247,491.6 12-31-2027 42 17.7 0.0 -97,274.3 745,418.8 -38,983.9 278,538.2 359,103.2 142,384.8 -22,941.9 12-31-2028 52 23.3 0.0 270,400.2 327,201.9 -569.6 276,246.7 630,933.7 773,318.5 328,881.6 12-31-2029 57 25.1 0.0 400,249.5 122,304.7 4,177.0 266,898.2 933,915.6 1,707,234.1 809,415.8 12-31-2030 56 22.3 0.0 340,762.8 143,241.3 -26,931.0 168,722.8 795,113.1 2,502,347.2 1,181,586.2 12-31-2031 56 20.3 0.0 269,068.4 137,327.4 -51,277.5 154,686.4 627,826.2 3,130,173.4 1,449,238.3 12-31-2032 64 21.3 0.0 219,176.5 25,184.6 34,210.3 169,629.1 455,552.4 3,585,725.8 1,625,749.9 12-31-2033 66 21.5 0.0 163,280.0 14,679.0 75,241.2 161,085.5 324,892.7 3,910,618.5 1,740,702.3 12-31-2034 70 22.5 0.0 125,169.4 19,411.5 85,099.6 155,202.8 251,229.7 4,161,848.2 1,821,504.2 12-31-2035 65 16.6 0.0 124,648.8 16,193.5 30,028.9 145,063.9 222,737.1 4,384,585.3 1,886,118.7 12-31-2036 66 17.3 0.0 54,292.9 77,431.4 31,393.2 158,976.6 124,726.8 4,509,312.1 1,918,985.4 SUBTOTAL 0.0 968,463.8 4,454,200.7 135,179.1 2,109,318.7 4,509,312.1 4,509,312.1 1,918,985.4 REMAINING 0.0 -238,358.9 0.0 1,133,009.9 1,123,232.9 -108,213.0 4,401,099.1 1,958,529.3 TOTAL OF 25.4 YRS 0.0 730,105.0 4,454,200.7 1,268,189.0 3,232,551.6 4,401,099.1 4,401,099.1 1,958,529.3 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 75,376.6 4,171.8 0.0 0.0 3,482.2 303.2 171,227.7 8,081.5 264,308.5 5,967.1 379,935.4 10,524.4 341,726.0 8,203.0 299,416.1 5,066.0 211,134.7 637.7 192,083.1 571.2 177,129.5 92.0 165,050.0 0.0 3,021,811.1 43,618.0 140,170.8 0.0 116,805.8 0.0 104,910.0 0.0 2,642,756.3 43,618.0 379,054.8 0.0 05.000 2,952,775.1 10.000 1,958,529.3 15.000 1,301,225.3 20.000 864,374.9 25.000 569,313.2 30.000 366,487.7 50.000 1,064.8 35.000 224,822.8 40.000 124,539.8 45.000 52,793.3 Table VI
SUMMARY PROJECTION OF RESOURCES AND CASH FLOW AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE BEST ESTIMATE (2C) CONTINGENT RESOURCES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESOURCES WORKING INTEREST RESOURCES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.000 0.00 0.0 0.0 12-31-2023 486.6 3,244.3 18.4 194.5 6.6 58.5 96.00 24.956 63.84 1,763.3 7,040.8 12-31-2024 3,179.1 8,566.7 417.1 1,405.0 17.7 677.0 83.19 17.181 60.33 34,694.3 59,902.4 12-31-2025 18,443.1 72,989.3 7,998.8 19,973.3 191.1 11,633.6 77.88 13.599 57.64 622,936.8 905,578.7 12-31-2026 35,948.8 94,459.3 14,693.3 33,205.0 126.9 20,545.2 78.75 10.768 58.92 1,157,083.3 1,522,103.1 12-31-2027 57,601.9 128,328.4 15,870.7 42,946.5 77.6 23,352.8 79.72 10.865 59.92 1,265,238.8 1,736,493.5 12-31-2028 60,667.4 108,627.2 18,996.4 37,521.4 51.1 25,516.7 81.80 11.095 61.71 1,553,919.1 1,973,368.7 12-31-2029 64,975.0 100,145.4 24,285.1 37,147.3 95.1 30,784.9 82.80 11.441 62.91 2,010,927.4 2,441,917.6 12-31-2030 64,200.3 92,008.3 25,783.0 36,787.1 166.0 32,291.6 84.86 11.670 63.64 2,187,858.6 2,627,746.3 12-31-2031 56,092.4 78,536.6 21,616.2 31,055.1 89.3 27,059.8 86.85 11.840 65.48 1,877,332.8 2,250,877.3 12-31-2032 45,426.5 64,767.9 16,078.7 25,013.8 19.3 20,410.7 89.80 11.930 71.24 1,443,817.9 1,743,606.2 12-31-2033 37,097.6 54,991.0 12,619.1 21,327.7 0.4 16,296.7 91.88 11.938 71.12 1,159,383.7 1,414,017.1 12-31-2034 31,827.6 50,268.1 10,587.6 19,871.4 0.3 14,014.1 94.81 12.148 73.43 1,003,809.3 1,245,240.6 12-31-2035 26,768.5 41,875.9 8,454.9 16,389.0 0.1 11,280.6 96.74 12.461 74.98 817,915.0 1,022,136.3 12-31-2036 22,209.5 35,334.6 6,846.3 13,842.6 0.0 9,232.9 99.74 12.930 0.00 682,817.9 861,809.4 SUBTOTAL 524,924.4 934,142.9 184,265.4 336,679.6 841.5 243,155.1 85.85 11.705 61.33 15,819,498.1 19,811,838.0 REMAINING 151,955.5 182,818.7 47,909.0 61,588.9 0.0 58,527.8 122.41 15.092 0.00 5,864,650.0 6,794,169.9 TOTAL 676,879.8 1,116,961.6 232,174.4 398,268.5 841.5 301,682.9 93.40 12.229 61.33 21,684,148.1 26,606,007.9 CUM PROD 0.0 0.0 ULTIMATE 676,879.8 1,116,961.6 FUTURE NET CASH FLOW NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% DISCOUNTED CASH FLOW PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CASH FLOW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 0 0.0 0.0 -40,294.4 89,543.0 0.0 0.0 -49,248.7 -49,248.7 -48,157.4 12-31-2023 1 0.1 0.0 -346,509.5 506,388.2 0.0 362.2 -153,200.1 -202,448.8 -176,791.3 12-31-2024 5 1.0 0.0 -302,709.9 939,912.0 0.0 3,555.8 -580,855.6 -783,304.4 -647,758.8 12-31-2025 21 10.4 0.0 -622,645.7 890,892.5 -5,724.8 48,285.8 594,771.0 -188,533.4 -208,311.0 12-31-2026 40 16.3 0.0 86,118.5 697,233.1 -419.7 123,104.2 616,067.0 427,533.6 209,211.0 12-31-2027 44 17.7 0.0 159,296.4 734,620.4 -2,378.0 205,337.0 639,617.8 1,067,151.4 610,647.6 12-31-2028 57 24.2 0.0 450,130.8 469,752.9 3,998.8 210,375.9 839,110.4 1,906,261.8 1,081,305.9 12-31-2029 67 31.1 0.0 686,349.9 364,734.9 -2,644.9 306,963.1 1,086,514.7 2,992,776.4 1,639,077.4 12-31-2030 76 34.6 0.0 850,244.3 158,747.3 -36,373.1 354,956.8 1,300,170.8 4,292,947.2 2,246,518.3 12-31-2031 77 34.9 0.0 710,074.7 137,327.4 3,168.5 313,737.3 1,086,569.4 5,379,516.7 2,710,490.5 12-31-2032 81 32.8 0.0 569,658.3 25,184.6 24,848.2 265,492.6 858,422.5 6,237,939.2 3,042,683.5 12-31-2033 80 31.5 0.0 491,361.8 14,679.0 -51,187.5 219,543.5 739,620.2 6,977,559.4 3,302,619.7 12-31-2034 82 31.3 0.0 420,769.3 19,411.5 -47,509.2 218,230.1 634,338.9 7,611,898.3 3,505,186.4 12-31-2035 75 24.6 0.0 280,225.2 16,193.5 97,302.0 205,473.6 422,942.0 8,034,840.3 3,628,859.9 12-31-2036 75 25.1 0.0 183,795.0 77,431.4 100,828.4 211,821.0 287,933.6 8,322,773.9 3,705,443.7 SUBTOTAL 0.0 3,575,864.8 5,142,051.8 83,908.6 2,687,238.9 8,322,773.9 8,322,773.9 3,705,443.7 REMAINING 0.0 736,733.3 0.0 1,608,360.5 3,344,628.2 1,104,447.9 9,427,221.8 3,994,985.5 TOTAL OF 40.9 YRS 0.0 4,312,598.1 5,142,051.8 1,692,269.0 6,031,867.1 9,427,221.8 9,427,221.8 3,994,985.5 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 24,138.7 1,069.4 0.0 0.0 4,854.9 422.7 271,625.6 11,016.3 357,542.2 7,477.6 466,607.6 4,647.1 416,295.9 3,153.7 425,009.5 5,980.7 429,322.1 10,565.5 367,698.9 5,845.6 298,414.2 1,374.1 254,602.6 30.7 4,870,245.5 51,614.3 241,406.1 25.2 204,215.7 5.6 178,991.5 0.0 3,940,725.6 51,614.3 929,519.9 0.0 05.000 6,091,449.6 10.000 3,994,985.5 15.000 2,705,167.1 20.000 1,882,466.0 25.000 1,337,281.2 30.000 964,040.4 50.000 271,404.3 35.000 701,537.6 40.000 512,743.6 45.000 374,396.3 Table VII
SUMMARY PROJECTION OF RESOURCES AND CASH FLOW AS OF JUNE 30, 2022 SUMMARY - CERTAIN PROPERTIES ITHACA ENERGY (UK) LIMITED INTEREST LOCATED IN THE UNITED KINGDOM SECTOR OF THE HIGH ESTIMATE (3C) CONTINGENT RESOURCES NORTH SEA AND IN THE NORTH ATLANTIC OCEAN PERIOD GROSS RESOURCES WORKING INTEREST RESOURCES AVERAGE PRICES WORKING INTEREST REVENUE AFTER ROYALTIES ENDING OIL GAS OIL GAS NGL EQUIV OIL GAS NGL OIL GAS NGL TOTAL M-D-Y MBBL MMCF MBBL MMCF MBBL MBOE $/BBL $/MCF $/BBL M$ M$ M$ M$ 12-31-2022 0.0 0.0 0.0 0.0 0.0 0.0 0.00 0.000 0.00 0.0 0.0 12-31-2023 532.3 3,548.4 20.1 212.8 7.2 64.0 96.00 24.956 63.84 1,928.5 7,700.7 12-31-2024 3,940.7 10,163.0 534.7 1,819.1 20.5 868.8 83.06 17.244 60.57 44,408.1 77,019.1 12-31-2025 25,332.2 67,954.3 8,881.4 14,958.5 71.7 11,532.1 77.97 14.217 58.33 692,524.7 909,365.5 12-31-2026 49,696.4 118,056.8 19,286.3 41,064.4 246.2 26,612.6 78.87 10.826 58.56 1,521,158.3 1,980,144.7 12-31-2027 78,070.5 166,345.6 22,581.0 56,134.7 158.6 32,418.0 79.69 10.789 59.44 1,799,527.1 2,414,582.6 12-31-2028 84,792.9 157,800.0 27,238.2 54,538.6 106.2 36,747.6 81.74 11.057 61.12 2,226,359.0 2,835,891.9 12-31-2029 93,371.6 142,943.7 34,298.2 51,501.3 74.1 43,251.8 82.82 11.351 62.10 2,840,689.5 3,429,881.4 12-31-2030 91,480.4 136,151.5 33,454.2 48,201.2 73.6 41,838.3 84.79 11.612 64.79 2,836,424.7 3,400,899.4 12-31-2031 84,502.6 121,314.2 30,760.7 44,017.4 62.9 38,412.8 86.73 11.848 67.18 2,667,823.0 3,193,558.6 12-31-2032 76,178.6 109,714.1 27,811.5 41,777.3 82.0 35,096.5 89.77 12.108 68.57 2,496,575.0 3,008,030.9 12-31-2033 70,325.5 103,892.2 26,707.1 42,200.9 181.7 34,164.8 91.81 12.352 68.50 2,451,950.2 2,985,678.9 12-31-2034 60,580.2 93,086.1 21,086.5 37,543.9 148.6 27,708.1 94.77 12.541 70.73 1,998,309.4 2,479,656.8 12-31-2035 53,330.4 74,627.9 17,602.9 28,591.2 89.4 22,621.8 96.83 12.775 71.70 1,704,500.6 2,076,154.8 12-31-2036 45,881.2 57,710.3 14,806.5 20,337.5 0.5 18,313.5 99.85 13.192 77.30 1,478,461.6 1,746,802.6 SUBTOTAL 818,015.5 1,363,308.2 285,069.3 482,898.8 1,323.2 369,650.9 86.86 11.803 64.12 24,760,639.7 30,545,367.9 REMAINING 335,153.6 386,001.6 84,312.8 104,335.9 0.8 102,302.5 120.30 15.729 80.60 10,143,060.8 11,784,215.9 TOTAL 1,153,169.1 1,749,309.9 369,382.1 587,234.7 1,324.0 471,953.4 94.49 12.501 64.13 34,903,700.6 42,329,583.9 CUM PROD 0.0 0.0 ULTIMATE 1,153,169.1 1,749,309.9 FUTURE NET CASH FLOW NET DEDUCTIONS/EXPENDITURES AFTER UK CORPORATE INCOME TAXES PERIOD NUMBER OF TAXES CAPITAL ABDNMNT OPERATING UNDISCOUNTED DISC AT 10.000% DISCOUNTED CASH FLOW PROFILE ENDING ACTIVE COMPLETIONS PRODUCTION INCOME COST COST EXPENSE PERIOD CUM CUM DISC RATE CASH FLOW M-D-Y GROSS NET M$ M$ M$ M$ M$ M$ M$ M$ % M$ 12-31-2022 0 0.0 0.0 -40,294.4 89,543.0 0.0 0.0 -49,248.7 -49,248.7 -48,157.4 12-31-2023 1 0.1 0.0 -211,004.7 472,961.5 0.0 388.7 -254,644.9 -303,893.5 -270,161.1 12-31-2024 5 1.0 0.0 -752,786.9 919,811.6 0.0 4,013.6 -94,019.2 -397,912.7 -338,456.9 12-31-2025 21 8.7 0.0 -508,971.5 1,001,679.7 0.0 48,640.0 368,017.3 -29,895.4 -70,208.9 12-31-2026 42 16.2 0.0 255,143.8 730,323.5 0.0 143,071.6 851,605.8 821,710.4 504,738.7 12-31-2027 46 17.1 0.0 521,235.1 766,865.0 -5,956.1 230,763.3 901,675.4 1,723,385.8 1,068,076.4 12-31-2028 64 27.3 0.0 792,669.4 525,019.8 -436.6 247,600.9 1,271,038.5 2,994,424.3 1,780,744.5 12-31-2029 78 35.0 0.0 1,085,361.2 370,055.7 -776.2 289,377.8 1,685,863.0 4,680,287.2 2,646,325.8 12-31-2030 78 35.8 0.0 1,142,617.7 191,081.0 429.0 322,988.6 1,743,783.0 6,424,070.2 3,461,321.6 12-31-2031 91 39.8 0.0 1,074,301.5 161,184.6 4,141.9 317,293.2 1,636,637.4 8,060,707.6 4,157,644.1 12-31-2032 97 38.9 0.0 1,040,833.2 54,381.3 -1,662.6 344,731.9 1,569,747.0 9,630,454.6 4,764,358.8 12-31-2033 98 39.6 0.0 1,045,610.1 22,018.6 -37,783.3 383,977.9 1,571,855.6 11,202,310.2 5,317,517.0 12-31-2034 101 39.3 0.0 841,612.9 23,154.6 -23,589.2 372,441.3 1,266,037.3 12,468,347.4 5,722,174.1 12-31-2035 99 37.8 0.0 695,634.9 16,193.5 -3,308.7 321,652.5 1,045,982.6 13,514,330.0 6,026,196.3 12-31-2036 94 35.0 0.0 560,245.6 77,431.4 -9,691.0 266,349.5 852,467.1 14,366,797.1 6,251,689.0 SUBTOTAL 0.0 7,542,208.1 5,421,704.9 -78,632.9 3,293,290.7 14,366,797.1 14,366,797.1 6,251,689.0 REMAINING 0.0 2,237,556.4 0.0 1,818,042.9 4,372,282.1 3,356,334.6 17,723,131.7 6,919,249.3 TOTAL OF 50.0 YRS 0.0 9,779,764.5 5,421,704.9 1,739,410.0 7,665,572.8 17,723,131.7 17,723,131.7 6,919,249.3 check All estimates and exhibits herein are art of the NSAI report and are subject to its parameters and conditions. BASED ON ESCALATED PRICE AND COST PARAMETERS 31,368.7 1,242.2 0.0 0.0 5,309.9 462.3 212,659.1 4,181.7 444,567.6 14,418.7 605,628.7 9,426.8 603,039.7 6,493.2 584,593.1 4,598.8 559,709.3 4,765.3 521,510.5 4,225.1 505,833.9 5,622.0 521,280.4 12,448.3 7,340,978.8 84,904.5 470,839.5 10,507.9 365,244.1 6,410.1 268,301.2 39.9 5,699,885.7 84,842.5 1,641,093.1 62.0 05.000 10,806,835.7 10.000 6,919,249.3 15.000 4,636,133.2 20.000 3,222,538.7 25.000 2,306,220.6 30.000 1,689,206.0 50.000 564,403.7 35.000 1,260,371.6 40.000 954,281.8 45.000 730,793.7 Table VIII
TECHNICAL DISCUSSION SECTION 1.0 – OVERVIEW
Page 1 TECHNICAL DISCUSSION UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN AS OF JUNE 30, 2022 1.0 OVERVIEW __________________________________________________________________ Netherland, Sewell & Associates, Inc. (NSAI) has estimated the proved, probable, and possible reserves and future revenue, as of June 30, 2022, to the Ithaca Energy (UK) Limited (referred to herein as "Ithaca") interest in certain oil and gas properties located in the United Kingdom (UK) Sector of the North Sea and in the North Atlantic Ocean. We have also estimated the contingent resources and cash flow, as of June 30, 2022, to the Ithaca interest in certain discoveries located in the UK Sector of the North Sea and in the North Atlantic Ocean. Working interest volumes shown in this report are after deductions for shrinkage to account for processing, fuel, and flare. A summary of interests and license status for the properties evaluated in this Competent Person's Report (report) is shown in Figure 1.1.1. A map of the relative positions of the properties is shown in Figure 1.1.2. The table below shows the operator, primary fluid, Ithaca working interest, and whether a geologic evaluation was performed for each field included in this evaluation. Ithaca Primary Working Geologic Field Group/Area/Field Operator Fluid Interest (%) Evaluation Captain Field Ithaca Energy (UK) Limited Oil 085.000 Yes Greater Stella Area Stella Field Ithaca Energy (UK) Limited Gas 100.000 Yes Harrier Field Ithaca Energy (UK) Limited Oil/Gas 100.000 Yes Vorlich Field Ithaca Energy (UK) Limited Oil 034.000 Yes Abigail Field Ithaca Energy (UK) Limited Oil/Gas 100.000 Yes Courageous Field Ithaca Energy (UK) Limited Oil 055.000 Yes Schiehallion Field BP Exploration Operating Company Limited Oil 011.754 No Greater Britannia Area Britannia Field Harbour Energy plc Gas 032.380 No Alder Field Ithaca Energy (UK) Limited Gas 073.684 Yes Brodgar Field Harbour Energy plc Gas 006.250 Yes Callanish Field Harbour Energy plc Oil 016.500 Yes Enochdhu Field Harbour Energy plc Oil 050.000 No MonArb Area Montrose Field Repsol Sinopec Resources UK Oil 041.026 No Arbroath Field Repsol Sinopec Resources UK Oil 041.026 No Arkwright Field Repsol Sinopec Resources UK Oil 041.026 No Brechin Field Repsol Sinopec Resources UK Oil 041.026 No Cayley Field Repsol Sinopec Resources UK Gas 041.026 Yes Godwin Field Repsol Sinopec Resources UK Oil 041.026 No Shaw Field Repsol Sinopec Resources UK Oil 041.026 Yes Wood Field Repsol Sinopec Resources UK Oil 041.026 No Mariner Area Mariner Field Equinor UK Limited Oil 008.889 Yes Mariner East Field Equinor UK Limited Oil 008.889 Yes Cadet Field Equinor UK Limited Oil 008.889 Yes
Page 2 Ithaca Primary Working Geologic Field Group/Area/Field Operator Fluid Interest (%) Evaluation Jade and Jade South Fields Harbour Energy plc Gas 025.500 No Cook Field Ithaca Energy (UK) Limited Oil 061.346 Yes Erskine Field Ithaca Energy (UK) Limited Gas 050.000 Yes Elgin-Franklin Field TotalEnergies E&P U.K. Limited Gas 006.088 Yes Alba Field Ithaca Energy (UK) Limited Oil 036.670 No Pierce Field Shell UK Exploration & Production Oil/Gas 007.483 Yes Columba Terraces Area B/D Terrace Canadian Natural Resources Limited Oil 005.600 No E Terrace Canadian Natural Resources Limited Oil 008.400 No Cambo Field Ithaca Energy (UK) Limited Oil 070.000 Yes Rosebank Field Equinor UK Limited Oil 020.000 Yes Tornado Field Ithaca Energy (UK) Limited Oil 050.000 Yes Marigold Field Ithaca Energy (UK) Limited Oil 100.000 Yes Fotla Field Ithaca Energy (UK) Limited Oil/Gas 060.000 Yes Isabella Field TotalEnergies E&P U.K. Limited Oil 010.000 Yes Leverett Field NEO Energy Oil/Gas 015.000 Yes Decommissioning Assets Pickerill Field Perenco UK Ltd Oil 005.217 No Renee Field Hess Corporation Oil 008.500 No Rubie Field Hess Corporation Oil 040.000 No The estimates in this report have been prepared in accordance with the definitions and guidelines set forth in the 2018 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE) and in accordance with the recommendations of the Financial Conduct Authority (FCA), as set out in Primary Market Technical Note 619.1 – the Guidelines on disclosure requirements under the Prospectus Regulation and Guidance on specialist issuers published by the FCA. As presented in the 2018 PRMS, petroleum accumulations can be classified, in decreasing order of likelihood of commerciality, as reserves, contingent resources, or prospective resources. Different classifications of petroleum accumulations have varying degrees of technical and commercial risk that are difficult to quantify; thus reserves, contingent resources, and prospective resources should not be aggregated without extensive consideration of these factors. During the course of our evaluation, Ithaca provided access to engineering, geologic, and economic data. Data provided included, but were not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. All data sources were used, as appropriate, for the evaluation of the properties. The reserves and contingent resources in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles set forth in the
Page 3 Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines.
1.1 FIGURES
SUMMARY OF INTERESTS AND LICENSE STATUS UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN AS OF JUNE 30, 2022 Ithaca Working Field Group/Area/Field Operator License (1) Anticipated License Expiration Date (1) Blocks Interest (%) Captain Field Ithaca Energy (UK) Limited P.324 Cessation of Production 13/22a ALL 85.000 P.2513 11-30-2026 (Second Term End) 11-30-2044 (License End) 13/21b, 13/22b 100.000 Greater Stella Area Stella Field Ithaca Energy (UK) Limited P.11 Cessation of Production 30/6a D, 29/10a C 100.000 Harrier Field Ithaca Energy (UK) Limited P.11 Cessation of Production 30/6a D, 29/10a C 100.000 Vorlich Field Ithaca Energy (UK) Limited P.363 Cessation of Production 30/1c LOWER 50.000 30/1c UPPER 20.000 P.1588 02-11-2035 (License End) 30/1f ALL 100.000 Abigail Field Ithaca Energy (UK) Limited P.1665 02-11-2035 (License End) 29/10b ALL 100.000 Courageous Field Ithaca Energy (UK) Limited P.2397 09-30-2022 (License Relinquished) (2) 30/1e ALL, 30/2e ALL 55.000 Schiehallion Field BP Exploration Operating Company Limited P.556 06-13-2033 (License End) 204/20a (3.1) 11.754 (3) P.559 Cessation of Production 204/25a 11.754 Greater Britannia Area Britannia Field Harbour Energy plc P.103 Cessation of Production 15/30a S-BRI 33.030 15/30a L-RST 50.634 P.119 Cessation of Production 15/29a AREA B, 15/29a AREA C 75.000 P.213 Cessation of Production 16/26a B-BRI, 16/26a D-BEL 33.167 P.345 Cessation of Production 16/27b AREA A, 16/27b AREA B 33.750 P.225 Cessation of Production 16/27c - Alder Field Ithaca Energy (UK) Limited P.119 Cessation of Production 15/29a ALDER, 15/29a AREA A 73.684 Brodgar Field Harbour Energy plc P.118 Cessation of Production 21/3a ALL 6.250 P.741 06-13-2027 (License End) 21/3b - P.2350 09-30-2024 (Initial Term End) 09-30-2028 (Second Term End) 09-30-2045 (License End) 21/4c - Callanish Field Harbour Energy plc P.347 Cessation of Production 21/4a ALL 13.700 P.590 06-03-2023 (License End) 15/29b ALL 20.000 Enochdhu Field Harbour Energy plc P.103 Cessation of Production 21/5a ALL 50.000 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 1.1.1 Page 1 of 4
SUMMARY OF INTERESTS AND LICENSE STATUS UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN AS OF JUNE 30, 2022 Ithaca Working Field Group/Area/Field Operator License (1) Anticipated License Expiration Date (1) Blocks Interest (%) MonArb Area Montrose Field Repsol Sinopec Resources UK P.19, P.20 Cessation of Production 22/17n, 22/18n 41.026 Arbroath Field Repsol Sinopec Resources UK P.19, P.291, P.292 Cessation of Production 22/17n, 22/17s, 22/18a, 22/22a 41.026 Arkwright Field Repsol Sinopec Resources UK P.291 Cessation of Production 22/23a 41.026 Brechin Field Repsol Sinopec Resources UK P.291 Cessation of Production 22/23a 41.026 Cayley Field Repsol Sinopec Resources UK P.291 Cessation of Production 22/17s 41.026 Godwin Field Repsol Sinopec Resources UK P.19, P.291 Cessation of Production 22/17s, 22/17n 41.026 Shaw Field Repsol Sinopec Resources UK P.291 Cessation of Production 22/22a 41.026 Wood Field Repsol Sinopec Resources UK P.292 Cessation of Production 22/18a 41.026 Mariner Area Mariner Field Equinor UK Limited P.335 Cessation of Production 9/11a 8.889 P.979 12-22-2034 (License End) 9/11c 8.889 P.2151 11-30-2022 (Second Term End) 11-30-2040 (License End) 9/11g 8.889 Mariner East Field Equinor UK Limited P.726 03-30-2023 (Second Term End) 06-13-2027 (License End) 9/11b 8.889 Cadet Field Equinor UK Limited P.1758 01-09-2037 (License End) 8/15a 8.889 Jade and Jade South Fields Harbour Energy plc P.672 07-19-2025 (License End) 30/2c JADE, 30/7b ALL 25.500 P.1589 02-11-2035 (License End) 30/7b ALL 25.500 Cook Field Ithaca Energy (UK) Limited P.185 Cessation of Production 21/20a ALL 61.346 Erskine Field Ithaca Energy (UK) Limited P.57 Cessation of Production 23/26a AREA B, 23/26b AREA B 50.000 P.264 Cessation of Production 23/26b AREA C, 23/26d AREA C 50.000 Elgin-Franklin Field TotalEnergies E&P U.K. Limited P.188 Cessation of Production 22/30b ELGN 6.088 P.362 Cessation of Production 29/5b ALL 6.088 P.666 07-19-2025 (License End) 22/30c ALL, 29/5c ALL 6.088 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 1.1.1 Page 2 of 4
SUMMARY OF INTERESTS AND LICENSE STATUS UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN AS OF JUNE 30, 2022 Ithaca Working Field Group/Area/Field Operator License (1) Anticipated License Expiration Date (1) Blocks Interest (%) Alba Field Ithaca Energy (UK) Limited P.213 Cessation of Production 16/26a A-ALB 36.670 16/26a C-10K 21.850 P.2373 09-30-2026 (Second Term End) 09-30-2044 (License End) 22/1b ALL 60.000 Pierce Field Shell UK Exploration & Production P.111 Cessation of Production 23/22a ALL 7.483 P.114 Cessation of Production 23/27a - Columba Terraces Area B/D Terrace Canadian Natural Resources Limited P.199, P.203 Cessation of Production 3/7a, 3/8a 5.600 E Terrace Canadian Natural Resources Limited P.203 Cessation of Production 3/7a 8.400 Cambo Field Ithaca Energy (UK) Limited P.1028 03-31-2024 (Second Term End) 05-31-2037 (License End) 204/9a, 204/10a 70.000 P.1189 03-31-2024 (Second Term End) 11-30-2030 (License End) 204/4a, 204/5a 70.000 Rosebank Field Equinor UK Limited P.1026 05-31-2024 (Second Term End) 05-31-2037 (License End) 213/26b, 213/27a 20.000 P.1191 05-31-2024 (Second Term End) 11-30-2030 (License End) 205/1a 20.000 P.1272 05-31-2024 (Second Term End) 12-21-2031 (License End) 205/2a 20.000 Tornado Field Ithaca Energy (UK) Limited P.2403 09-30-2026 (Initial Term End) 09-30-2030 (Second Term End) 09-30-2048 (License End) 204/13,14d 50.000 Marigold Field Ithaca Energy (UK) Limited P.2158 11-30-2022 (Second Term End) 11-30-2040 (License End) 15/18b ALL 100.000 Fotla Field Ithaca Energy (UK) Limited P.2373 09-30-2026 (Second Term End) 09-30-2044 (License End) 22/1b 60.000 Isabella Field TotalEnergies E&P U.K. Limited P.1820 09-30-2025 (Second Term End) 01-09-2037 (License End) 30/11a, 30/12d 10.000 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 1.1.1 Page 3 of 4
SUMMARY OF INTERESTS AND LICENSE STATUS UNITED KINGDOM SECTOR OF THE NORTH SEA AND THE NORTH ATLANTIC OCEAN AS OF JUNE 30, 2022 Ithaca Working Field Group/Area/Field Operator License (1) Anticipated License Expiration Date (1) Blocks Interest (%) Leverett Field NEO Energy P.118 Cessation of Production 21/3a (4.1) 25.000 (4) P.2350 09-30-2024 (Initial Term End) 09-30-2028 (Second Term End) 09-30-2045 (License End) 21/2d - Decommissioning Assets (5) Pickerill Field Perenco UK Ltd N/A - 48/11a 5.217 Renee Field Hess Corporation N/A - 15/27a 8.500 Rubie Field Hess Corporation N/A - 15/28b 40.000 (1) (2) (3) (4) (5) These assets do not have active licenses because they are not producing, and it is our understanding that the operators have no plans to produce them in the future. It is our understanding that Ithaca owns a 25.000 percent interest in Block 21/3a. It is also our understanding that this block is expected to be unitized with other blocks in which Ithaca does not own an interest, and that Ithaca is expected to own a 15.000 percent interest in the resulting unitized field. It is our understanding that Schiehallion Field has been unitized, and that Ithaca owns an 11.754 percent interest in the unitized field. The anticipated license end dates shown for licenses related to producing fields may be subject to extension. For licenses with multiple terms, the anticipated license end date shown is the date the license will expire if the license progresses to each term on its scheduled date, which depends on the fulfillment of certain obligations required by the North Sea Transition Authority. It is our understanding that Ithaca relinquished license P.2397 for Courageous Field effective September 30, 2022; however, for the purposes of this report, we have used the following anticipated license expiration dates, which we understood to be in effect at the time of our evaluation: September 30, 2024 (Initial Term End), September 30, 2028 (Second Term End), and September 30, 2045 (License End). All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 1.1.1 Page 4 of 4
Page 4 2.0 CAPTAIN FIELD ______________________________________________________________ Captain Field is an oil field located in Block 13/22a in the UK Sector of the North Sea, approximately 145 kilometers (km) northeast of Aberdeen in a water depth of approximately 370 feet (ft). Captain Field is shown on the location map in Figure 2.5.1, and it produces oil from four reservoirs: the Upper Captain Sandstone (UCS), the Lower Captain Sandstone (LCS), the Ross Sandstone, and the Burns Sandstone. For each of these reservoirs, the trap is defined by a stratigraphic pinch-out. A summary of certain geologic characteristics and petrophysical parameters for Captain Field is shown in the table below. Reservoir Depth (ft TVDSS) Primary Fluid Solution GOR (CF/BBL) Average Porosity (%) Average Swi (%) UCS 2,700 Oil 150 30 10 LCS 2,800 Oil 100 31 37 Burns 3,250 Oil 130 29 38 Ross 3,500 Oil 130 28 27 For Captain Field, we used decline curve analysis (DCA), dimensionless response, volumetric analysis, and analogy to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used by category for Captain Field is shown in the table below. Category Evaluation Methods Producing Wells under Waterflood DCA Producing Wells under Polymer Flood DCA and Dimensionless Response Undeveloped Polymer Flood Groups Analogy Other Upside Opportunities Classified as Reserves Analogy and Volumetric Analysis Other Upside Opportunities Classified as DCA, Dimensionless Response, Volumetric Contingent Resources Analysis, and Analogy Development plans for Captain Field were provided by Ithaca. A summary of the development timing for projects in Captain Field is shown in the table below. Project Timing Class 12th Campaign 2022 Reserves 13th Campaign 2024–2025 Reserves 14th Campaign 2026–2027 Reserves 15th Campaign 2028 Contingent Resources EOR Stage 2 2022–2028 Reserves B26Y Well 2023 Reserves Jurassic Well 2025 Reserves C Far East 2025–2029 Contingent Resources Greater LCS 2029 Contingent Resources Ross-E 2029 Contingent Resources Southern Terrace 2028–2030 Contingent Resources 2.1 OVERVIEW Captain Field was discovered in 1977 and began producing in March 1997. There are currently 42 active wells: 7 water injection, 4 polymer injection, 17 producing under waterflood, and 14 producing under
Page 5 polymer flood. Oil at Captain Field is heavy, with oil gravity ranging from 19 to 21 degrees API; this oil has a relatively low gas-oil ratio (GOR) and an in situ viscosity between 47 and 150 centipoise (cP) at the mean reservoir temperature of 87°F. However, production is possible because of the high in situ permeability, which averages 7 darcies (D), the use of horizontal wells with long lateral lengths, and the water injection program, which began at the onset of production in 1997. Captain Field is divided into three areas: Area A to the west, Area B in the center, and Area C to the east. These areas are shown on the depth structure maps in Figures 2.5.2 and 2.5.3. The initial development targeted Area A and utilized a manned wellhead production and drilling platform facility, WPP-A, tied back to a floating production storage and offloading (FPSO) vessel. Shuttle tankers are used for offshore loading of the Captain Field crude oil. A second wellhead platform bridge-linked to WPP-A was installed in 2000. A subsea manifold called the Unitised Template Manifold (UTM), christmas trees, wellheads, and control systems were installed in May 2000 to allow for the commissioning and commencement of development drilling in Area B during the summer of 2000. In June 2005, Chevron North Sea Limited (Chevron) began development of Captain Area C. Two production wells were drilled initially, and first production from the area occurred in July 2006. The wells are tied back to an extension mini-manifold attached to the UTM. Area A wells have electric submersible pumps (ESPs) installed. Because of the local gas cap, Area B wells use hydraulic submersible pumps for pumping the multi-phase fluids. An enhanced oil recovery (EOR) project of polymerized water injection is being deployed in the field. Some initial facilities were included in the original design to facilitate a polymer injection project. Captain Field produces from the UCS, the LCS, and the Ross and Burns Sandstones (collectively referred to as Ross). Depth structure maps on the tops of the UCS and LCS are shown in Figures 2.5.2 and 2.5.3, respectively. The UCS can be divided into two distinct accumulations. The Main accumulation comprises Areas A and B, and the East accumulation comprises Area C. A summary graph of the gross historical production for Captain Field is shown in Figure 2.5.4. Cumulative and recent production for Captain Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir (Area) Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) UCS (Areas A/B) 221,400 46,392 1,138,503 18,546 4,805 250,891 UCS (Area C) 053,269 12,792 0,155,789 04,200 0,843 044,081 LCS 051,131 06,555 0,236,267 02,262 0,563 046,420 Ross 029,343 04,820 0,080,322 - - - Total 355,142 70,559 1,610,881 25,008 6,211 341,392 Totals may not add because of rounding. 2.2 GEOLOGY Captain Field is composed of two related structures, the Main and East accumulations. The trap is further defined by a stratigraphic pinch-out. The principal reservoirs consist of Lower Cretaceous marine turbidites subdivided into the UCS and LCS. The shallow marine Jurassic Ross Sandstone and Jurassic Burns Sandstone are also productive in the field. Type log sections illustrating these formations are shown in Figures 2.5.5 and 2.5.6.
Page 6 2.3 METHODOLOGY Producing Wells Under Waterflood Nearly all active wells that are being produced via waterflood drive have sufficient production history to estimate future production through performance-based analysis. DCA was performed by estimating the total liquid production rate and water-oil ratio (WOR), using different trends for the proved (1P), proved plus probable (2P), and proved plus probable plus possible (3P) cases, and then using these values to calculate oil production rates. Terminal water cuts and WORs were determined for the 1P, 2P, and 3P cases from a review of historical terminal rates along with considerations of future operating practices. Producing Wells Under Polymer Flood The first polymer flood pilot test was performed in the Southern Upper Captain Sandstone (SUCS). A dedicated injection well, the 13/22a-C43, was drilled and completed in October 2009. Injectivity tests were performed in October 2010, and continuous polymer injection began in April 2011 and ended in August 2013. There was a material enhancement in oil production rates from the 13/22a-C47 well located to the west of the 13/22a-C43 well, and this initial test was deemed successful. A second pilot test was then initiated in the UCS through an injection well, the 13/22a-C52. Although polymer injection into the 13/22a-C52 well was starting to show a response consistent with predictions, the polymer injection was stopped because of polymer injectivity-related problems. A third pilot test was conducted in the SUCS through the 13/22a-C58 well located to the west of the 13/22a-C43 well. Polymer injection into the 13/22a-C58 well began in July 2015 and ended in February 2021. The observed enhancement in oil production was very favorable. The fourth and final pilot test began in late 2016 with injection into the UCS 13/22a-C60 well, which is located near the 13/22a-C52 well. A positive response was seen in the neighboring production wells, and this polymer injection test was deemed successful. Polymer injection into the 13/22a-C60 well is ongoing. Following the success of the pilot program, additional polymer injection development has been performed in the UCS. Polymer injection began in August 2018 into the 13/22a-C55 well, in May 2019 into the 13/22a-C65 well, and in July 2019 into the 13/22a-C56 well. The polymer flood pilot program and subsequent development programs were evaluated using a dimensionless response approach. Polygons were drawn around the likely polymer sweep areas between each injection well and the neighboring production wells, and the sweep-area hydrocarbon pore volume and stock tank oil initially in-place (STOIIP) were calculated. For the production wells, baseline primary plus secondary oil rate projections were made using DCA. Incremental oil production in excess of the baseline due to polymer injection was calculated as a fraction of STOIIP and plotted against pore volumes of polymer water injected. Representative response curves for the 1P, 2P, and 3P cases were generated based on the most mature observed responses to date. Currently active and future polymer flood plans are primarily based on a repeating strategy of having a horizontal polymer injection well flanked on each side by one or two horizontal production wells. Each of these patterns is considered a polymer flood group (PFG). The existing active PFG reserves estimates are based on extrapolation of current response curves. The more recently activated PFGs are in the early phase of polymer injection and have not progressed as far along the response curve as the more mature flood areas. Therefore, there is more uncertainty regarding the ultimate incremental production attributable to polymer injection for these PFGs. At this stage of the evaluation, we used a similar range of ultimate responses (1P, 2P, and 3P) for the recently activated PFGs
Page 7 as for the undeveloped PFGs. The estimates were also compared to Ithaca's UCS polymer simulation runs and were found to be in reasonable agreement. Undeveloped Polymer Flood Groups Reserves for undeveloped PFGs have been estimated based on the representative response curves described above. For each PFG, the representative response curves were further adjusted to account for the estimated oil saturation within the group area at the estimated onset of polymer injection operations. PFG areas that have undergone less water flooding because of timing or lower well density will have higher average oil saturation when injection starts. For these areas, the ultimate incremental responses of the representative response curves have been commensurately increased. The future polymer flood programs include a number of new PFGs in Areas A, B, and C. Some new PFGs include new drillwells that are expected to produce from unswept or underswept areas. For each future PFG volumes estimate, incremental polymer flood production estimates based on dimensionless analogy to the pilot areas were combined with new well production to calculate an ultimate recovery factor for each case. Aggregated ultimate production was then compared to calculated in-place volumes to check ultimate recovery factors against pilot area performance. Other Upside Opportunities Classified as Reserves We have estimated reserves for two additional undeveloped projects in Ithaca's Captain Field Development Plan (FDP). In UCS Area A, two "edge" locations have been identified that target relatively underswept areas. One location, known as the UM118P, is located north of the 13/22a-C68 well, and reserves have been estimated similarly to the reserves for that well. The other location, known as the UM150P, is located south of the 13/22a-C64 well, and reserves have been estimated similarly to reserves for other new drillwells in underswept areas. The second additional undeveloped reserves project is the drilling of one waterflood infill well into the Ross. Reserves for this project have been estimated using volumetric analysis and analogy. Other Upside Opportunities Classified as Contingent Resources Contingent resources have been estimated for the following six undeveloped projects in Ithaca's Captain FDP: (1) Extending the polymer flood program to an area known as C Far East, located east of the currently planned Area C polymer floods, (2) Drilling a new horizontal injection well-production well pair close to a former production well in the LCS East area that had inadequate pressure support, (3) Drilling an injection well-production well pair to develop a currently unproduced area of the LCS known as the Southern Terrace, (4) Drilling two injection well-production well pairs to develop two areas of the LCS to the east of the currently developed main LCS area; one pair of wells targets the Greater LCS 9a High area, and the other targets the Greater LCS 29 area, (5) Drilling two further infill production wells in the Ross, and
Page 8 (6) Drilling two primary production wells targeting extensions of the UCS to the northwest of Area A known as Area X and Area Y. Contingent resources for extending the polymer flood program described above have been estimated using similar techniques to those described for the reserves polymer flood development areas. Contingent resources for the remaining items have been estimated using volumetric analysis and analogy. 2.4 RESERVES AND CONTINGENT RESOURCES BY PROJECT We estimate the Ithaca working interest reserves by development project for Captain Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) 12th Campaign 1P 03,818.8 0.0 0.0 03,818.8 12th Campaign 2P 05,063.8 0.0 0.0 05,063.8 12th Campaign 3P 07,043.1 0.0 0.0 07,043.1 13th Campaign 1P 06,953.7 0.0 0.0 06,953.7 13th Campaign 2P 08,984.7 0.0 0.0 08,984.7 13th Campaign 3P 12,205.5 0.0 0.0 12,205.5 14th Campaign 1P 04,926.3 0.0 0.0 04,926.3 14th Campaign 2P 06,526.2 0.0 0.0 06,526.2 14th Campaign 3P 08,609.7 0.0 0.0 08,609.7 EOR Stage 2 1P 22,952.4 0.0 0.0 22,952.4 EOR Stage 2 2P 27,993.1 0.0 0.0 27,993.1 EOR Stage 2 3P 33,395.9 0.0 0.0 33,395.9 B26Y Well 1P 00,035.3 0.0 0.0 00,035.3 B26Y Well 2P 00,144.5 0.0 0.0 00,144.5 B26Y Well 3P 00,419.0 0.0 0.0 00,419.0 Jurassic Well 1P 01,166.9 0.0 0.0 01,166.9 Jurassic Well 2P 02,088.9 0.0 0.0 02,088.9 Jurassic Well 3P 03,311.2 0.0 0.0 03,311.2 We estimate the Ithaca working interest contingent resources by development project for Captain Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) 15th Campaign (1) 1C (1) 0,000.0 0.0 0.0 0,000.0 15th Campaign 2C 1,144.6 0.0 0.0 1,144.6 15th Campaign 3C 5,944.0 0.0 0.0 5,944.0
Page 9 Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) C Far East 1) 1C (1) 0,000.0 0.0 0.0 0,000.0 C Far East 2C 5,489.7 0.0 0.0 5,489.7 C Far East 3C 9,019.7 0.0 0.0 9,019.7 Greater LCS 1) 1C (1) 0,000.0 0.0 0.0 0,000.0 Greater LCS 2C 2,133.9 0.0 0.0 2,133.9 Greater LCS 3C 4,579.4 0.0 0.0 4,579.4 Ross-E 1) 1C (1) 0,000.0 0.0 0.0 0,000.0 Ross-E 2C 3,165.3 0.0 0.0 3,165.3 Ross-E 3C 6,029.2 0.0 0.0 6,029.2 Southern Terrace 1) 1C (1) 0,000.0 0.0 0.0 0,000.0 Southern Terrace 2C 1,082.7 0.0 0.0 1,082.7 Southern Terrace 3C 2,763.9 0.0 0.0 2,763.9 (1) There are no low estimate (1C) contingent resources for Captain Field at the price and cost parameters used in this report.
TECHNICAL DISCUSSION SECTION 3.0 – GREATER STELLA AREA
Page 10 3.0 GREATER STELLA AREA ______________________________________________________ There are five fields that currently make up the Greater Stella Area (GSA). Three fields are actively producing (Stella, Harrier, and Vorlich), one field is under development (Abigail), and one field is classified as contingent resources (Courageous). The fields included in the GSA are shown on the location map in Figure 3.6.1. Stella, Harrier, and Vorlich Fields are currently subsea developments and are tied back to a semi- submersible floating production facility (FPF) known as FPF-1. Abigail and Courageous Fields are planned to be subsea developments. Abigail Field will also be tied back to FPF-1, and it is our understanding that Ithaca's current plans are for Courageous Field to also be tied back to FPF-1. FPF-1 is secured by a 12-point spread mooring system and has fixed risers on the hull and flexible risers to the seabed. The facility has two-stage separation. Oil and gas are exported via pipelines. Nameplate processing capacities are 89 million cubic feet of gas per day (MMCFD), 25 thousand barrels of oil per day (MBOPD), and 22 thousand barrels of water per day (MBWPD). An infrastructure schematic for FPF-1 and its associated fields is shown in Figure 3.6.2. A summary of certain geologic characteristics of the fields included in the GSA is shown in the table below. Field Reservoir Depth (ft TVDSS) Trap Stella ASM 09,200 Faulted Four-way Anticline Stella Ekofisk 09,400 Stratigraphic Trap Harrier Maureen 09,800 Stratigraphic Trap Harrier Ekofisk 19,900 Faulted Four-way Anticline Harrier Tor 10,200 Faulted Four-way Anticline Vorlich Sele (S1b) 10,300 Three-way Stratigraphic Trap Abigail Forties 09,400 Stratigraphic Trap Abigail Statfjord 09,750 Faulted Dip Closure Courageous Forties 10,000 Four-way Anticline A summary of certain petrophysical parameters for the fields included in the GSA is shown in the table below. Field Reservoir Primary Fluid Solution GOR (CF/BBL) Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Stella ASM Gas - 150 19 21 Stella Ekofisk Gas - 250 26 58 Harrier Maureen Oil 1,500 - 22 10 Harrier Ekofisk Gas - 045 31 34 Harrier Tor Gas - 050 28 20 Vorlich Sele (S1b) Oil 3,200 - 28 32 Abigail Forties Oil/Gas 1,100 150 32 35 Abigail Statfjord Gas - 035 26 34 Courageous Forties Oil 2,000 - 20 50 For the fields included in the GSA, we used DCA, volumetric analysis, and reservoir modeling to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used for each field included in the GSA is shown in the table below.
Page 11 Field Evaluation Methods Stella DCA Harrier Volumetric Analysis and Reservoir Modeling Vorlich Volumetric Analysis, Analogy, and Reservoir Modeling Abigail Volumetric Analysis, Analogy, and Reservoir Modeling Courageous Volumetric Analysis and Analogy Development plans for the GSA were provided by Ithaca, and a summary of the development timing for projects in the GSA is shown in the table below. Field Project Timing Class Harrier Infill Well 2024 Reserves Harrier 30/06a-10 Behind-Pipe After Producing Zone Contingent Resources Abigail West Well 2022 Reserves Abigail East Well 2024 Contingent Resources Courageous Locations 1 and 2 2023–2024 Contingent Resources Courageous Location 3 2027 Contingent Resources 3.1 STELLA FIELD Stella Field, operated by Ithaca, is located entirely within Block 30/6a in the UK Sector of the North Sea in a water depth of approximately 330 ft. It is located approximately 260 km east of Aberdeen. Stella Field is shown on the location map in Figure 3.6.1, and the field comprises two producing reservoirs. The primary reservoir is the Andrew Sand Member (ASM) of the Lista Formation. The second reservoir is the Ekofisk Formation, which is a chalk underlying the ASM. The field is tied back subsea from two drill centers to the Ithaca-operated FPF-1. Following initial processing on FPF-1, oil is exported via the Norpipe oil pipeline and gas is exported via the Central Area Transmission System (CATS). A summary graph of the gross historical production for Stella Field is shown in Figure 3.6.3. Cumulative and recent production for Stella Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) ASM 2,772 49,252 0,714 0,671 10,062 133 Ekofisk 0,465 02,436 0,318 0,560 02,642 286 Total 3,237 51,689 1,032 1,232 12,704 419 Totals may not add because of rounding. Geology 3.1.1.1 Andrew Sand Member The Paleocene ASM is the primary reservoir in Stella Field and is a regionally extensive turbidite sequence. The ASM is fairly thin and ranges between 5 and 26 ft thick. The structure is a salt-cored and faulted four- way anticlinal feature with different oil-water contacts (OWCs) within the field. A depth structure on the top of the ASM is shown in Figure 3.6.4.
Page 12 The ASM is at a depth of approximately 9,200 ft true vertical depth subsea (TVDSS) at the crest of the structure and contains a rich gas-condensate with an oil rim. The ASM is relatively thin but has a large column height of approximately 820 ft. A type log section of this formation is shown in Figure 3.6.5. There is evidence of a compositional gradient within the condensate accumulation, which is not surprising because of the large column height. The ASM is broken up into a number of hydrostatically separated fault block compartments. This was apparent from formation test pressure analysis and has subsequently been confirmed with production pressure analysis. Average initial reservoir pressure at an average gas-oil contact (GOC) is approximately 6,700 psia. Reservoir temperature is approximately 250°F. The ASM has been produced by five horizontal production wells. Initially, three flank wells targeted the oil rim and one crestal well targeted the gas cap. An additional flank infill well was drilled in 2019. The drive mechanism in the ASM is principally depletion drive with some moderate natural aquifer pressure support observed from the south and east. Two of the five ASM production wells, the 30/06a-A1Z and 30/06a-A2Z, are no longer producing. 3.1.1.2 Ekofisk Formation The Paleocene Ekofisk Formation is a chalk that also produces in the field, and it is believed to be an underfilled stratigraphic trap. The Ekofisk Formation underlies the ASM at a depth of approximately 9,400 ft TVDSS and contains oil. The Ekofisk Formation has been produced by one horizontal well. Methodology Reserves estimates for Stella Field are based on DCA. All of the Stella Field wells have reasonably well- established production trends. Considering these trends and the relative maturity of the fields, DCA was deemed the most appropriate forecasting method. For each well, DCA projections were made for gas rate and condensate yield. 3.2 HARRIER FIELD Harrier Field, operated by Ithaca, is a gas-condensate field located within Block 30/06a in the UK Sector of the North Sea in a water depth of approximately 330 ft. It is located approximately 260 km east of Aberdeen. Harrier Field is shown on the location map in Figure 3.6.1. Harrier Field comprises two producing chalk reservoir intervals, the Tor and the Ekofisk Formations, at a depth of approximately 10,000 ft TVDSS. Harrier Field has been developed via a single multi-lateral well, the 30/06a-10Z, which simultaneously produces from the Paleocene Ekofisk Formation and the Cretaceous Tor Formation. The well is tied back to FPF-1 via a 9-km pipe-in-pipe flowline connected to the Stella Field main subsea manifold. A summary graph of the gross historical production for Harrier Field is shown in Figure 3.6.6. Cumulative and recent production for Harrier Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Ekofisk/Tor 910 34,470 196 401 15,347 230 Geology Harrier Field is a faulted four-way anticline with three productive pelagic chalk formations: the Paleocene Maureen and Ekofisk Formations and the Cretaceous Tor Formation. The Ekofisk Formation is relatively
Page 13 thick and broken into subunits, of which the E1 and E2 were evaluated for this report. It has a porosity of 23 to 25 percent. The Tor Formation is also broken into subunits, but only the M1 was evaluated for this report, and it is the only gas-bearing subunit. It has a porosity of 20 to 22 percent. The Maureen Formation is a confined, channelized turbidite with seismic amplitude support. It has a porosity of 22 percent and an intial water saturation (Swi) of 10 percent. Type log sections illustrating these formations are shown in Figures 3.6.7 and 3.6.8. A depth structure map on the top of the Tor M1 Formation is shown in Figure 3.6.9. Methodology A petrophysical evaluation was conducted and net pay maps were created as inputs to an independent volumetric analysis. Low and high case net pay maps were created for the Tor M1 Formation, the combined Ekofisk E1/E2 Formation, and the Maureen Formation. A fit-for-purpose simulation model was built to model the Tor and Ekofisk Formations currently being simultaneously produced by the dual lateral 30/06a-10Z well. The model was built using structure maps, and the in-place volumes were adjusted based on our net pay mapping. Well drawdown was used as the primary production constraint, and gas production rate, flowing bottomhole pressure (FBHP), and condensate-gas ratio (CGR) were the history-matching parameters. Key objectives of the relatively simple simulation model were to gain an understanding of the relative production from the Ekofisk and Tor Formations and the likely drainage area. Since the reservoirs have very low permeability, the drainage areas are relatively local. A low case version of the simulation model was created that limited active grid cells to the current effective drainage area. The simulation models were used in prediction mode, continuing the drawdown constraint and adding an FBHP constraint based on the most recently observed FBHP. The predictions were used as guides for the estimated 1P, 2P, and 3P production forecasts for the 30/06a-10Z well. The full area simulation model was also used in prediction mode to assess the potential for an additional well. Reserves estimates for this new well are based on the mapping and the simulation runs. A workover to recomplete the 30/06a-10Z well in the shallower Maureen Formation following depletion of the Tor and Ekofisk Formations has been included in the contingent resources category. Another simple fit-for-purpose simulation model was built to help estimate these resources. As with the Tor/Ekofisk model, the Maureen model was built using structure maps and the in-place volumes were tuned based on our net pay mapping. Since there is no existing production from the Maureen Formation, this model could not be calibrated by history matching. Instead it was used to run a matrix of cases based on ranges of uncertain parameters. The uncertain parameters included OWC, aquifer volume and strength, and absolute effective permeability. The simulation runs were used to guide the low estimate (1C), best estimate (2C), and high estimate (3C) cases of contingent resources production profiles for the workover. Reserves and Contingent Resources by Project We estimate the Ithaca working interest reserves by development project for Harrier Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Infill Well 1P 0,409.4 12,749.0 0,380.2 02,987.7 Infill Well 2P 0,958.0 28,552.1 0,851.6 06,732.3 Infill Well 3P 1,510.9 44,193.7 1,318.1 10,448.6
Page 14 We estimate the Ithaca working interest contingent resources by development project for Harrier Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) 30/06a-10 Behind-Pipe 1C 1,155.2 1,521.7 045.4 1,463.0 30/06a-10 Behind-Pipe 2C 1,504.0 1,986.3 059.2 1,905.7 30/06a-10 Behind-Pipe 3C 3,005.1 6,061.6 180.8 4,231.0 3.3 VORLICH FIELD Vorlich Field, operated by Ithaca, is a volatile oil field located in Blocks 30/1c and 30/1f in the UK Sector of the North Sea in a water depth of approximately 300 ft. Vorlich Field is shown on the location map in Figure 3.6.1. The field, located approximately 260 km east of Aberdeen, was discovered in 1984 with the drilling of the 30/01c-3 well, although only approximately 7 ft of pay was encountered. The field was further appraised by the 30/01f-13A, 30/01f-13Z, and 30/01f-13Y wellbores. Two production wells have been drilled and completed, and production commenced in November 2020. The wells are tied back via a 9-km pipe-in-pipe flowline to a new dedicated flexible riser and umbilical connecting the subsea infrastructure to FPF-1. A new module for processing natural gas liquids (NGL) on FPF-1 was installed to maximize liquids production from the field. A summary graph of the gross historical production for Vorlich Field is shown in Figure 3.6.10. Cumulative and recent production for Vorlich Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Sele (S1b) 4,924 22,090 255 8,694 60,130 699 Geology Vorlich Field is a broad, unfaulted, three-way stratigraphic closure with low dip. The Late Paleocene Sele (S1b) Formation is a distal deep-marine turbidite fan complex that laps onto a paleo high. The average porosity and Swi are approximately 26 percent and 32 percent, respectively. The reservoir is approximately 10,300 ft TVDSS. A type log section illustrating this formation is shown in Figure 3.6.11. A depth structure map on the top of the S1b Formation is shown in Figure 3.6.12. Methodology Reserves estimates for Vorlich Field are based on volumetric analysis, analogy to similar reservoirs, and reservoir modeling. We mapped the net pay in the reservoir down to the logged OWC in all cases. We used a range of net thickness and top of reservoir structure away from well control to establish the range of potential net rock volumes (NRVs). Because the fluid at Vorlich Field is a near-critical oil, a large portion of the oil in the reservoir flashes to gas at pressures just below the bubble point. Gas produced from Vorlich Field is first processed through the new NGL module at FPF-1, and the residual gas is exported to the Teesside Gas Processing Plant,
Page 15 where additional NGL is extracted. We built a dynamic compositional simulation model and used it to guide our forecasts of the various product sales rates. The gross gas volumes shown in this report for Vorlich Field are the gross (100 percent) gas volumes remaining at the outlet of the offshore NGL processing module; these volumes are before offshore fuel and flare gas consumption is taken into account. This definition of gross gas is consistent with that reported by Ithaca for Vorlich Field. The working interest gas volumes shown in this report for Vorlich Field are after deductions for shrinkage that account for the volume converted to condensate and NGL during onshore processing and after deductions for Vorlich Field's estimated share of the 4.2 MMCFD of gas consumed in field operations at FPF-1. 3.4 ABIGAIL FIELD Abigail Field includes both oil and gas-condensate reservoirs and is located in Block 29/10b in the UK Sector of the North Sea in a water depth of approximately 300 ft. Abigail Field is shown on the location map in Figure 3.6.1. The field, located approximately 250 km east of Aberdeen, was discovered in 1995 and further appraised in 2012 with the 29/10b-8 well. Before 2021, Abigail Field was known as Hurricane Field. Abigail is a pre-production discovery and part of the larger GSA development. It is our understanding that Abigail Field has been fully sanctioned to proceed with development. A production well has been drilled and completed and subsea infrastructure installed. The current proposed development plan involves two production wells. The first production well, drilled in 2022, twinned the 29/10-4Z well, and a second well will twin the 29/10b-8 well. The wells will share a flowline back to the Stella Main Drill Center (SMDC), which is tied back to FPF-1. Construction of the subsea infrastructure is underway. First oil is expected in October 2022, approximately ten months after field development plan approval, with the second well to come online approximately two years later. Geology Abigail Field logged a productive Paleocene Forties Formation, which consists of channelized turbidites. The narrow channel system is draped over an anticlinal structure. The porosity and Swi are 32 percent and 35 percent, respectively. A type log section illustrating the Forties Formation is shown in Figure 3.6.13, and a depth structure on the top of the formation is shown in Figure 3.6.14. The ASM, which is the Stella Field- equivalent sandstone, was encountered in all five wells in the field. The ASM is usually thin, less than 20 ft; however, the 29/10-4Y well to the northwest logged approximately 50 ft. The porosity is estimated at 26 percent. Methodology Reserves estimates for Abigail Field are based on volumetric analysis, analogy to similar properties, and reservoir modeling. We mapped net pay for the Forties Formation based on structure maps, a logged OWC, and petrophysics from the discovery and appraisal wells. However, no two penetrations of the ASM to date have been in communication, indicating a high degree of compartmentalization and significant uncertainty regarding connectivity over the license block. Given the observed compartmentalization, we did not have confidence in a mapping approach to this reservoir and instead opted to assign a drainage area around each planned completion to arrive at a NRV for each proposed well. We also built an integrated production model of the reservoirs, wells, and subsea flowlines back to the SMDC to understand the impact of commingling Forties Formation and ASM production and to guide our forecasts of the rate profiles over the life of the field.
Page 16 Reserves and Contingent Resources by Project We estimate the Ithaca working interest reserves by development project for Abigail Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) West Well 1P 1,850.6 1,787.3 059.0 2,217.7 West Well 2P 3,300.3 3,187.4 105.2 3,955.0 West Well 3P 5,167.4 4,990.7 164.7 6,192.5 We estimate the Ithaca working interest contingent resources by development project for Abigail Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) East Well 1C 0,604.7 04,151.9 137.0 1,457.5 East Well 2C 0,811.9 05,987.6 197.6 2,041.9 East Well 3C 1,236.9 11,475.7 378.7 3,594.2 3.5 COURAGEOUS FIELD Courageous Field, operated by Ithaca, is located in Blocks 30/1e and 30/2e in the UK Sector of the North Sea in a water depth of 263 ft, approximately 17 km northeast of FPF-1. Courageous Field is shown on the location map in Figure 3.6.1. The field was discovered by the drilling of the 30/02-1 well in 1971. Historically, the field was appraised by Kerr-McGee Corporation and BG Group with seven penetrations and three drillstem tests (DSTs). Development plans are currently being evaluated, and first oil for the field is expected in 2024. The conceptual field development consists of a subsea tieback to FPF-1 of two wells targeting the central and eastern portions of the field from a planned main drill center. Because of the tentative nature and timeline of the development, only contingent resources have been estimated for Courageous Field. Geology The Courageous Field structure is interpreted as a single low-relief four-way closure with no obvious faults observed on the seismic dataset. The primary reservoir is the Paleocene Forties Formation, which is a distal turbidite at approximately 10,000 ft TVDSS. A type log section illustrating this formation is shown in Figure 3.6.15. Despite the lack of identified compartments, fluid samples and DSTs taken across the field show varying fluid types and OWCs. Reservoir net-to-gross ratio (NTG) distribution is a key uncertainty for evaluation. Average porosity is approximately 20 percent with permeability averaging approximately 20 millidarcies (mD). The Swi is generally high at approximately 50 percent. A depth structure map on the top of the Forties Formation is shown in Figure 3.6.16. Methodology Contingent resources estimates for Courageous Field are based on volumetric analysis and analogy to similar properties. Net pay for the Forties Formation was mapped based on structure maps, logged OWCs,
Page 17 and petrophysical data from the discovery and appraisal wells. The appraisal wells have different fluids and contacts, but there are no apparent features separating them, so our mapping was performed assuming wells were approximately centered in their respective compartments. Location 1 is planned to penetrate the compartments defined by the 30/02a-5 and 30/02a-5Y appraisal wells. Location 2 is planned to penetrate the compartment defined by the 30/02a-9 appraisal well. Location 3 is only included in the 3C case and is planned to penetrate the compartment defined by the 30/02a-9Z appraisal well. In the 1C case, sampled oil discovered at saturated conditions indicates that the 30/02a-5 compartment carries a gas cap from the top of the structure to the highest known oil (HKO). The 30/02a-9 compartment also includes a gas cap in this case, as indicated by a possible DST and repeat formation test (RFT) interpretation of fluid yields and a GOC. In the 2C case, we assume oil fill from the top of the structure to the OWCs. The 3C case is a lognormal extrapolation of in-place resources based on the 1C and 2C cases. Formation volume factors and yields were determined from equation-of-state (EOS) characterizations of all fluids used in the assessment, including four oil samples and one gas-condensate sample. Further, the EOS was used to align all samples to common separator conditions. Hydraulic and material balance (P/Z) models were used to estimate abandonment pressures by representation of commingling at the subsea manifold and pressure losses in the subsea pipeline and riser. Pore volume compressibility was estimated from core samples collected in the 30/02a-5, 30/02-1, and 30/02a-5Z appraisal wells. Fluid compressibility was estimated through the EOS representations. Well productivity indices have been estimated from the 30/02a-5 well measurements from DST 1, normalized for perforated length, and verified against core permeability estimates. Contingent Resources by Project We estimate the Ithaca working interest contingent resources by development project for Courageous Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Locations 1 and 2 1C 2,330.4 20,952.5 0.0 05,942.9 Locations 1 and 2 2C 2,957.8 25,219.2 0.0 07,306.0 Locations 1 and 2 3C 5,438.8 39,780.5 0.0 12,297.5 Location 3 (1) 1C (1) 0,000.0 00,000.0 0.0 00,000.0 Location 3 (1) 2C (1) 0,000.0 00,000.0 0.0 00,000.0 Location 3 3C 1,124.0 11,446.6 0.0 03,097.5 (1) Our study indicates that as of June 30, 2022, there are no low estimate (1C) or best estimate (2C) contingent resources for the Location 3 project.
NETHERLAND, SEWELL & ASSOCIATES, INC. All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Greater Stella Area Infrastructure Schematic United Kingdom Sector of the North Sea Figure provided by Ithaca Energy (UK) Limited. Figure 3.6.2
10 3 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 5 10 6 10 7 10 GAS (MCF / MO) 2017 2018 2019 2020 2021 2022 | | | | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN STELLA FIELD UNITED KINGDOM SECTOR OF THE NORTH SEA ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 3.6.3
10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 6 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 4 10 5 10 6 10 GAS (MCF / MO) 2020 2021 2022 | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN VORLICH FIELD UNITED KINGDOM SECTOR OF THE NORTH SEA ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 3.6.10
TECHNICAL DISCUSSION SECTION 4.0 – SCHIEHALLION FIELD
Page 18 4.0 SCHIEHALLION FIELD _________________________________________________________ Schiehallion Field, operated by British Petroleum (BP), is an oil field located in Blocks 204/20a, 204/25a, 205/16a, and 205/21b in the North Atlantic Ocean in a water depth of approximately 1,300 ft. Schiehallion Field, located approximately 175 km west of the Shetland Islands, is shown on the location map in Figure 4.4.1. Other partners in the field include Shell UK Exploration & Production (Shell) and Harbour Energy plc (Harbour). Schiehallion Field was discovered by BP in 1993. The final investment decision (FID) was secured for Schiehallion Field in 1996, and the field was brought online in 1998. Schiehallion Field was initially developed with 21 production wells and 23 water injection wells. A redevelopment program was approved in 2011, and in 2012 the field was shut in. The redevelopment program included the manufacturing of the Glen Lyon FPSO and the drilling of 17 additional wells. Drilling commenced in 2016 and the field was brought back online in 2017. Topsides production design capacity is 130,000 barrels of oil per day (BOPD) and 310,000 barrels of water per day (BWPD), with injection capacity up to 570,000 BWPD. Oil is exported via shuttle tankers, and produced gas is exported via pipeline. The Glen Lyon FPSO produces oil and gas from both Schiehallion and Loyal Fields; however, it is our understanding that Ithaca owns no interest in Loyal Field. First production for Schiehallion Field occured in July 1998, and the field reached a sustained rate greater than 100,000 BOPD by the early 2000s. The produced oil is a medium crude oil of approximately 25 degrees API, slightly undersaturated. GORs for the producing wells range from 500 to 1,000 standard cubic feet per stock tank barrel (SCF/STB), and in situ viscosity ranges from 1.5 to 3.5 cP. Schiehallion Field produces from the Vaila Formation. A summary graph of the gross historical production for Schiehallion Field is shown in Figure 4.4.2. Cumulative and recent production for Schiehallion Field are shown in the following table: Cumulative Production December 2021 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Vaila 424,522 188,353 268,056 39,503 15,353 112,944 4.1 GEOLOGY Schiehallion Field is composed of a series of tilted fault blocks that are separated by east-to-west-trending faults. The field area measures approximately 8 km in length and 8 km in width and is at a depth of approximately 6,500 ft TVDSS. Production comes from a series of sandstones within the late Paleocene- aged Vaila Formation that are configured as both stratigraphic and structural traps. Areal connectivity of the reservoirs varies based on depositional limits and amalgamation within and between channel complexes. The sands were deposited along the middle shelf slope to basin floor by gravity flow mechanisms such as debrites, turbidites, and slumps. Reservoir quality in the field is typically high, with porosities in the main sands ranging from 20 to 35 percent. 3-D seismic data are instrumental in identifying sand geometries within the field, and 4-D seismic data have been used to evaluate changes in hydrocarbon distribution over the producing life of the field. A summary of certain geologic characteristics of Schiehallion Field is shown in the table below. Reservoir Depth (ft TVDSS) Trap Vaila 6,500 Structural, Stratigraphic, and Faulted Closures
Page 19 4.2 METHODOLOGY The active wells are being produced via waterflood drive because the surrounding aquifer is insignificant. Most of these wells have sufficient production history to estimate future production using performance- based analysis. DCA was performed for each well by estimating the total liquid production rate and either the WOR or the water cut, using different trends for the 1P, 2P, and 3P cases, and then using these values to calculate the estimated oil production rates. Most of the wells were forecasted using WOR trends. Selection between a WOR and a water cut forecast is based on well groupings on a plot of WOR versus normalized estimated ultimate recovery (EUR). Terminal water cuts and WORs were estimated for the 1P, 2P, and 3P cases from a review of historical terminal rates along with consideration of future operating practices. A summary of certain petrophysical parameters for Schiehallion Field is shown in the table below. Reservoir Primary Fluid Solution GOR (CF/BBL) Average Porosity (%) Average Swi (%) Vaila Oil 450 27 25 Reserves have been estimated for the Phase A drilling program, which comprises five additional infill production wells in 2022 and 2023. Long lead authorization for expenditure (AFE) requests have been approved for these five wells. Estimates of reserves for undeveloped locations in the Vaila Formation are based on the operator's estimates. The post-completion estimates of EUR for wells drilled since 2016 aligned closely with the operator's pre-drill estimates. The initial production rates for these wells, meanwhile, were 5 to 10 percent lower than the operator's pre-drill estimates; therefore, we applied reductions accordingly to the operator's estimates of initial production rates for future wells. Contingent resources have been estimated for further planned infill drilling, including the remaining Phase B drilling program (comprising six wells planned to be drilled between 2024 and 2026) and the Phases C and D drilling programs (comprising an additional 15 wells planned to be drilled between 2027 and 2030). The placement of well locations in these drilling programs will be informed by the acquisition of additional 4-D seismic data, and each program is contingent upon the success of preceding infill wells. Because of the size of the accumulation at Schiehallion Field, we expect that the operator will pursue a field life extension project to allow an additional seven years of production of economic resources beyond the initial thirty-year facility design limit of 2047. The facility life extension project is contingent upon field performance and future economic conditions. Estimates of contingent resources associated with further infill drilling of the Vaila Formation are based on creaming curve analysis. The P90, P50, and P10 EURs for all wells produced in Schiehallion Field were ordered based on date drilled, and the EUR trends were extrapolated to arrive at technically recoverable estimates as the basis for our 1C, 2C, and 3C estimates. Because of historical variability in well results, program-level EUR-per-well averages were applied to individual program wells. 4.3 RESERVES AND CONTINGENT RESOURCES BY PROJECT We estimate the Ithaca working interest reserves by development project for Schiehallion Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Phase A Infill 1P 0,747.3 0,203.5 0.0 0,782.4 Phase A Infill 2P 2,420.5 0,659.0 0.0 2,534.1 Phase A Infill 3P 4,328.7 1,178.5 0.0 4,531.9
Page 20 We estimate the Ithaca working interest contingent resources by development project for Schiehallion Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Phase B Infill 1C 1,808.9 0,492.5 0.0 1,893.9 Phase B Infill 2C 2,541.5 0,691.9 0.0 2,660.8 Phase B Infill 3C 3,507.9 0,955.0 0.0 3,672.6 Phase C/D Infill 1C 2,086.3 0,568.0 0.0 2,184.3 Phase C/D Infill 2C 3,244.8 0,883.4 0.0 3,397.1 Phase C/D Infill 3C 5,398.0 1,469.6 0.0 5,651.3 Life Extension 1C 0,000.0 0,000.0 0.0 0,000.0 Life Extension 2C 0,188.2 0,088.2 0.0 0,203.4 Life Extension 3C 0,320.3 0,150.2 0.0 0,346.2
10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 6 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 4 10 5 10 6 10 GAS (MCF / MO) 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 | | | | | | | | | | | | | | | | | | | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN SCHIEHALLION FIELD THE NORTH ATLANTIC OCEAN ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 Figure 4.4.2 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
TECHNICAL DISCUSSION SECTION 5.0 – GREATER BRITANNIA AREA
Page 21 5.0 GREATER BRITANNIA AREA ___________________________________________________ The Greater Britannia Area (GBA) consists of Britannia, Alder, Brodgar, Callanish, and Enochdhu Fields. These fields are shown on the Britannia Area location map in Figure 5.6.1. A summary of certain geologic characteristics of each field included in the GBA is shown in the table below. Field Reservoir Depth (ft TVDSS) Trap Britannia Britannia 12,750 (1) Alder Galley 14,700 Faulted Four-way Anticline Brodgar Britannia 10,900 Four-way Anticline Callanish Forties 06,500 Four-way Anticline with Stratigraphic Pinch-out Enochdhu Forties 16,900 (1) (1) No geologic evaluation was performed. A summary of certain petrophysical parameters for each field included in the GBA is shown in the table below. Field Reservoir Primary Fluid Solution GOR (CF/BBL) Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Britannia Britannia Gas - 060 (1) (1) Alder Galley Gas - 115 - - Brodgar Britannia Gas - 050 17 20 Callanish Forties Oil 1,000 - 29 22 Enochdhu Forties Oil 1,000 - (1) (1) (1) No geologic evaluation was performed. For the fields included in the GBA, we used performance analysis, volumetric analysis, analogy, and reservoir modeling to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used for the fields included in the GBA is shown in the table below. Field Category Evaluation Methods Britannia All DCA Alder All DCA and P/Z Analysis Brodgar All DCA Callanish Reserves DCA Callanish Contingent Resources Volumetrics and Analogy Enochdhu All DCA Development plans for the GBA were provided by Ithaca, and a summary of the development timing for projects in the GBA is shown in the table below. Field Project Timing Class Britannia Compressor Overhaul 2022 Reserves Britannia Well Intervention 2023–2029 Reserves Brodgar Compressor Overhaul 2022 Reserves Callanish F6 Well 2024 Contingent Resources
Page 22 5.1 BRITANNIA FIELD Britannia Field is a gas-condensate field located in Blocks 15/29a, 15/30a, 16/26a, and 16/27b in the UK Sector of the North Sea in a water depth of 480 ft, approximately 225 km northeast of Aberdeen. Britannia Field is shown on the location map in Figure 5.6.1. The field covers approximately 250 square km and is operated by Harbour. The field was discovered in 1975, and field development was approved in 1994 with an agreement to develop Blocks 15/30a and 16/26a as one accumulation. A fixed platform was installed in Block 16/26a, and wells were drilled in Block 15/30a that tie back to the platform via a subsea manifold. Sales gas has been produced from the field since 1998. Dry gas is delivered via the dedicated Britannia Gas Pipeline to the Scottish Area Gas Evacuation (SAGE) system, operated by Ancala Midstream Acquisitions Limited (Ancala), for onshore processing at the St. Fergus gas terminal. Condensate is exported through the Forties Pipeline System (FPS), operated by Ineos FPS Limited, for processing at the Grangemouth oil terminal in Scotland. There are currently 35 producing wells. Britannia Field produces from a single reservoir, the Britannia Formation. A summary graph of the gross historical production for Britannia Field is shown in Figure 5.6.2. Cumulative and recent production for Britannia Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Britannia 76,138 2,114,355 - 1,358 62,118 - Geology Britannia Field spans four UK Continental Shelf blocks and is a combination stratigraphic-structural trap. Britannia Field originally had a 1,400-ft gas column and a 140-ft oil column in Lower Cretaceous deepwater marine sandstones known as the Britannia Formation. The reservoir's characteristics vary throughout the field, ranging from high-quality turbidites to poor-quality debris flows. The reservoir has an average porosity of 15 percent, and NTG ranges from 12 to 58 percent. A type log section illustrating this formation is shown in Figure 5.6.3. A depth structure map on the top of the Britannia Formation is shown in Figure 5.6.4. Methodology Reserves estimates for the existing producing wells are based on DCA on both gas rate versus time and cumulative gas production bases. Because of well interactions, well forecasts were aggregated and field gas rate versus field cumulative gas plots were also included in the analysis. Recurring well work programs were also considered in estimating reserves. Typical program scopes include running production logs, reperforating wells, and adding tail pipes and velocity strings to optimize producing wells and to reestablish production. Production uplift estimates are based on the historical performance of similar activities in the field. No study was made to determine whether any developed non-producing or undeveloped reserves might be established for Britannia Field. 5.2 ALDER FIELD Alder Field, operated by Ithaca, is a gas-condensate satellite field to Britannia Field (see Section 5.1) and is located in Block 15/29a in the UK Sector of the North Sea in a water depth of 500 ft. Alder Field is located
Page 23 27 km west of Britannia Field and 199 km northeast of Aberdeen. Alder Field is shown on the Britannia Area location map in Figure 5.6.1. The field was discovered in 1975, and a single subsea gas well, the 15/29a-A1, began producing in 2016. The production is processed at the Britannia platform, and condensate is exported via the FPS for processing at the Grangemouth oil terminal. The gas is exported from the Britannia platform via the SAGE system, operated by Ancala, for onshore processing at the St. Fergus gas terminal. Alder Field has produced from the Galley Formation. A summary graph of the gross historical production for Alder Field is shown in Figure 5.6.5. Cumulative and recent production for Alder Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Galley 6,126 78,863 21 564 11,779 - Geology Alder Field produces from the Jurassic Galley Formation, which is a sandstone containing sand-rich turbidites, at approximately 14,700 ft TVDSS. The reservoir is a combination stratigraphic-structural trap with a shale-out to the north and east and structural dip to the south. The reservoir has an average porosity of approximately 13 percent and an Swi of approximately 20 percent. A type log section illustrating this formation is shown in Figure 5.6.6. A depth structure map on the top of the Galley A Formation is shown in Figure 5.6.7. Methodology DCA and P/Z estimates have been used to forecast production for the 15/29a-A1 well. First, a P/Z plot was constructed relying on several key shut-in events allowing extended pressure buildups, namely the 2017, 2018, and 2019 turnarounds and an FPS shutdown period at the end of 2017. Equilibrium gas Z-factors were pulled from the 15/29a-8 DST 1 pressure-volume-temperature (PVT) report in the constant composition expansion and constant volume depletion experiments. As two-phase Z-factors were not estimated, only equilibrium gas Z-factors were used. Rock compressibility was included in the P/Z analysis as Alder Field was discovered to be over-pressured. An estimated abandonment pressure was calculated from a hydraulic model representing the flow path from Alder Field to the Britannia platform. Additionally, because of the liquid yield of the produced gas, it was deemed necessary to include the gaseous equivalent volumes of liquid in the P/Z plot. Remaining gas and liquid recoveries have been estimated assuming constant liquid yield because of the maturity of the field. A range in remaining recoverable volumes was generated through various fits through the P/Z plot, with the 1P estimate honoring the early and middle time data and the 2P and 3P estimates honoring the early time data with a range of rock compaction influence. DCA was constructed to honor the P/Z-derived EUR while matching the historical field rates on rate-versus- time and rate-versus-cumulative gas bases. No study was made to determine whether developed non-producing reserves, undeveloped reserves, or contingent resources might be established for Alder Field. A second productive area, the DAB Fault Block, was discovered near the 15/29a-3 well to the south of the currently producing area. Fluid properties and a logged gas-water contact (GWC) indicated isolation from the producing A1 compartment. Successive DST results from the 15/29a-3 well showed progressively lower extrapolated buildup pressures. The resulting P/Z calculations indicated the potential for a very small
Page 24 connected drainage area. It is our understanding that Ithaca has no plans for future activities or to further study or appraise this area; therefore, contingent resources have not been estimated for Alder Field. 5.3 BRODGAR FIELD Brodgar Field, operated by Harbour, is a gas-condensate satellite field to Britannia Field (see Section 5.1) and is located in Blocks 21/3a and 21/3b in the UK Sector of the North Sea in a water depth of 450 ft. Brodgar Field is shown on the location map in Figure 5.6.1. The field, located 41 km southwest of Britannia Field and approximately 185 km northeast of Aberdeen, was discovered in 1985, and first production began in 2008. Brodgar Field currently has two producing wells, the 21/03a-H3Z and 21/03a-H4Z, which tie back to the bridge-linked platform (BLP) connected to the Britannia platform via a pipeline. Brodgar Field produces from a single reservoir, the Britannia Formation. A summary graph of the gross historical production for Brodgar Field is shown in Figure 5.6.8. Cumulative and recent production for Brodgar Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Britannia 10,451 198,520 196 2,097 40,828 204 Geology Brodgar Field produces from the Cretaceous Britannia Formation in a narrow, elongated northwest-to- southeast-trending structure at approximately 10,900 ft TVDSS. The reservoir has an average porosity of 20 percent and an average Swi of 17 percent. A type log section illustrating this formation is shown in Figure 5.6.9. A depth structure map on the top of the Britannia Formation is shown in Figure 5.6.10. Methodology The gas rate for the 21/03a-H3Z well was reduced to approximately 20 MMCFD at the end of 2019 to provide processing capacity for the 21/03a-H4 well. The water-gas ratio increased throughout 2020, and the well was shut in during the third quarter of 2020. Work is ongoing to clear a hydrate blockage in the flow line and return the well to production in late 2022. The 21/03a-H4 well came online in the fourth quarter of 2019. The 21/03a-H4 well targets a structural high to the west of the historically developed area, across a saddle. Petrophysical parameters were evaluated from log data, and NRV maps were created for the field. Incremental recovery associated with this location has been estimated by volumetric analysis and analogy to the historical performance of the field. Boundaries on in-field sweep efficiency have been estimated by differentiating current recovery into pressure depletion and water encroachment, or sweep, categories. High- and low-side boundaries of sweep efficiency have been estimated based on varying assumptions of connected volume and degree of water encroachment. The well is expected to produce on plateau until water encroachment impedes production. No study was made to determine whether any undeveloped reserves or contingent resources might be established for Brodgar Field.
Page 25 5.4 CALLANISH FIELD Callanish Field, operated by Harbour, is a saturated oil field with a primary gas cap located in Blocks 15/29b and 21/04a in the UK Sector of the North Sea in a water depth of 490 ft. The field is located approximately 160 km northeast of Aberdeen and 14 km southwest of Britannia Field. Callanish Field is shown on the location map in Figure 5.6.1. The field was discovered in 1999 and began producing in 2008. As of March 2022, there were four actively producing wells and one shut-in well. The Callanish Field wells tie back to the BLP connected to the Britannia platform via a subsea pipeline. Callanish Field produces from a single reservoir, the Forties Formation. A summary graph of the gross historical production for Callanish Field is shown in Figure 5.6.11. Cumulative and recent production for Callanish Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 55,738 53,029 82,302 11,351 9,949 15,051 Geology Callanish Field produces from the Upper Paleocene Forties Formation at a depth of approximately 6,500 ft TVDSS and consists of marine turbidites. There are two four-way dip structures separated by a saddle, with a stratigraphic pinch-out defining the southern limit of the accumulation. The reservoir has an average porosity of approximately 21 percent and an Swi of 25 percent. A type log section illustrating this formation is shown in Figure 5.6.12. A depth structure map on the top of the Forties Formation is shown in Figure 5.6.13. Methodology The producing wells have demonstrated a strong water drive, and reserves estimates are based on DCA of oil cut versus cumulative oil production and oil rate versus time. Because of the flattening in oil cut behavior, oil cut versus cumulative oil is evaluated on both Cartesian and semilogarithmic scales to provide a range of 1P to 3P estimates. No study was made to determine whether any developed non-producing reserves might be established for this field. The 15/29b-F5 well was drilled at the end of 2020 towards the eastern flank, and it is a strong performing well. The well path provides a take point in the original gas cap and has a horizontal section in the eastern flank of the oil rim. We evaluated petrophysics from log data and mapped the field's NRV. Additionally, a 4-D seismic survey was conducted in 2019, and preliminary processed results were made available. These data indicated that sweep is confined to areas with existing wells, with the structural flanks largely undrained. Detailed PVT data were not available, so an unmatched Glaso black oil correlation was used to estimate original in-place volumes. The reserves for this well have been estimated using volumetrics and analogy to similar properties along with the historical performance of the field, informed by the preliminary 4-D seismic data. An additional undeveloped location is included in our contingent resources estimates for Callanish Field. This well targets a portion of the original gas cap in the northwest area of the field and has a horizontal section in the northwestern flank of the oil rim. Similarly to the 15/29b-F5 well, contingent resources for this location have been estimated using volumetrics and analogy to similar properties, along with the historical performance of the field, informed by the preliminary 4-D seismic data.
Page 26 Contingent Resources by Project We estimate the Ithaca working interest contingent resources for Callanish Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) F6 Well 1C 0,384.1 0,333.0 18.5 0,460.0 F6 Well 2C 0,847.7 0,734.9 40.8 1,015.2 F6 Well 3C 1,301.6 1,128.5 62.7 1,558.8 5.5 ENOCHDHU FIELD Enochdhu Field, operated by Harbour, is a satellite oil field to Britannia Field and is located in Block 21/5a in the UK Sector of the North Sea in a water depth of 460 ft. The field is located 18 km southwest of Britannia Field and approximately 160 km east of Aberdeen. Enochdhu Field is shown on the location map in Figure 5.6.1. The field was discovered in 2005 and began producing in 2015. The field currently has one producing well, the 21/05a-6, which is tied back approximately 8 km to the Callanish subsea manifold. Enochdhu Field produces from a single reservoir, the Forties Formation. A summary graph of the gross historical production for Enochdhu Field is shown in Figure 5.6.14. Cumulative and recent production for Enochdhu Field are shown in the following table: Cumulative Production March 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 10,306 10,652 5,988 1,140 1,001 3,258 Geology Enochdhu Field produces from the Paleocene Forties Formation at approximately 6,900 ft TVDSS and is saddle-separated from Callanish Field. A type log section illustrating this formation is shown in Figure 5.6.15. A depth structure map on the top of the Forties Formation is shown in Figure 5.6.13. Methodology Reserves estimates are based on DCA. Similarly to Callanish Field, Enochdhu Field has a strong water drive and has seen a flattening in water cut behavior. Thus, ultimate oil recovery was estimated through Cartesian and semilogarithmic plots of oil cut versus cumulative oil to provide the range of 1P to 3P estimates. Rate-versus-time plots were used to trend historical production and target the expected ultimate recovery. Terminal water cuts greater than 95 percent were chosen for the 1P, 2P, and 3P estimates. With the additional new 15/29b-F5 well in Callanish Field, rates are now constrained in Enochdhu Field. Forecasts are constrained and are designed to increase as Callanish Field production is forecasted to decrease. No study was made to determine whether any developed non-producing reserves, undeveloped reserves, or contingent resources might be established for Enochdhu Field.
Page 27 6.0 MONARB AREA ______________________________________________________________ The Montrose-Arbroath (MonArb) Area includes the hub fields of Montrose and Arbroath and the satellite fields of Arkwright, Brechin, Cayley, Godwin, Shaw, and Wood. Carnoustie Field, also a satellite field in the MonArb Area, was not included in this evaluation because we estimate it to have negligible volumes of reserves. The MonArb Area is shown on the location map in Figure 6.9.1. The Montrose Alpha platform, commissioned in 1976, is an eight-legged steel jacket structure that has processing, separation, and export facilities for hydrocarbons produced from Montrose, Arbroath, Arkwright, Brechin, Carnoustie, Godwin, and Wood Fields. The Montrose Alpha platform was modified in 1990 to receive liquids from the Arbroath platform, a minimal facilities platform that receives hydrocarbons from Arbroath, Arkwright, Brechin, Carnoustie, and Godwin Fields. Gas and liquids are initially separated at this platform, then exported to the Montrose Alpha platform via a 10-inch liquids pipeline and a 16-inch gas pipeline. Produced liquids from the MonArb Area are exported to the Forties Charlie platform via a 48-km, 14-inch pipeline owned by the MonArb partners. A new platform, the Montrose BLP, was built in 2016 and connected to the Montrose Alpha platform by a 71-m bridge. The Montrose BLP receives hydrocarbons from Cayley and Shaw Fields, which are two subsea developed fields discovered in 2007 and 2009, respectively. Oil is routed over the bridge to the Montrose Alpha platform and gas is exported via a gas riser into a 6-inch export pipeline into the CATS pipeline. A summary of certain geologic characteristics of each of the fields included in the MonArb Area is shown in the table below. Field Reservoir Depth (ft TVDSS) Trap Montrose Forties (1) (1) Arbroath Forties (1) (1) Arkwright Forties (1) (1) Brechin Forties (1) (1) Cayley Fulmar 11,600 Faulted Three-way Closure Godwin Fulmar (1) (1) Shaw Fulmar 10,700 Faulted Three-way Closure Wood Fulmar (1) (1) (1) No geologic evaluation was performed. A summary of certain petrophysical parameters for each of the fields included in the MonArb Area is shown in the table below. Field Reservoir Primary Fluid Solution GOR (CF/BBL) Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Montrose Forties Oil (1) (1) (1) (1) Arbroath Forties Oil (1) (1) (1) (1) Arkwright Forties Oil (1) (1) (1) (1) Brechin Forties Oil (1) (1) (1) (1) Cayley Fulmar Gas - 100 24 12 Godwin Fulmar Oil (1) (1) (1) (1) Shaw Fulmar Oil 900 - 19 25 Wood Fulmar Oil (1) (1) (1) (1) (1) No geologic evaluation was performed.
Page 28 For the MonArb Area, we used DCA, volumetric analysis, and material balance to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used for each of the fields included in the MonArb Area is shown in the table below. Field Evaluation Methods Montrose DCA Arbroath DCA Arkwright DCA Brechin DCA Cayley DCA, Volumetric Analysis, and Material Balance Godwin DCA Shaw DCA and Volumetric Analysis Wood DCA Development plans for the MonArb Area were provided by Ithaca, and a summary of the development timing for projects in the MonArb Area is shown in the table below. Field Project Timing Class MonArb Area Facilities 2022–2040 Reserves Montrose Phase 1 2022–2025 Reserves Montrose Phase 2 2026–2027 Reserves Arbroath Facilities 2022–2025 Reserves Arbroath Reinstatements 2022–2023 Reserves Shaw Facilities 2022 Reserves Shaw SHC Well 2022–2023 Reserves Wood Facilities 2022–2023 Reserves 6.1 MONTROSE FIELD Montrose Field, operated by Repsol Sinopec Resources UK Limited (Repsol), is an oil field located in Blocks 22/17n and 22/18n in the UK Sector of the North Sea in a water depth of approximately 289 ft. Montrose Field is shown on the location map in Figure 6.9.1. The field, located approximately 200 km east of Aberdeen, was discovered in 1971 by the drilling of the 22/18-2 well. The field was appraised by the drilling of the 22/17-1 well, and production commenced in June 1976. As of April 2022, 25 production wells and 5 water injection wells have been drilled from the Montrose Alpha platform. Separation, processing, and export of hydrocarbons also occurs on the Montrose Alpha platform. The 22/17-A28Z well is currently the only well online; a number of mechanical failures led to several other wells being prematurely shut in. A proposed infill program is being progressed by the operator, with the FID for Phase 1 expected in 2022. Phase 1 includes the drilling of 4 new subsea wells (the MRC, MRG, MRH, and MRI) and the purchase of associated production equipment. First oil for the Phase 1 wells is expected in 2025. Phase 2 includes the drilling of 2 additional subsea production wells (the MRJ and MRSW), and first oil for the Phase 2 wells is expected in 2027. Montrose Field produces from a single reservoir, the Forties Sandstone. A summary graph of the gross historical production for Montrose Field is shown in Figure 6.9.2. Cumulative and recent production for Montrose Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 91,263 64,265 56,634 429 219 1,549
Page 29 Geology The Paleocene Forties Sandstone is a fine- to coarse-grained sandstone interbedded with silt and mudstone that was deposited as a marine turbidite fan complex. The formation ranges from 300 to 400 ft in thickness, and it has a very high NTG of 70 to 100 percent. The porosity ranges from 21 to 24 percent. The field is located on an unfaulted four-way anticline with very low relief. The structure is very flat with dips of less than 4 degrees. Seismic amplitudes are present within the reservoir and provide insight into reservoir presence, quality, and thickness. Methodology Proved developed producing (PDP) reserves for the 22/17-A28Z well were forecasted by DCA, including a review of WOR and oil production rate versus cumulative oil production. Undeveloped reserves have been estimated by a combination of DCA on shut-in wells located near the proposed infill locations and volumetric analysis. Recovery factors used in volumetric estimates are based on the range of swept zone recovery factors calculated for historical production wells. Reserves by Project We estimate the Ithaca working interest reserves by development project for Montrose Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Phase 1 1P 02,402.2 1,347.2 0.0 02,634.5 Phase 1 2P 06,051.4 3,421.1 0.0 06,641.3 Phase 1 3P 10,438.3 5,859.6 0.0 11,448.5 Phase 2 1P 0,0662.0 0373.3 0.0 00,726.4 Phase 2 2P 01,161.7 0657.4 0.0 01,275.0 Phase 2 3P 01,693.9 0964.4 0.0 01,860.2 6.2 ARBROATH FIELD Arbroath Field, operated by Repsol, is an oil field located in Blocks 22/17n, 22/17s, 22/18a, and 22/22a in the UK Sector of the North Sea in a water depth of approximately 305 ft. Arbroath Field is shown on the location map in Figure 6.9.1. The field, located approximately 8 km south of Montrose Field, was discovered in 1969 by the drilling of the 22/18-1 well. Production commenced in April 1990. As of April 2022, 26 production wells and 9 water injection wells have been drilled from the Arbroath platform. Arbroath is a minimum facilities platform with gas and liquids separation taking place prior to fluids being exported to the Montrose Alpha platform for further processing and export. There are 5 wells currently producing, and most historical producing wells are shut-in because of water production. Water injection ceased in 2004. Three additional reinstatements are planned in the near term for the 22/17-T17, 22/17-T20, and 22/17-T25 wells. Arbroath Field produces from a single reservoir, the Forties Sandstone. A summary graph of the gross historical production for Arbroath Field is shown in Figure 6.9.3. Cumulative and recent production for Arbroath Field are shown in the following table:
Page 30 Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 155,756 84,569 88,253 1,138 405 6,532 Geology Arbroath Field is located adjacent to Montrose Field and is only separated by a minor saddle in the structure. It also produces from the same Forties Sandstone with comparable reservoir characteristics of thickness, NTG, and porosity. The structural setting is very analogous to Montrose Field. Methodology PDP reserves for the producing wells were forecasted by DCA using projections of total liquid rates in combination with projections of WORs. Non-producing reserves for the reinstatement wells have been estimated based on the performance of the recently reinstated 22/17-T19 and 22/17-T21 wells. Reserves by Project We estimate the Ithaca working interest reserves by development project for Arbroath Field, as of June 30, 2022, to be: Working Interest Reserves Oil Gas NGL Equivalent Project Category (MBBL) (MMCF) (MBBL) (MBOE) Reinstatements 1P 048.4 18.9 0.0 051.6 Reinstatements 2P 073.6 28.7 0.0 078.5 Reinstatements 3P 102.3 39.9 0.0 109.2 6.3 ARKWRIGHT FIELD Arkwright Field, operated by Repsol, is an oil field located in Block 22/23a in the UK Sector of the North Sea in a water depth of approximately 308 ft. Arkwright Field is shown on the location map in Figure 6.9.1. The field, located approximately 217 km east of Aberdeen, was discovered in 1990 by the drilling of the 22/23a-3 well. Production commenced in November 1996 with three production wells. A fourth, horizontal well was drilled and brought online in 2007. The 22/23a-C4 well is the only well currently online. According to Repsol, the 22/23a-C3 well is shut-in pending pipeline ullage and the 22/23a-C2 well is infrequently produced. Arkwright Field produces from a single reservoir, the Forties Sandstone. A summary graph of the gross historical production for Arkwright Field is shown in Figure 6.9.4. Cumulative and recent production for Arkwright Field are shown in the following table:
Page 31 Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 23,068 13,997 6,993 763 380 1,808 Geology Arkwright Field is located adjacent to Arbroath and Montrose Fields. Similarly, this field produces from the Forties Sandstone with very analogous reservoir and structural characteristics to the adjacent fields. Methodology All reserves for Arkwright Field have been estimated by DCA. In addition to the PDP 22/23a-C4 well, probable and possible non-producing reserves were also forecasted for the 22/23a-C2 and 22/23a-C3 wells. These forecasts are based on each well's production history prior to going offline. These two wells are scheduled to produce sequentially after the 22/23a-C4 well depletes, starting with the 22/23a-C3 well. No proved developed non-producing reserves have been estimated for those wells because of the potential for uneconomic low oil production rates upon attempted reactivation. 6.4 BRECHIN FIELD Brechin Field, operated by Repsol, is an oil field located in Block 22/23a in the UK Sector of the North Sea in a water depth of approximately 305 ft. Brechin Field is shown on the location map in Figure 6.9.1. The field, located approximately 221 km east of Aberdeen, was discovered in 2004 by the drilling of the 22/23a-7 well. Production commenced in June 2005 from the 22/23a-7Z well, a horizontal sidetrack on the original discovery well. Brechin Field produces from a single reservoir, the Forties Sandstone. A summary graph of the gross historical production for Brechin Field is shown in Figure 6.9.5. Cumulative and recent production for Brechin Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Forties 5,469 5,919 4,331 948 716 2,156 Geology Brechin Field is located immediately adjacent to Arkwright Field and also produces from the Paleocene Forties Sandstone. The reservoir exhibits similar characteristics as the other fields, but it has slightly less porosity that ranges from 19 to 20 percent. This four-way anticline closure was discovered because of a seismic anomaly. Methodology PDP reserves for Brechin Field were forecasted using DCA. Our study indicates that there are no non- producing or undeveloped reserves for Brechin Field. It is our understanding that there are no future development projects planned for Brechin Field.
Page 32 6.5 CAYLEY FIELD Cayley Field, operated by Repsol, is a gas-condensate field located in Block 22/17s in the UK Sector of the North Sea in a water depth of approximately 298 ft. Cayley Field is shown on the location map in Figure 6.9.1. The field, located approximately 10 km west of the Montrose Alpha platform, was discovered in 2007 by the drilling of the 22/17-3 exploration well. The field was appraised by the drilling of the 22/17-3Z, 22/17-3Y, and 22/22a-7X wells, and production commenced in June 2017. As of April 2022, a single production well has been drilled as a subsea tieback to the Montrose Alpha platform. Separation, processing, and export of hydrocarbons also occurs on the Montrose Alpha platform. The 22/17-J1 well (also known as the CP01 well) started producing in June 2017 and is still currently producing. Cayley Field produces from the Fulmar Formation. A summary graph of the gross historical production for Cayley Field is shown in Figure 6.9.6. Cumulative and recent production for Cayley Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Fulmar 2,931 58,271 7 850 23,743 0 Geology Cayley Field produces from the Upper Jurassic Fulmar Formation, which consists of shallow marine sandstones. The Fulmar Formation is approximately 200 ft thick with a moderate NTG of approximately 65 percent. The reservoir is of good quality with a porosity averaging approximately 23 percent. The field is a highly faulted structure with faulting occurring in various orientations. Some faults have significant throw that is greater than the thickness of the Fulmar Formation. A type log section illustrating the Fulmar Formation is shown in Figure 6.9.7. A depth structure map on the top of the Fulmar Formation is shown in Figure 6.9.8. Net pay maps were generated for the Upper and Lower Fulmar Formations. Maps were generated based on the lowest known gas depth, a maximum case to a depth of 12,720 ft TVDSS and two intermediate cases. Volumetric analyses were performed based on these maps. Methodology PDP reserves for the producing well were forecasted by DCA and compared against the volumetric analysis for reasonableness of the estimated recovery factors. A material balance analysis was also performed. The material balance analysis did not indicate that the reservoir was behaving in a purely tank-like manner. Rather, there was an early response period during the first 20 billion cubic feet of production, but the subsequent pressure response indicated energy support that was interpreted to be gas feeding in from the adjacent 1B Fault Block. The latter response portion of the material balance analysis indicated a connected volume in reasonable agreement with the lower of the intermediate volumetric cases. 6.6 GODWIN FIELD Godwin Field, operated by Repsol, is an oil field located in Block 22/17s in the UK Sector of the North Sea in a water depth of approximately 289 ft. Godwin Field is shown on the location map in Figure 6.9.1. The
Page 33 field, located approximately 206 km east of Aberdeen, was discovered in 2009 by the drilling of the 22/17-4 well and appraised by the drilling of an updip sidetrack, the 22/17-4Z well. Production commenced in July 2015 from a single horizontal well, the 22/17-T27, which was drilled as an extended-reach well from the Arbroath platform. Godwin Field produces from a single reservoir, the Fulmar Formation. A summary graph of the gross historical production for Godwin Field is shown in Figure 6.9.9. Cumulative and recent production for Godwin Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Fulmar 4,389 1,944 2,561 590 258 2,366 Geology Godwin Field is located adjacent to Cayley Field and also produces from the Fulmar Formation. The reservoir characteristics are similar to those at Cayley Field. The structure is stratigraphically trapped to the east and south by the Triassic Smith Bank mudstones, dip-closed to the west, and combination fault- and dip-closed to the north. Several north-to-south-trending faults exist in the field. Methodology PDP reserves were forecasted by DCA. Our study indicates that there are no non-producing or undeveloped reserves for Godwin Field. It is our understanding that the operator does not have any future development projects planned for Godwin Field. 6.7 SHAW FIELD Shaw Field, operated by Repsol, is an oil field located in Block 22/22a in the UK Sector of the North Sea in a water depth of approximately 313 ft. Shaw Field is shown on the location map in Figure 6.9.1. The field, located approximately 17 km south of the Montrose Alpha platform, was discovered in 2009 by the drilling of the 22/22a-7 exploration well. The field was appraised by the drilling of the 22/22a-7Z and 22/22a-7Y wells, and production commenced in May 2017. As of April 2022, two production wells and one water injection well have been drilled as subsea tiebacks to the Montrose Alpha platform. Separation, processing, and export of hydrocarbons also occurs on the Montrose Alpha platform. The 22/22a-N2 well (also known as the SHA well) started producing in May 2017 and is still producing. The 22/22a-N3 well (also known as the SHB well) started producing in June 2019 and is still producing. Water injection into the 22/22a-R1 well (also known as the SHD well) started in July 2018. Water injection stopped in May 2020 and recommenced in March 2021. A third production well, the SHC well, is planned to be drilled in 2022 with first production expected in November 2022. Shaw Field produces from a single reservoir, the Fulmar Formation. A summary graph of the gross historical production for Shaw Field is shown in Figure 6.9.10. Cumulative and recent production for Shaw Field are shown in the following table:
Page 34 Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Fulmar 22,678 20,419 1,601 8,660 9,097 3,165 Geology Shaw Field also produces from the Fulmar Formation but the reservoir is much thicker here, over 600 ft thick. The porosity is approximately 19 percent. At Shaw Field, the Fulmar Formation has a highly cemented zone that is a little over 100 ft thick located approximately two-thirds from the top of the reservoir. The structure has north-to-south-trending faults. To the south and west the structure is dip-closed and to the north and east it is stratigraphically sealed against the Smith Bank Formation. A type log section illustrating the Fulmar Formation is shown in Figure 6.9.11. A depth structure map on the base of the Cretaceous Unconformity is shown in Figure 6.9.12. Net pay maps were generated for the Fulmar Formation to the lowest known oil depth (which is the base of the 22/22a-R1 injection well) and to a deeper, high-side possible OWC depth. An attic map to the top of the 22/22a-R1 injection well was also generated. A volumetric analysis was performed based on these maps. Methodology PDP reserves for the producing wells were forecasted by DCA and compared against the volumetric analysis for reasonableness of the estimated recovery factors. Reserves for the undeveloped SHC location are based on the volumetric analysis and analogous performance to the existing production wells adjusted for somewhat reduced field pressure due to lag between injected volumes and produced volumes. Reserves by Project We estimate the Ithaca working interest reserves by development project for Shaw Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) SHC Well 1P 1,333.3 1,126.6 0.0 1,527.5 SHC Well 2P 2,368.7 2,001.5 0.0 2,713.8 SHC Well 3P 4,178.0 3,530.4 0.0 4,786.7 6.8 WOOD FIELD Wood Field, operated by Repsol, is a volatile oil field located in Block 22/18a in the UK Sector of the North Sea in a water depth of approximately 296 ft. Wood Field is shown on the location map in Figure 6.9.1. The field, located approximately 215 km east of Aberdeen, was discovered in 1996 by the drilling of the 22/18-6 well. Production commenced in December 2007 from a single horizontal subsea well, the 22/18-7 (also known as the W01), which is tied back to the Montrose Alpha platform.
Page 35 Wood Field produces from a single reservoir, the Fulmar Formation. A summary graph of the gross historical production for Wood Field is shown in Figure 6.9.13. Cumulative and recent production for Wood Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Fulmar 4,278 9,755 1,010 684 1,626 1,020 Geology Wood Field also produces from the Fulmar Formation. In this field, the interval is approximately 400 ft thick with a high NTG that ranges from 75 to 80 percent. The porosity is approximately 21 percent. The structure is a very highly faulted four-way anticline. These faults have various orientations but most appear to be small-throw faults that do not fully offset the reservoir. Methodology PDP reserves were forecasted based on DCA. Our study indicates that there are no non-producing or undeveloped reserves for Wood Field. It is our understanding that the operator does not have any future development projects planned for Wood Field.
10 3 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 3 10 4 10 5 10 GAS (MCF / MO) 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 | | | | | | | | | | | | | | | | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN WOOD FIELD UNITED KINGDOM SECTOR OF THE NORTH SEA ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 Figure 6.9.13 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
TECHNICAL DISCUSSION SECTION 7.0 – MARINER AREA
Page 36 7.0 MARINER AREA ______________________________________________________________ The Mariner Area comprises Mariner, Mariner East, and Cadet Fields. Mariner Field is actively producing, and the volumes for Mariner East and Cadet Fields are classified as contingent resources. The Mariner Area location map is shown in Figure 7.4.1. Mariner and Mariner East Fields target the Maureen Formation and Heimdal Sandstones, and Cadet Field targets the Heimdal Sandstones. Mariner Area development is centered on Mariner A, a steel jacket production, drilling, and living quarters platform. The platform has 60 well slots, of which 50 can be concurrently active. Topsides production capacity is 80,000 BOPD and 290,000 BWPD, with injection capacity of 345,000 BWPD. Oil is exported from Mariner A to Mariner B, a fixed floating storage unit, then to shuttle tankers. Oil production began in 2019, and the Mariner A platform has a 40-year design life. A summary of certain geologic characteristics of the fields included in the Mariner Area is shown in the table below. Field Reservoir Depth (ft TVDSS) Trap Mariner Heimdal 3,400 Stratigraphic Pinch-out Mariner Maureen 4,600 Monoclinal Dip with Stratigraphic Pinch-out Mariner East Heimdal 3,900 Stratigraphic Pinch-out Mariner East Maureen 4,900 Monoclinal Dip with Stratigraphic Pinch-out Cadet Heimdal 3,800 Stratigraphic Pinch-out A summary of certain petrophysical parameters for the fields included in the Mariner Area is shown in the table below. Field Reservoir Primary Fluid Solution GOR (CF/BBL) Average Porosity (%) Average Swi (%) Mariner Heimdal Oil 138 34 20 Mariner Maureen Oil 188 30 25 Mariner East Heimdal Oil 138 34 20 Mariner East Maureen Oil 188 30 25 Cadet Heimdal Oil 138 34 20 For the fields included in the Mariner Area, we used DCA, volumetric analysis, and analogy to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used for each field included in the Mariner Area is shown in the table below. Field Evaluation Methods Mariner DCA, Volumetric Analysis, and Analogy Mariner East Volumetric Analysis and Analogy Cadet Volumetric Analysis and Analogy Development plans for the Mariner Area were provided by Ithaca, and a summary of the development timing for projects in the Mariner Area is shown in the table below.
Page 37 Field Project Timing Class Mariner Heimdal Reserves Wells 2022–2031 Reserves Mariner Maureen First Campaign 2022–2023 Reserves Mariner Maureen Second Campaign 2026–2029 Reserves Mariner Heimdal Contingent Resources Wells 2032–2035 Contingent Resources Mariner Maureen Third Campaign 2030–2032 Contingent Resources Mariner Polymer Injection 2023–2027 Contingent Resources Mariner East Facilities 2023–2030 Contingent Resources Mariner East Wells 2030–2033 Contingent Resources Cadet Facilities 2026–2034 Contingent Resources Cadet Wells 2034–2039 Contingent Resources 7.1 MARINER FIELD Mariner Field, operated by Equinor UK Limited (Equinor), is located in Blocks 9/11a, 9/11b, 9/11c, and 9/11g in the UK Sector of the North Sea in a water depth of approximately 330 ft. The field, located approximately 150 km east of the Shetland Islands, was discovered by Union Oil Company of California (Unocal) in 1981, with the drilling of the 9/11-1 well. Texaco took ownership of Mariner Field in 1984. Unocal had drilled 4 additional appraisal wells by that time, and Texaco drilled 8 appraisal wells from 1995 to 1997. Equinor assumed operatorship in 2007. To date, there are 22 exploration and appraisal wells and 20 development well penetrations, including sidetracks. First production occurred in August 2019, and the field production rate reached 50,000 BOPD in 2021. The produced oil is heavy, and typical density values are 15 degrees API in the Maureen Formation and 11 degrees API in the Heimdal Sandstones. Production is accomplished with the use of ESPs in every well plus the use of diluent. Diluent was initially used for production from the Maureen Formation, but it is our understanding that this technique has been progressively phased out. It will be used for production of the heavier oil from the Heimdal Sandstone wells. As of the end of February 2022, there were ten wells actively producing from the Maureen Formation and three active water injection wells in the Maureen Formation, one oil well producing from the Heimdal Sandstones with no water injection into the Heimdal Sandstones, and one well returning to production in August 2022 following an ESP replacement. Mariner Field has produced from the Maureen Formation and the Heimdal Sandstones. A summary graph of the gross historical production for Mariner Field is shown in Figure 7.4.2. Cumulative and recent production for Mariner Field are shown in the following table: Cumulative Production December 2021 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Maureen 21,422 4,483 63,063 19,407 4,280 100,943 Heimdal 00,348 0,055 00,049 02,689 0,425 000,866 Total 21,770 4,539 63,113 22,095 4,705 101,810 Totals may not add because of rounding. Geology Mariner Field is a complex field consisting of two producing formations, the Middle-to-Upper Paleocene Maureen Formation and the Heimdal Sandstones of slightly younger but similar age. The Maureen Formation is present at Mariner and Mariner East Fields and was deposited in a mid-shelf marine
Page 38 environment as a series of sand-rich turbidite sheet lobes. The structure is mostly a monoclonal, east- dipping surface. Slumping is believed to have occurred after deposition of the Maureen Formation, creating intra-formation thrusting and separating the reservoir into various tanks with multiple OWCs throughout the accumulation. The Maureen Formation has very good reservoir characteristics, with 30 percent porosity and an Swi of 25 percent. A type log section illustrating the Maureen Formation for Mariner and Mariner East Fields is shown in Figure 7.4.3, and a depth structure map representing the top of the Maureen Formation is shown in Figure 7.4.4. Following deposition of the Maureen Formation, sea level rose leading to the deposition of hemipelagic mudstones and sandstones. This increase in overburden remobilized sands, most likely from the Maureen Formation, creating injectites that are known as the Heimdal Sandstones. This formation is present in Mariner, Mariner East, and Cadet Fields. The Heimdal Sandstones are vertical dikes and horizontal sills that form a complex system of mostly interconnected sandbodies, which are identified using 3-D seismic data. They stand out as bright amplitudes known as geobodies, indicating the presence of sandbodies and their stratigraphic limits. The Heimdal Sandstones can be in pressure communication but still have unique contacts from one sandbody to another. A schematic illustrating the depositional setting of the injectites is shown in Figure 7.4.5. Injectites generally have excellent reservoir characteristics. The Heimdal Sandstones in the Mariner Area are no exception with 34 percent porosity and an Swi of 20 percent. A type log section illustrating the Heimdal Sandstones for Mariner, Mariner East, and Cadet Fields is shown in Figure 7.4.6, and a depth structure map representing the top of the Heimdal Sandstones is shown in Figure 7.4.7. Methodology Active producing wells are being produced via waterflood drive or experience pressure support from the surrounding aquifer, and most of these wells have sufficient production history to estimate future production through performance-based analysis. DCA was performed by estimating the total liquid production rate and WOR, using different trends for the 1P, 2P, and 3P cases, and then using these values to calculate oil production rates. Terminal water cuts and WORs were determined for the 1P, 2P, and 3P cases from a review of historical terminal rates along with consideration of future operating practices. Future development of the Maureen Formation includes the drilling of four additional production wells and one additional water injection well in 2022 and 2023. In addition, three production wells and one water injection well are further planned from 2026 to 2029. The production wells are a mix of infill locations and step-out locations. Estimated reserves for undeveloped locations in the Maureen Formation are based on adjacent well performance for the infill locations and average region segment performance for the step-out locations. Future development of the Heimdal Sandstones includes the drilling of 36 additional production well locations and 19 injection well locations between 2022 and 2031. It is our understanding that these wells are committed wells per the FDP. Reserves estimates for undeveloped locations in the Heimdal Sandstones are based on volumetric analysis and analogy to the performance of the only current active Heimdal production well, the 9/11a-A24. A net pay map was generated for the aggregate Heimdal sandbodies package. Polygons were drawn around the areas with the thickest aggregate reservoir development based on this map, and estimates for in-place volumes were calculated for these expected development areas. An estimated average recovery factor of 15 percent was calculated based on the EUR for the 9/11a-A24 well and the in-place volume in an estimated production area surrounding the 9/11a-A24 lateral. This recovery factor was applied to the in-place volumes calculated for the expected development areas. The 1P reserves estimates for the Heimdal Sandstones are based on an average recovery factor of 10 percent, and the 3P reserves estimates are based on an average recovery factor of 20 percent.
Page 39 Two projects in Mariner Field are classified as contingent resources. One is a polymer injection project that targets the Heimdal Sandstones and is similar in concept to the operation carried out in Captain Field. Estimates of contingent resources associated with a Heimdal polymer injection project assume successful polymer flood implementation in two of the five Mariner Field areas that have been modeled by the operator: the Central South Lower area and the Central East area. Operator modeling of incremental production resulting from polymer injection was reviewed, and the estimates of increased recovery were checked against in-place volumes and seem reasonable. The increases in estimates are relatively modest compared to the experience at Captain Field, primarily because the oil at Mariner Field is considerably denser. The polymer flood contingent resources are contingent upon the completion of a successful pilot program. The second contingent resources project involves the drilling of additional production and injection locations in the Heimdal Sandstones. These locations would target areas of the reservoir that are less well defined and may be less well developed. These locations are contingent upon the success of the preceding development of the Heimdal Sandstones. Estimates of contingent resources associated with developing areas of the Heimdal Sandstones outside of the expected initial development areas based on our mapping were made using the same methodology that was used for estimating reserves. Reserves and Contingent Resources by Project We estimate the Ithaca working interest reserves by development project for Mariner Field, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Heimdal Reserves Wells 1P 06,918.6 0.0 0.0 06,918.6 Heimdal Reserves Wells 2P 10,171.9 0.0 0.0 10,171.9 Heimdal Reserves Wells 3P 12,714.6 0.0 0.0 12,714.6 Maureen First Campaign 1P 00,878.1 0.0 0.0 00,878.1 Maureen First Campaign 2P 01,102.4 0.0 0.0 01,102.4 Maureen First Campaign 3P 01,326.9 0.0 0.0 01,326.9 Maureen Second Campaign 1P 00,265.4 0.0 0.0 00,265.4 Maureen Second Campaign 2P 00,442.4 0.0 0.0 00,442.4 Maureen Second Campaign 3P 00,680.9 0.0 0.0 00,680.9 We estimate the Ithaca working interest contingent resources by development project for Mariner Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Heimdal Contingent Resources Wells 1C 0,559.6 0.0 0.0 0,559.6 Heimdal Contingent Resources Wells 2C 0,959.3 0.0 0.0 0,959.3 Heimdal Contingent Resources Wells 3C 1,258.2 0.0 0.0 1,258.2 Maureen Third Campaign 1C 0,467.7 0.0 0.0 0,467.7 Maureen Third Campaign 2C 0,751.9 0.0 0.0 0,751.9 Maureen Third Campaign 3C 0,982.3 0.0 0.0 0,982.3 Polymer Injection 1C 0,833.0 0.0 0.0 0,833.0 Polymer Injection 2C 1,581.3 0.0 0.0 1,581.3 Polymer Injection 3C 2,330.9 0.0 0.0 2,330.9
Page 40 7.2 MARINER EAST FIELD Mariner East Field is located southeast of Mariner Field in Blocks 9/11a and 9/11b in the UK Sector of the North Sea. Mariner East Field was discovered by the drilling of the 9/11b-11 well, which penetrated the Maureen Formation and Heimdal Sandstone. The development plan assumes a standalone unmanned wellhead platform tied back to the Mariner A platform that would target both the Maureen Formation and Heimdal Sandstone. The Maureen Formation is assumed to be developed with six production wells and two injection wells, and the Heimdal Sandstone is assumed to be developed with three production wells and one injection well. The volumes included in this report for Mariner East Field are classified as contingent resources. Geology The Maureen Formation and Heimdal Sandstones are present at Mariner East Field, and they share the characteristics that are described for Mariner Field in Section 7.1.1. A type log section illustrating the Maureen Formation at Mariner Field is shown in Figure 7.4.3, and this type log is appropriate to describe the formation at Mariner East Field also. The depth structure map on the top of the Maureen Formation includes Mariner East Field and is shown in Figure 7.4.4. A type log section illustrating the Heimdal Sandstones is shown in Figure 7.4.6, and a depth structure map on the top of the Heimdal Sandstones is shown in Figure 7.4.7. Methodology Volumetric analysis and analogy were used to estimate the contingent resources within Mariner East Field. For the Maureen Formation, net pay maps were generated for Mariner Field and Mariner East Field. Estimates of original oil-in-place (OOIP) were calculated for the developed segments of the Maureen Formation of Mariner Field, and ultimate recovery factor estimates were calculated based on the EURs of the wells. Contingent resources estimates were then derived by applying the average Mariner Field recovery factor to oil-in-place estimates calculated for Mariner East Field. Contingent resources for the Heimdal Sandstones within Mariner East Field have been estimated using the same methodology as described for Mariner Field. Volumetric analysis based on a net pay map was combined with the ultimate recovery factor estimated for the producing 9/11a-A24 well. Contingent Resources by Project We estimate the Ithaca working interest contingent resources for Mariner East Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Wells and Facilities (1) 1C (1) 0,000.0 0.0 0.0 0,000.0 Wells and Facilities (1) 2C (1) 0,000.0 0.0 0.0 0,000.0 Wells and Facilities 3C 1,730.2 0.0 0.0 1,730.2 (1) There are no low estimate (1C) or best estimate (2C) contingent resources for Mariner East Field at the price and cost parameters used in this report.
Page 41 7.3 CADET FIELD Cadet Field is located west of Mariner Field in Block 8/15a in the UK Sector of the North Sea. Cadet Field was discovered by the drilling of the 8/15-1 well, which penetrated the Heimdal Sandstones. The development plan assumes a standalone unmanned wellhead platform tied back to the Mariner A platform. The Heimdal Sandstones are assumed to be developed with ten production wells and five injection wells. The volumes included in this report for Cadet Field are classified as contingent resources. Geology The Heimdal Sandstones are present at Cadet Field and share the characteristics that are described for Mariner Field in Section 7.1.1. A type log section illustrating the Heimdal Sandstones at Mariner Field is shown in Figure 7.4.6, and this type log is appropriate to describe the formation at Cadet Field also. The depth structure map on the top of the Heimdal Sandstones includes Cadet Field and is shown in Figure 7.4.7. Methodology Contingent resources for the Heimdal Sandstones within Cadet Field have been estimated using the same method as described for Mariner Field. Volumetric analysis based on a net pay map was combined with the ultimate recovery factor estimated for the producing 9/11a-A24 well. Contingent Resources by Project We have evaluated contingent resources for Cadet Field; however, there are no contingent resources at the price and cost parameters used in this report.
10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 6 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 4 10 5 10 6 10 GAS (MCF / MO) 2019 2020 2021 | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN MARINER FIELD UNITED KINGDOM SECTOR OF THE NORTH SEA ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions. Figure 7.4.2
TECHNICAL DISCUSSION SECTION 8.0 – JADE AND JADE SOUTH FIELDS
Page 42 8.0 JADE AND JADE SOUTH FIELDS ________________________________________________ Jade and Jade South Fields, operated by Harbour, are high-pressure, high-temperature gas-condensate fields located in Blocks 30/2c and 30/7b in the UK Sector of the North Sea in a water depth of approximately 260 ft. The fields are shown on the location map in Figure 8.4.1. Jade Field, located approximately 270 km east of Aberdeen, was discovered in 1996 and began producing in 2002 from a normally unattended installation (NUI). There are currently nine wells producing from a fixed wellhead platform, which is tied back to a dedicated separator on the Judy platform. Two of the nine wells produce cyclically. The Judy platform, operated by Harbour, is located approximately 17 km to the southeast and hosts the primary Jade processing facilities. Jade South Field is a southern extension of Jade Field. In the subsurface, it is separated from Jade Field by a structural saddle. Jade South Field produces from a single well, which is drilled from the same platform as the Jade Field wells. Jade Field produces from the Joanne and Judy Sandstones, and Jade South Field produces from the Joanne Sandstone. The single Jade South well came online in January 2022. A summary graph of the gross historical production for Jade and Jade South Fields is shown in Figure 8.4.2. Cumulative and recent production for Jade and Jade South Fields are shown in the following table: Cumulative Production January 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Joanne 35,416 607,308 3,615 5,193 42,175 393 Judy 08,660 056,831 0,378 - - - Joanne/Judy 10,894 135,438 0,752 0,241 04,355 072 Total 54,969 799,577 4,745 5,434 46,530 465 Totals may not add because of rounding. 8.1 GEOLOGY The structure at Jade and Jade South Fields consists of tilted fault blocks. The fields primarily produce from the Triassic Joanne Sandstone, which is a series of stacked fluvial channel sequences, at approximately 15,100 ft TVDSS. The Joanne Sandstone is quite thick and averages approximately 1,000 ft at Jade Field. Reservoir facies range from high permeability channel sands, up to 1 D, to very low permeability siltstones and shales. A type log section illustrating this formation is shown in Figure 8.4.3. A depth structure map on the top of the Joanne Sandstone is shown in Figure 8.4.4. A summary of certain geologic characteristics of Jade and Jade South Fields is shown in the table below. Field Reservoir Depth (ft TVDSS) Trap Jade Judy (1) (1) Jade Joanne 15,100 (1) Jade South Joanne 16,800 Faulted Dip Closure (1) No geologic evaluation was performed. 8.2 METHODOLOGY Reserves estimates for the producing wells are based on DCA, using both rate-versus-time and rate- versus-cumulative gas production methods. A well work program at the end of 2019 provided significant,
Page 43 sustained uplift to the field in 2020. A new well, the 30/02c-JM10, is intended to reestablish and reposition the 30/02c-J10 well and is scheduled to come online in 2022. DCA is also used for this well based on the historical performance of the 30/02c-J10 well, with a slight uplift given in ultimate recovery based on an expected more favorable structural position. The 30/02c-J13 well in Jade South Field was brought online in January 2022 with strong initial rates, comparable to those of early Jade Field wells. Reserves have been estimated using volumetrics and analogy to similar properties, along with the historical performance of Jade Field. A summary of certain petrophysical parameters for Jade and Jade South Fields is shown in the table below. Field Reservoir Primary Fluid Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Jade Judy Gas 070 (1) (1) Jade Joanne Gas 350 (1) (1) Jade South Joanne Gas 110 14 25 (1) No geologic evaluation was performed. 8.3 RESERVES BY PROJECT We estimate the Ithaca working interest reserves by development project for Jade and Jade South Fields, as of June 30, 2022, to be: Working Interest Reserves Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) JM Well 1P 513.8 2,917.5 088.4 1,105.2 JM Well 2P 653.1 3,708.4 112.4 1,404.8 JM Well 3P 814.6 4,625.4 140.2 1,752.2
Page 44 9.0 COOK FIELD _________________________________________________________________ Cook Field, operated by Ithaca, is an oil field located in Block 21/20a within the Central Graben Area of the UK Continental Shelf in a water depth of approximately 310 ft. Cook Field is shown on the location map in Figure 9.4.1. The field, located 195 km east of Aberdeen, was discovered by the drilling of Amoco's 21/20a-2 well in August 1983 and began commercial production from the 21/20a-P1 well in early 2000. Cook Field was developed under depletion drive by the single producing well until a water injection well, the 21/20a-P2, was drilled in October 2019. The injection well had limited uptime and was repaired in February 2021. Shortly after the February 2021 repair another defect was discovered in the injection system. A repair is planned for late 2022 to bring the well back into service. An additional water injection well, the Cook West well, is planned for 2024. Oil at Cook Field is light and undersaturated with oil gravity of approximately 38 degrees API and an in situ viscosity of approximately 0.3 cP at an average reservoir temperature of 300°F. Fluid expansion and rock compression have been the dominant drive mechanisms as the pressure has depleted nearly 7,000 psi to date. Additionally, there is evidence of aquifer encroachment and pressure support from the formation of a secondary gas cap. The 21/20a-P2 water injection well was drilled to provide additional pressure support and reservoir sweep. The 21/20a-P1 well is a subsea wellhead tied back approximately 12 km to the third- party-operated Anasuria FPSO. The FPSO is shared with additional subsea tiebacks including the Teal, Teal South, and Guillemot A developments. Oil volumes are offloaded via tanker from the Anasuria FPSO to oil markets. Gas volumes are exported via the subsea Shell-Esso Gas and Liquids (SEGAL) pipeline to the Shell Group-operated gas terminal at St. Fergus. Gas-lift infrastructure is in place and operational in the production well. Successful water injection performance has been realized after the recent installation of water injection infrastructure at the 21/20a-P2 well. Cook Field has produced from a single reservoir, the Fulmar Formation. A summary graph of the gross historical production for Cook Field is shown in Figure 9.4.2. Cumulative and recent production for Cook Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Fulmar 53,261 76,479 221 3,502 12,019 - 9.1 GEOLOGY The Cook Field structure consists of two four-way highs that have differing OWCs and that are separated by a normal fault. The productive horizon is the Fulmar Formation. Three fault block areas were mapped and named Main, South, and West Fault Blocks. An OWC was logged in the main block, and a lowest known oil (LKO) deeper than the OWC seen in the main block was logged in the south block. The west block appears connected and contiguous to the main block. The average depth of the structures is approximately 12,000 ft TVDSS. The average porosity is 21 percent, and the average Swi is 10 percent. A type log section illustrating this formation is shown in Figure 9.4.3. A depth structure map on the top of the Fulmar Formation is shown in Figure 9.4.4. A summary of certain geologic characteristics of Cook Field is shown in the table below. Reservoir Depth (ft TVDSS) Trap Fulmar 12,100 Three-way Stratigraphic Trap
Page 45 9.2 METHODOLOGY Because of the field transitioning to waterflood, reserves estimates are based on DCA using liquid rate versus time and WOR versus cumulative oil production to predict oil rate versus time, all guided by history- matched simulation models. In-place volumes were verified through material balance modeling. A summary of certain petrophysical parameters for Cook Field is shown in the table below. Reservoir Primary Fluid Solution GOR (CF/BBL) Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Fulmar Oil 0,900 - 21 10 The 21/20a-P1 and 21/20a-P2 wells share pressure depletion, but the LKO of the 21/20a-P2 well, at 12,250 ft TVDSS, is deeper than the OWC of the 21/20a-P1 well at 12,090 ft TVDSS. Because of this unexpected discrepancy, additional emphasis was placed on mapped volumes, P/Z estimates, and reservoir simulation. Simulation results were verified using displacement efficiencies and recoveries from the starting point of the waterflood and using available relative permeability lab data and Dykstra Parsons methods for waterflood sweep performance. Nearby analog fields were checked for reasonableness of waterflood recoveries. Differences in 1P, 2P, and 3P estimates were guided by two history-matched simulation models, both representing the difference in OWCs between the main and south fault blocks. One match used a pressure-dependent fault separating the main and south fault blocks. The other relied on a fault sealed down to the LKO found in the 21/20a-P2 well. Aquifer strength, vertical-to-horizontal permeability ratio, the size of the west block OOIP, and voidage played a role in the quality of the history match. Prediction outcomes, especially timing of oil volumes, were further impacted by assumed water injector performance. Liquid rate buildup profiles and water cut breakthrough timing were the key variables differentiating the reserves estimates. Contingent resources associated with the Cook West injection well have been estimated by focusing the analysis on the area between the current production well and injection well to approximate intra-well recovery factors. A similar recovery factor was applied to the intra-well area between the current production well and the planned Cook West injection well, with a discount to sweep efficiency based on geometric differences in the expected flooding pathway. This method was supported by results from Ithaca's reservoir simulation model, which included Cook West injection. Because the two field water injection wells are planned to share a constrained water injection supply pipeline, our predictions assume injection rates will be adjusted to balance injected pore volumes across the two flood regions to optimize waterflood front convergence on the production well. No study was made to determine whether any developed non-producing reserves or undeveloped reserves might be established for Cook Field. 9.3 CONTINGENT RESOURCES BY PROJECT We estimate the Ithaca working interest contingent resources by development project for Cook Field, as of June 30, 2022, to be:
Page 46 Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) West Injector (1) 1C (1) 0,000.0 0,000.0 0.0 0,000.0 West Injector 2C 3,919.4 1,151.5 0.0 4,118.0 West Injector 3C 6,160.9 2,062.7 0.0 6,516.5 (1) There are no low estimate (1C) contingent resources for Cook Field at the price and cost parameters used in this report.
Page 47 10.0 ERSKINE FIELD ______________________________________________________________ Erskine Field, operated by Ithaca, is a gas-condensate field located in Blocks 23/26a and 23/26b in the UK Sector of the North Sea in a water depth of approximately 300 ft. Erskine Field is shown on the location map in Figure 8.4.1. The field, located approximately 241 km east of Aberdeen, was discovered in 1985 and began producing in 1997 from a NUI operated remotely from the Lomond platform. In January 2018, the field was shut in because of a blockage of the condensate export line from the Lomond platform. Installation of a new line to bypass the blocked segment was completed and production was restarted in October 2018. From the Lomond platform, gas and condensate are exported separately to the North Everest platform, operated by Harbour, before gas is exported via the CATS. Condensate is exported through the FPS. There are currently four active wells. The W1 well is currently offline because of an issue with scale in the tubing. A remedial workover is planned in 2022. Erskine Field has produced from three reservoirs: the Erskine, Kimmeridge, and Pentland Sandstones. A summary graph of the gross historical production for Erskine Field is shown in Figure 10.4.1. Cumulative and recent production for Erskine Field are shown in the following table: Cumulative Production April 2022 Average Daily Rate Reservoir Oil (MBBL) Gas (MMCF) Water (MBBL) Oil (BOPD) Gas (MCFD) Water (BWPD) Erskine 41,482 228,135 01,250 4,141 35,734 333 Kimmeridge 09,142 059,239 00,330 - - - Pentland 19,862 100,710 10,933 0,017 00,116 012 Total 70,486 388,085 12,513 4,158 36,222 345 Totals may not add because of rounding. 10.1 GEOLOGY Hydrocarbons at Erskine Field have been produced from three Jurassic reservoirs: the Erskine, Kimmeridge, and Pentland Sandstones. The Erskine Sandstone is a fine-grained, bioturbated, shaley sandstone deposited in a shallow marine environment and is the main reservoir for the field. It is produced from approximately 15,100 ft TVDSS and has an average porosity of 22 percent and an Swi of 24 percent. The Kimmeridge Sandstone is an amalgamation of marine turbidites. The Pentland Sandstone is a mix of sandstone, shales, coals, and siltstones deposited in a fluvial-lacustrine environment. A type log section illustrating the Erskine and Pentland Sandstones is shown in Figure 10.4.2. A depth structure map on the top of the Erskine Sandstone is shown in Figure 10.4.3. A summary of certain geologic characteristics of Erskine Field is shown in the table below. Reservoir Depth (ft TVDSS) Trap Kimmeridge 14,800 Stratigraphic Trap Erskine 15,300 Faulted Dip Closure Pentland 15,600 Faulted Dip Closure 10.2 METHODOLOGY Reserves estimates for the producing wells are based on DCA and volumetric analysis. Erskine Field produces through the Lomond platform, which has historically experienced high downtime rates. Average
Page 48 forecast rates are based on recent daily rates and assumed average uptime rates taken from an analysis of historic downtime. A summary of certain petrophysical parameters for Erskine Field is shown in the table below. Reservoir Primary Fluid Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Kimmeridge Gas 190 20 07 Erskine Gas 120 22 24 Pentland Gas 210 16 22 One undeveloped location was included in the contingent resources category. The Location F well is an infill opportunity in the main fault block, roughly on-strike with the currently producing 23/26b-W5 well but with good separation from other producing wells. A future compressor rewheel project has also been included to drop the flowing tubing pressure of the producing wells and recover additional resources. The contingent resources have been estimated using volumetric analysis and analogy to similar properties. Development plans for Erskine Field were provided by Ithaca, and a summary of the development timing for projects in Erskine Field is shown in the table below. Project Timing Class Compressor Rewheel 2024 Contingent Resources Location F 2025 Contingent Resources 10.3 CONTINGENT RESOURCES BY PROJECT We estimate the Ithaca working interest contingent resources by development project for Erskine Field, as of June 30, 2022, to be: Working Interest Contingent Resources Project Category Oil (MBBL) Gas (MMCF) NGL (MBBL) Equivalent (MBOE) Compressor Rewheel 1C 0,758.1 06,115.3 000.0 1,812.4 Compressor Rewheel 2C 1,358.3 10,956.8 000.0 3,247.4 Compressor Rewheel 3C 2,179.2 17,578.5 000.0 5,209.9 Location F 1C 0,609.7 05,901.7 085.4 1,712.7 Location F 2C 1,375.9 11,098.8 160.7 3,450.2 Location F 3C 2,232.3 15,434.8 223.5 5,117.0
10.4 FIGURES
10 4 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 5 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 6 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 10 | OIL (BBL / MO) 10 5 10 6 10 7 10 GAS (MCF / MO) 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 | | | | | | | | | | | | | | | | | | | | | | | | | | GROSS HISTORICAL OIL AND GAS PRODUCTION PROPERTIES LOCATED IN ERSKINE FIELD UNITED KINGDOM SECTOR OF THE NORTH SEA ITHACA ENERGY (UK) LIMITED AS OF JUNE 30, 2022 Figure 10.4.1 All estimates and exhibits herein are part of this NSAI report and are subject to its parameters and conditions.
TECHNICAL DISCUSSION SECTION 11.0 – ELGIN-FRANKLIN FIELD
Page 49 11.0 ELGIN-FRANKLIN FIELD _______________________________________________________ Elgin-Franklin Field is composed of two gas-condensate fields, Elgin and Franklin Fields, located in Blocks 22/30b, 22/30c, 29/4d, 29/5b, and 29/5c in the UK Sector of the North Sea in a water depth of approximately 330 ft. The fields, operated by TotalEnergies E&P U.K. Limited (Total), are located approximately 240 km east of Aberdeen and are produced from a total of four wellhead platforms back to one central processing unit. Gas is exported via the Shearwater Elgin Area Line, and condensate is exported through the FPS. For the purposes of this report, these two fields are combined into Elgin-Franklin Field to facilitate the handling of projects impacting the shared infrastructure. Elgin-Franklin Field is shown on the location map in Figure 8.4.1. For the purposes of our technical analysis, Elgin-Franklin Field was split into three separate areas: Elgin, Franklin, and West Franklin. Each area has its own distinct structure and trap. The Elgin, Franklin, and West Franklin Areas were discovered in 1991, 1985, and 2003, respectively. All three areas have high- pressure, high-temperature fluids with initial pressures over 15,500 psia and temperatures over 370°F. There are currently seven active production wells in the Elgin Area, five in the Franklin Area, and four in the West Franklin Area. A summary graph of the gross historical production for Elgin-Franklin Field is shown in Figure 11.6.1. A summary of certain geologic characteristics of each area is shown in the table below. Area Reservoir Depth (ft TVDSS) Trap Elgin Fulmar 17,500 Faulted Anticline Franklin Fulmar 17,600 Faulted Dip Closure Franklin Pentland 18,200 Faulted Dip Closure Franklin Skagerrak 18,700 Faulted Dip Closure West Franklin Fulmar 18,600 Faulted Anticline A summary of certain petrophysical parameters for the Elgin, Franklin, and West Franklin Areas is shown in the table below. Area Reservoir Primary Fluid Solution CGR (BBL/MMCF) Average Porosity (%) Average Swi (%) Elgin Fulmar Gas 310 15 40 Franklin Fulmar Gas 160 13 43 Franklin Pentland Gas 160 10 60 Franklin Skagerrak Gas 160 10 - West Franklin Fulmar Gas 160 11 - For Elgin-Franklin Field, we used DCA, performance analysis, volumetric analysis, and analogy to classify, categorize, and estimate volumes in accordance with the 2018 PRMS definitions and guidelines. A summary of the evaluation methods used for Elgin-Franklin Field is shown in the table below. Category Evaluation Methods Producing Wells DCA Non-Producing Wells P/Z Analysis and Analogy Undeveloped Locations Analogy Development plans for Elgin-Franklin Field were provided by Ithaca, and development timing for projects in Elgin-Franklin Field is shown in the table below.