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May 2022
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I. EXECUTIVE SUMMARY
This memorandum is an internal, privileged work product prepared for the file by the Calderwood & Harkness LLP ("C&H") deal team in connection with the arbitration claim of Dunmore Energy Holdings Ltd. ("DEH") against the Republic of Valderia (the "Respondent") under the auspices of the International Centre for Settlement of Investment Disputes ("ICSID"), registered as ICSID Case No. ARB/22/11. The purpose of this memorandum is to set forth a comprehensive summary of the total quantum of DEH's claim arising from the expropriation by the Republic of Valderia of Concession No. HYD-2012-047 (the "Concession"), covering the Bloque Orinoco Sur (the "Concession Area"), a 1,240 km² onshore hydrocarbon concession located in the Valderian Orinoco Basin.
The total quantum of DEH's claim is USD 867,000,000 (eight hundred sixty-seven million United States dollars). This figure comprises three principal components:
Component 1 — Sunk Capital Expenditure: USD 347,000,000
Component 2 — Lost Future Profits (Discounted Cash Flow): USD 312,000,000
Component 3 — Consequential Damages: USD 208,000,000
The arithmetic sum of these components is confirmed as follows: USD 347,000,000 + USD 312,000,000 + USD 208,000,000 = USD 867,000,000.
This memorandum sets out the factual basis, analytical methodology, and key assumptions underlying each component of the claim. It further discusses the coordination framework with two retained expert advisors: (a) Pemberton Valuation Advisory LLC ("Pemberton"), the damages valuation expert retained by C&H on behalf of DEH, led by Dr. Elaine Cho, CFA, ASA, who will prepare the formal expert damages report; and (b) Ridgewell Subsurface Consultants Ltd. ("Ridgewell"), the independent petroleum engineering firm retained to provide technical opinions on reserves, production profiles, and subsurface data, led by Dr. Alistair Greaves, P.Eng. The quantum framework described herein will form the foundation for Pemberton's formal expert damages report, which is to be submitted if and when the ICSID proceedings are reactivated following their current period of dormancy.
The primary valuation date for purposes of the claim is April 17, 2021, which is the date of Presidential Decree No. 2021-0417, by which the Government of the Republic of Valderia ordered the nationalization of strategic hydrocarbon assets, including the Concession. The applicable standard of compensation is fair market value on the date immediately preceding the expropriation, as required by Article 5 of the Agreement Between the Government of the United Kingdom of Great Britain and Northern Ireland and the Government of the Republic of Valderia for the Promotion and Protection of Investments (the "UK-Valderia BIT (2006)"), which mandates "prompt, adequate, and effective compensation."
As discussed in greater detail below, we anticipate that the Respondent will challenge the quantum of the claim through its retained quantum expert, Northbridge Economic Consulting Ltd. ("Northbridge"), led by Dr. Henrik Johansson. This memorandum identifies the principal areas of anticipated challenge and sets forth initial strategies for addressing them. In particular, the memorandum flags a potential double-counting risk in the cumulative presentation of Components 1 and 2 and recommends that the claim be presented in the alternative, with the tribunal invited to select the appropriate measure of compensation.
II. BACKGROUND AND FACTUAL CONTEXT FOR QUANTUM
II.A. The Investment
Dunmore Energy Holdings Ltd. ("DEH") is a Cayman Islands exempted company, incorporated under the laws of the Cayman Islands, with its registered office at 4th Floor, Harbour Place, 103 South Church Street, George Town, Grand Cayman KY1-1002. DEH maintains its principal business office at 27 Curzon Street, London W1J 5HT, United Kingdom. DEH is an international energy company engaged in oil and gas exploration, production, and development, as well as renewable energy development across multiple jurisdictions.
DEH's investment in the Republic of Valderia was effected through its wholly owned subsidiary, Dunmore Valderia upstream S.A. ("DVU"), a Sociedad Anónima incorporated under the laws of the Republic of Valderia, with its registered address at Avenida Libertador 1480, Piso 12, Puerto Valdés, Valderia. DVU was established as the purpose vehicle for DEH's Valderian upstream oil and gas operations and served as the named concessionaire under the Concession.
Concession No. HYD-2012-047 was formally granted to DVU on September 12, 2013, pursuant to the Valderian Hydrocarbons Law of 2009 (the "Hydrocarbons Law"), by the Ministry of Energy and Natural Resources of the Republic of Valderia. The Concession was granted for a term of 30 years, with a scheduled expiry date of September 12, 2043. The Concession covered the Bloque Orinoco Sur, an onshore area of approximately 1,240 km² situated in the Valderian Orinoco Basin, one of the most prolific hydrocarbon provinces in the region.
The fiscal terms applicable to the Concession were established under the Hydrocarbons Law and the Concession agreement itself, and comprised the following principal elements:
(a) A royalty of 12.5% levied on the gross production value, payable to the Valderian Treasury;
(b) Valderian corporate income tax at a rate of 34%, applicable to DVU's taxable income; and
(c) A 10% carried interest held by PetroValderia S.A. ("PetroValderia"), the state-owned oil company of the Republic of Valderia, in the economic interest of the Concession, entitling PetroValderia to a 10% share of production revenues without an obligation to fund its proportionate share of capital or operating expenditures.
These fiscal terms, taken together, represented a significant economic burden on the Concession, but were consistent with the terms offered to international upstream operators in Valderia at the time the Concession was awarded. DEH accepted these terms on the understanding that the investment was protected under the legal framework of the Hydrocarbons Law, the Concession agreement, and the UK-Valderia BIT (2006).
II.B. Ownership Structure of DEH
The beneficial ownership structure of DEH as of the date of expropriation was as follows:
The Dunmore Family Trust is the controlling shareholder, with Sir Malcolm Dunmore serving as both the founder and the chairman of DEH's board of directors. Meridian Growth Partners Fund III, L.P. ("Meridian Fund III") is a private equity fund that invested in DEH in connection with the original development of the Valderian concession. Meridian Fund III is managed by Meridian Growth Partners LLC, a Delaware-domiciled fund manager. The presence of Meridian Fund III as a minority institutional shareholder is relevant to the reputational damages analysis (Component 3), as the expropriation has affected DEH's ability to attract similar institutional capital for future projects.
II.C. Operational History and Production Profile
DEH's investment in the Bloque Orinoco Sur progressed through three distinct phases over the period from 2013 to 2021:
Exploration Phase (2013–2016). Following the grant of the Concession in September 2013, DVU undertook an extensive exploration program across the Concession Area. This included the acquisition of a comprehensive 3D seismic survey covering approximately 800 km² of the Concession Area, followed by the drilling of seven (7) exploration wells between 2014 and 2016. Of the seven exploration wells drilled, five (5) were determined to be commercially viable, confirming the presence of significant hydrocarbon accumulations within the Bloque Orinoco Sur. The results of the exploration program formed the basis for DVU's decision to proceed to the development phase and underpinned the initial reserve estimates prepared by Ridgewell Subsurface Consultants Ltd.
Development Phase (2016–2019). On the strength of the exploration results, DVU committed to a full-scale field development program. Over the period from 2016 to 2019, DVU drilled twenty-two (22) development wells, constructed a 68-kilometer gathering pipeline connecting the production wells to the central processing facility, and designed, procured, and constructed the CPF Orinoco Sur (the "CPF"), a central processing facility with a nameplate capacity of 35,000 barrels per day ("bbl/day"). The CPF included oil treatment facilities, produced water handling, gas compression and flaring systems, tank farms, utilities infrastructure, and associated access roads. The development program was financed in part through the Commonwealth Capital Bank project finance facility described in Section II.E below and in part through DEH equity contributions.
Production Phase (2019–2021). DVU commenced commercial production from the Bloque Orinoco Sur in early 2019. The field achieved steady ramp-up over the following months. Key production metrics are summarized below:
•  Peak production: 24,800 bbl/day, achieved in September 2020;
•  Average production FY2020: 21,200 bbl/day;
•  Production at time of expropriation (April 2021): 18,600 bbl/day, reflecting a natural decline from the September 2020 peak.
For the fiscal year ended December 31, 2020 ("FY2020"), DVU reported the following key financial metrics, as reflected in its audited financial statements prepared by Ashworth & Palliser LLP:
•  Gross Revenue: USD 128.6 million;
•  EBITDA: USD 41.3 million;
•  EBITDA Margin: approximately 32.1%.
These figures demonstrate that the Bloque Orinoco Sur was a mature, commercially successful production asset generating substantial revenues and cash flows at the time of the expropriation. The asset had moved well beyond the speculative exploration stage and was an established going concern with a proven track record of profitability.
Reserve Certification. As of December 31, 2020, Ridgewell Subsurface Consultants Ltd. independently certified the following reserves for the Bloque Orinoco Sur:
•  Proved Reserves (1P): 87.4 million barrels of oil equivalent ("mmboe");
•  Probable Reserves (2P incremental): 42.1 mmboe.
These reserve figures, independently certified by a qualified petroleum engineering firm, provide the technical foundation for the production profile assumptions used in the DCF valuation (Component 2) and will serve as a key exhibit in the ICSID proceedings.
II.D. The Expropriation
The expropriation of DEH's investment in Valderia occurred through a series of escalating governmental actions over the period from January 2020 to September 2021, culminating in the total deprivation of DEH's investment without any compensation. The following timeline summarizes the key events:
January 15, 2020 — Presidential Inauguration. President Héctor Luján Montalvo was inaugurated as President of the Republic of Valderia. President Montalvo's election platform included a "resource sovereignty" agenda calling for the reassertion of state control over Valderia's strategic natural resources, particularly hydrocarbon assets held by foreign investors. The inauguration marked a significant shift in political orientation toward increased state intervention in the energy sector.
March 2, 2021 — Notice of Review. The Ministry of Energy and Natural Resources of the Republic of Valderia issued a formal "Notice of Review" (Notificación de Revisión) to all foreign-held hydrocarbon concessions operating in Valderia. The Notice of Review stated that the Ministry would undertake a comprehensive review of the terms and conditions of all foreign-held concessions to assess their compliance with "national interest requirements." DVU received the Notice of Review on March 4, 2021 at its registered offices in Puerto Valdés. The Notice of Review did not specify the scope or timeline of the review, nor did it provide any opportunity for the affected concessionaires to participate in the review process.
April 17, 2021 — Presidential Decree No. 2021-0417. President Montalvo issued Presidential Decree No. 2021-0417 (Decreto Presidencial de Nacionalización de Activos Estratégicos de Hidrocarburos), ordering the nationalization of all strategic hydrocarbon assets in the Republic of Valderia. The Decree declared that all hydrocarbon concessions held by foreign entities were "of strategic national interest" and ordered their immediate transfer to PetroValderia S.A. The Decree did not provide for any compensation to the affected concessionaires, nor did it establish any mechanism for the assessment or payment of compensation. This date — April 17, 2021 — is the primary valuation date for the purposes of the quantum claim.
May 3, 2021 — Physical Occupation. Units of the Valderian military, accompanied by personnel from PetroValderia, physically occupied the CPF Orinoco Sur and all associated field installations within the Bloque Orinoco Sur Concession Area. DVU's expatriate and local staff were denied access to the facility, and all operations were placed under the direct control of PetroValderia. DEH's field management team, led by DVU's General Manager, was given less than four hours to vacate the premises and was not permitted to remove any equipment, records, or personal effects of a material nature.
June 23, 2021 — Presidential Decree No. 2021-0623. President Montalvo issued a second decree, Presidential Decree No. 2021-0623, formally transferring Concession No. HYD-2012-047 from DVU to PetroValderia S.A. in its entirety. The Decree purported to vest in PetroValderia all rights, titles, interests, and obligations arising under the Concession, retroactive to the date of the nationalization decree.
August 5, 2021 — Ministerial Resolution No. MEN-2021-089. The Ministry of Energy and Natural Resources issued Ministerial Resolution No. MEN-2021-089, formally revoking all operating licenses held by DVU in the Republic of Valderia, including its hydrocarbon operating license, environmental operating permit, and pipeline operating license. The Resolution was issued without any prior notice to DVU and without any offer of compensation.
September 1, 2021 — Freezing of DVU Bank Accounts. By order of the Attorney General of the Republic of Valderia, Dr. Renata Villamizar Ochoa, all bank accounts held by DVU at Banco Nacional de Valderia were frozen. DVU was unable to access any funds held in its Valderian accounts, including receivables from pre-expropriation production sales.
At no stage during this sequence of events did the Republic of Valderia offer or pay any compensation to DEH, DVU, or their shareholders. The cumulative effect of these actions was the total and irrevocable deprivation of DEH's investment in the Republic of Valderia.
At the date of expropriation, the remaining term of the Concession was approximately 22.4 years (calculated from April 17, 2021 to the scheduled expiry on September 12, 2043). For purposes of the DCF analysis, this remaining term has been rounded to 23 years, which provides a conservative basis for the projection period.
II.E. Project Finance Facility
DEH's development of the Bloque Orinoco Sur was financed in part through a senior secured project finance facility provided by Commonwealth Capital Bank plc ("CCB"). The key terms of the facility are summarized below:
The facility was secured by a first-priority lien on all of DVU's assets (including the Concession, the CPF, the pipeline, all production equipment, and all associated receivables), a parent guarantee from DEH, and an assignment of DVU's concession receivables. The security package was designed to provide CCB with comprehensive recourse to DVU's assets and cash flows, as well as recourse to DEH at the parent level.
Following the expropriation, CCB declared a technical default on November 1, 2021, citing Event of Default under Section 9.1(k) of the Facility Agreement, which covers expropriation, nationalization, or similar seizure of all or a material portion of the collateral securing the facility. DEH and CCB subsequently entered into a standstill agreement on December 22, 2021, pursuant to which CCB agreed to forbear from exercising its acceleration and enforcement rights for a defined period, subject to periodic extensions. The current standstill agreement has been extended multiple times and is presently scheduled to expire on March 31, 2025.
The standstill arrangement, while providing short-term relief, has imposed significant ongoing costs on DEH, including amendment and waiver fees, legal advisory costs, and the accrual of default-rate interest. Moreover, the existence of the technical default has materially impaired DEH's creditworthiness and its ability to access financing for other projects, a matter which forms part of the consequential damages claim discussed in Section VI below.
III. LEGAL STANDARD FOR COMPENSATION
III.A. Article 5 of the UK-Valderia BIT (2006)
The applicable legal framework for the assessment of compensation in this case is Article 5 of the Agreement Between the Government of the United Kingdom of Great Britain and Northern Ireland and the Government of the Republic of Valderia for the Promotion and Protection of Investments, signed on May 22, 2006, and entered into force on November 1, 2006 (the "UK-Valderia BIT" or the "BIT"). The BIT provides the jurisdictional basis for DEH's claim before ICSID, as DEH qualifies as an investor of the United Kingdom for the purposes of the BIT by virtue of its being a company incorporated in the Cayman Islands, a British Overseas Territory, and maintaining its principal place of business in London.
Article 5 of the BIT provides, in relevant part, that neither Contracting Party shall expropriate or nationalize investments of nationals or companies of the other Contracting Party except for a public purpose related to the internal needs of that Party, on a non-discriminatory basis, in accordance with due process of law, and against "prompt, adequate, and effective compensation." The BIT further provides that such compensation shall amount to the "fair market value" of the investment expropriated, determined as of the date immediately preceding the expropriation or the date on which the impending expropriation became public knowledge, whichever is earlier.
The relevant date analysis in this case presents two potential valuation dates:
(a) March 2, 2021: the date of the Ministry of Energy's Notice of Review, which arguably put the market on notice of the impending expropriation; or
(b) April 17, 2021: the date of Presidential Decree No. 2021-0417, which formally ordered the nationalization.
The determination of the appropriate valuation date is a matter to be resolved by the tribunal. For the purposes of this memorandum, and consistent with the advice of the C&H litigation team, the primary valuation date is taken to be April 17, 2021, which represents the date of the formal expropriation. However, to the extent that the tribunal determines that the market was aware of the impending expropriation at an earlier date, it may select March 2, 2021 as the valuation date. In practice, the difference between these two dates is unlikely to have a material impact on the quantum, as there were no significant changes in commodity prices, production volumes, or reserve estimates between the two dates.
III.B. Applicable Jurisprudence on Quantum
The quantum of compensation for the expropriation of an investment under international law is governed by well-established principles. The foundational principle is the Chorzów Factory standard (PCIJ, Series A, No. 17, 1928), which holds that the obligation to provide reparation requires the State responsible for an internationally wrongful act to place the injured party in the position in which it would have been "but for" the unlawful act. This principle of full reparation has been consistently applied by ICSID tribunals and other international arbitral bodies.
In the context of the expropriation of a going concern — that is, an investment that is operational, generating revenue, and has an established production and financial track record — ICSID tribunals have consistently endorsed the discounted cash flow ("DCF") methodology as the primary approach for determining fair market value. The DCF methodology is appropriate where the investment has moved beyond the speculative exploration stage and has demonstrable cash flows that can be projected with reasonable certainty. In the present case, DVU's status as a producing asset with FY2020 gross revenues of USD 128.6 million, an EBITDA of USD 41.3 million, independently certified reserves of 87.4 mmboe (proved), and a remaining concession life of approximately 23 years establishes a strong factual basis for the application of DCF as the primary valuation methodology.
The historical cost approach (also referred to as the "invested capital" or "book value" approach) is recognized as an alternative or complementary methodology, particularly where it provides a minimum or floor value for the investment. ICSID tribunals have recognized that an investor should, at a minimum, be compensated for the capital it invested in reliance on the host State's legal framework, even if the DCF analysis were to yield a lower value (which is not expected in the present case).
Consequential damages are recoverable under international law where they are causally linked to the unlawful act and were reasonably foreseeable at the time of the expropriation. The availability and scope of consequential damages are discussed further in Section VI below.
Pre-award interest is routinely awarded by ICSID tribunals to compensate the investor for the time value of money between the date of expropriation and the date of the award. Compound interest is the standard in cases of unlawful expropriation, reflecting the investor's actual cost of capital and the economic reality of the loss.
III.C. Distinction Between Lawful and Unlawful Expropriation
The distinction between lawful and unlawful expropriation is material to the quantum analysis. Under international law:
(a) A lawful expropriation — one that is undertaken for a genuine public purpose, on a non-discriminatory basis, in accordance with due process, and accompanied by prompt, adequate, and effective compensation — gives rise to an obligation to pay fair market value. In such cases, the quantum is typically limited to the fair market value of the investment on the date of expropriation.
(b) An unlawful expropriation — one that fails to satisfy any of the foregoing conditions — gives rise to the broader obligation of full reparation under customary international law (the Chorzów Factory standard). Under this standard, the quantum of damages may exceed the fair market value of the investment to include consequential losses, such as financing costs, reputational harm, and other incidental damages, provided they are causally linked and reasonably foreseeable.
In the present case, DEH's position is that the expropriation by the Republic of Valderia was unlawful on multiple grounds:
(i) No compensation was offered or paid at any stage, in violation of the "prompt, adequate, and effective compensation" requirement of Article 5 of the BIT;
(ii) The expropriation targeted foreign concessionaires and was therefore discriminatory in nature, as the nationalization decree disproportionately affected foreign-held hydrocarbon concessions while leaving domestically-held concessions intact or subject to different treatment;
(iii) The expropriation lacked procedural safeguards: DVU was given no prior notice, no opportunity to be heard, no access to administrative or judicial review, and no mechanism for the assessment of compensation; and
(iv) The physical occupation of the CPF Orinoco Sur by military forces, with less than four hours' notice and without any legal process, constituted a deprivation effected by force rather than by law.
If the tribunal finds the expropriation to be unlawful, the full reparation standard will apply, which supports the recoverability of the consequential damages claimed in Component 3 (USD 208,000,000), in addition to the fair market value of the investment itself.
IV. COMPONENT 1: SUNK CAPITAL EXPENDITURE — USD 347,000,000
IV.A. Overview
The first component of DEH's claim is the total capital expenditure invested by DEH and DVU in the Bloque Orinoco Sur Concession between 2014 and 2021. The total sunk capital expenditure is USD 347,000,000. This figure represents the aggregate of all exploration, development, and infrastructure capital deployed by the investor in reliance on the legal framework of the Concession, the Hydrocarbons Law, and the BIT.
The sunk capital expenditure serves as a "floor" or minimum damages figure under the invested-capital approach to compensation. The logic of this approach is straightforward: at a bare minimum, an investor whose investment has been expropriated without compensation is entitled to recover the capital it deployed in reliance on the host State's legal commitments. While the DCF methodology (Component 2) is expected to yield a higher total enterprise value for the Concession — reflecting the going-concern premium attributable to DVU's established production, reserves, and remaining concession life — the sunk capital figure provides an important alternative measure of damages and a lower bound on the quantum of the claim.
The USD 347,000,000 in sunk capital expenditure is divided into three sub-components, as described below.
IV.B. Exploration and Development Drilling — USD 211,000,000
The largest sub-component of sunk capital expenditure relates to the costs of exploration and development drilling. The total cost of exploration and development drilling incurred by DVU was USD 211,000,000, covering the following activities:
(a) The drilling of seven (7) exploration wells during the exploration phase (2013–2016), including mobilization and demobilization of drilling rigs, directional drilling services, wireline logging, well testing, and associated services;
(b) The drilling of twenty-two (22) development wells during the development phase (2016–2019), including drilling, completion, and stimulation of all production wells; and
(c) All associated well completion activities, including casing, cementing, perforation, gravel packing, and installation of downhole equipment.
The source documentation supporting this figure includes DVU's capital accounts, detailed invoices from drilling contractors and service providers, drilling contracts, well completion reports, and related technical and financial records. All capital expenditure figures have been audited by Ashworth & Palliser LLP, DEH's corporate auditors, based at 20 Moorgate, London EC2R 6DA, and are reflected in DVU's audited financial statements for the relevant fiscal years.
IV.C. Surface Infrastructure and Pipeline Construction — USD 89,000,000
The second sub-component of sunk capital expenditure relates to the costs of surface infrastructure and pipeline construction. The total cost incurred was USD 89,000,000, covering the following:
(a) Design, procurement, and construction of the CPF Orinoco Sur (the central processing facility), with a nameplate capacity of 35,000 bbl/day, including oil treatment facilities, produced water handling systems, gas compression units, flaring systems, control rooms, and ancillary structures;
(b) Construction of the 68-kilometer gathering pipeline connecting the production wellheads to the CPF;
(c) Construction of tank farms for crude oil storage;
(d) Installation of utilities infrastructure, including power generation, water supply, and telecommunications; and
(e) Construction of access roads and related civil works within the Concession Area.
The source documentation supporting this figure includes engineering, procurement, and construction ("EPC") contracts, progress payment certificates, commissioning records, and as-built documentation. As with the drilling costs, all surface infrastructure capital expenditure has been audited by Ashworth & Palliser LLP and is reflected in DVU's audited financial statements.
IV.D. Seismic Acquisition and Geological Studies — USD 47,000,000
The third sub-component of sunk capital expenditure relates to the costs of seismic data acquisition and geological studies. The total cost incurred was USD 47,000,000, covering the following:
(a) Acquisition of a comprehensive 3D seismic survey over approximately 800 km² of the Concession Area, including data acquisition, processing, and interpretation;
(b) Geological and geophysical interpretation studies, including structural mapping, stratigraphic analysis, and prospect identification; and
(c) Reservoir modeling and simulation studies used to support development planning and reserve certification.
The source documentation includes seismic acquisition contracts, data processing agreements, geological and geophysical interpretation reports, and the Ridgewell reserve reports. All costs have been audited by Ashworth & Palliser LLP.
IV.E. Adjustments and Methodology Notes
The historical cost figures set forth above are drawn from DVU's audited financial statements as prepared by Ashworth & Palliser LLP. The following methodological notes apply:
(a) Depreciation adjustment. The gross capital expenditure figures of USD 347,000,000 represent the unadjusted historical cost of the investment. Under the historical cost approach, these figures may be adjusted for depreciation to the valuation date in order to reflect the book value of the assets at the time of expropriation. The depreciation schedule — including the applicable depreciation method, useful lives, and residual values — is to be finalized in coordination with Pemberton Valuation Advisory as part of the formal expert damages report.
(b) Alternative: unadjusted (gross) basis. An alternative presentation of the sunk capital expenditure claim is on an unadjusted (gross) basis, representing the investor's total out-of-pocket expenditure without reduction for depreciation. This approach reflects the full magnitude of the capital deployed by DEH in reliance on the host State's legal commitments and is appropriate as a measure of the investor's actual economic loss. The choice between the adjusted and unadjusted approaches is to be discussed with Dr. Elaine Cho of Pemberton and will depend in part on how Component 1 interacts with Component 2 (the DCF).
Arithmetic check: USD 211,000,000 + USD 89,000,000 + USD 47,000,000 = USD 347,000,000.
V. COMPONENT 2: LOST FUTURE PROFITS (DISCOUNTED CASH FLOW) — USD 312,000,000
V.A. Overview and Methodology Selection
The second and principal component of DEH's claim is the value of the lost future profits from the Bloque Orinoco Sur Concession, quantified using the discounted cash flow ("DCF") methodology. The DCF is the primary valuation methodology for determining the fair market value of a going concern with an established production history, independently certified reserves, and a defined remaining concession life.
The selection of DCF as the primary methodology is appropriate in the present case for the following reasons:
(a) DVU had achieved commercial production and was generating substantial revenues (USD 128.6 million gross revenue in FY2020) and operating profits (USD 41.3 million EBITDA, representing a 32.1% EBITDA margin);
(b) The Bloque Orinoco Sur had independently certified reserves of 87.4 mmboe (proved) and 42.1 mmboe (probable), as certified by Ridgewell Subsurface Consultants Ltd. as of December 31, 2020;
(c) The Concession had a substantial remaining term of approximately 23 years (from the valuation date of April 17, 2021 to the scheduled expiry of September 12, 2043), providing a long projection period over which the asset was expected to generate cash flows; and
(d) ICSID tribunals have consistently endorsed the DCF methodology for the valuation of producing hydrocarbon assets with established track records, making it the standard approach in cases of this nature.
The DCF methodology calculates the net present value ("NPV") of the projected future free cash flows from the Concession over the remaining 23-year concession term, discounted to the valuation date at a weighted average cost of capital ("WACC") that reflects the specific risks associated with the project, the country, and the sector. The resulting NPV represents the price that a willing buyer would pay a willing seller for the Concession in an arm's-length transaction, with both parties having reasonable knowledge of the relevant facts — the standard definition of fair market value.
V.B. Key Assumptions
The DCF model is built on a series of key assumptions relating to the production profile, commodity prices, operating costs, fiscal terms, and discount rate. Each of these assumptions is described below. It is emphasized that these assumptions are preliminary and are subject to refinement by Pemberton Valuation Advisory upon completion of the full expert model.
V.B.1. Production Profile
The production profile for the DCF model is derived from the following inputs:
(a) Starting production rate: 18,600 bbl/day, being the actual production rate at the Bloque Orinoco Sur at the time of expropriation in April 2021. This rate reflects the natural decline from the peak production of 24,800 bbl/day achieved in September 2020 and the average FY2020 production of 21,200 bbl/day.
(b) Decline curve analysis: The production profile over the remaining 23-year concession term is to be modeled using decline curve analysis, a standard petroleum engineering technique that projects future production based on the observed historical production decline and the physical characteristics of the reservoir. The decline curve analysis will be prepared by Dr. Alistair Greaves of Ridgewell Subsurface Consultants Ltd. based on available reservoir engineering data, well performance history, and reservoir simulation models.
(c) Proved reserves: The proved reserves of 87.4 mmboe, as independently certified by Ridgewell as of December 31, 2020, form the primary basis for the production profile in the base case DCF model. The production profile will be calibrated to ensure consistency with the total proved reserves remaining to be produced over the concession life.
(d) Probable reserves: The probable reserves of 42.1 mmboe will be addressed in a sensitivity analysis (Upside scenario) rather than in the base case. The inclusion of probable reserves would increase the projected production volumes and, consequently, the DCF value. However, for the purposes of presenting a conservative base case, the primary production profile will be based on proved reserves only.
(e) upside potential: The CPF Orinoco Sur had a nameplate processing capacity of 35,000 bbl/day, which significantly exceeded the production rate at the time of expropriation (18,600 bbl/day) and the peak production rate (24,800 bbl/day). This spare capacity represented significant upside potential had Phase II development drilling proceeded as planned. While this upside is not incorporated into the base case DCF, it will be noted in the expert report as evidence of the asset's unrealized value.
V.B.2. Commodity Price Assumption
The commodity price is a critical input to the DCF model, as it determines the revenue stream from oil production. The following price assumptions will be used:
(a) Base case: Brent crude price of USD 65 per barrel ("/bbl"), reflecting the long-term consensus forecast as of the valuation date of April 17, 2021. This assumption is intended to represent a reasonable, forward-looking estimate of the average realized price over the remaining concession life, taking into account the cyclical nature of oil prices and the long-term fundamentals of global oil supply and demand.
(b) Sensitivity analysis — Low case: Brent crude price of USD 55/bbl, representing a downside scenario in which sustained low demand growth, increased supply from non-OPEC producers, or a prolonged economic downturn depresses oil prices below the consensus forecast.
(c) Sensitivity analysis — High case: Brent crude price of USD 75/bbl, representing an upside scenario in which supply constraints, accelerated demand recovery, or geopolitical supply disruptions support prices above the consensus forecast.
All price assumptions will be benchmarked against third-party commodity price forecasts and forward price curves prevailing at the valuation date, including those published by the U.S. Energy Information Administration, the International Energy Agency, and major investment banks. The basis for the selected price assumptions will be fully documented and supported in Pemberton's expert report.
V.B.3. Operating Costs and Royalties
The operating cost assumptions for the DCF model will be derived from DVU's historical cost structure, as reflected in its audited financial statements:
(a) Operating expenditure ("opex") per barrel: To be derived from DVU's historical operating cost data, including direct lifting costs, field operating expenses, maintenance costs, transportation costs, and general and administrative expenses attributable to the Concession. The per-barrel opex figure will be estimated based on FY2020 actual costs and adjusted for anticipated inflation and changes in the production profile over the concession life.
(b) Royalty: 12.5% of gross production value, payable to the Valderian Treasury in accordance with the Concession terms and the Hydrocarbons Law of 2009.
(c) Valderian corporate income tax: 34%, applicable to DVU's taxable income derived from the Concession.
(d) PetroValderia carried interest: The 10% carried interest held by PetroValderia S.A. will be reflected in the cash flow modeling as an economic burden on the Concession. PetroValderia's carried interest entitles it to receive 10% of production revenues (or, depending on the interpretation of the Concession terms, 10% of net cash flows) without contributing to capital or operating costs. The precise treatment of the carried interest in the DCF model will be determined in consultation with Pemberton.
V.B.4. Discount Rate (WACC)
The projected future free cash flows will be discounted to the valuation date at a weighted average cost of capital ("WACC") of 10%. The WACC is intended to reflect the total risk associated with the projected cash flows, including:
(a) The risk-free rate, based on the yield on long-term U.S. Treasury bonds as of the valuation date;
(b) An equity risk premium, reflecting the additional return required by equity investors over the risk-free rate for investing in equity securities generally;
(c) A country risk premium specific to the Republic of Valderia, reflecting the political, regulatory, macroeconomic, and institutional risks associated with investing in Valderia;
(d) A small-company premium, reflecting the additional risk associated with investing in a company of DEH's size and characteristics; and
(e) An oil and gas sector beta, reflecting the systematic risk of investing in upstream oil and gas assets relative to the broader market.
The 10% WACC is a preliminary estimate and will be supported by a detailed build-up methodology in Pemberton's expert report. The WACC build-up will reference established data sources, including Westmark Consulting Group (Sundial Advisors) cost of capital data, Damodaran country risk premium estimates, and comparable company beta analysis. The 10% WACC incorporates a Valderia-specific country risk premium to reflect the heightened political and regulatory risks of operating in Valderia, which have been dramatically underscored by the expropriation itself. It is noted, however, that ICSID tribunals have generally held that the country risk premium should reflect the risks that existed before the expropriatory measures, not the additional risk created by the expropriation — a point that will require careful treatment in the expert report.
V.B.5. Terminal Value
No terminal value is assumed beyond the expiry date of the Concession on September 12, 2043. All cash flows are projected to terminate at the end of the concession term, and no residual or salvage value is attributed to the assets at that date. Instead, decommissioning and abandonment costs will be deducted from the projected cash flows in the final years of the concession term, reflecting DVU's obligation (which would have remained in effect had the Concession not been expropriated) to decommission the production wells, dismantle the CPF and pipeline infrastructure, remediate the Concession Area, and restore it to its pre-operational condition.
The absence of a terminal value beyond the concession expiry is a conservative assumption that limits the DCF to the economic value of the remaining concession life, without attributing any value to potential concession renewals, extensions, or alternative uses of the assets.
V.C. DCF Computation Summary
Based on the key assumptions set forth above, the DCF computation produces the following result:
•  Projection period: 23 years (April 17, 2021 to September 12, 2043)
•  Projected cash flows: Net free cash flows after royalties (12.5%), operating expenditures, capital maintenance expenditures, Valderian corporate income tax (34%), and PetroValderia's 10% carried interest
•  discount rate: 10% WACC
•  Net present value (NPV): USD 312,000,000
This figure represents the estimated fair market value of the Concession as a going concern on the valuation date, based on the projected stream of future free cash flows discounted to present value. It is the price that a willing buyer, with full knowledge of the asset's reserves, production profile, cost structure, and remaining concession term, would have been expected to pay for the Concession in an arm's-length transaction on the valuation date.
It is emphasized that this figure is preliminary and is subject to refinement by Pemberton Valuation Advisory upon completion of the full expert valuation model. Key areas of potential refinement include the precise shape of the production decline curve (to be confirmed by Ridgewell), the per-barrel operating cost estimates (to be derived from a detailed review of DVU's historical cost data), the commodity price assumptions (to be benchmarked against third-party forecasts prevailing at the valuation date), and the WACC (to be supported by a fully documented build-up methodology).
A sensitivity table will be included in Pemberton's final expert report, showing the quantum of the DCF under different combinations of commodity price, production profile, and WACC assumptions. This table will allow the tribunal to assess the robustness of the valuation across a range of plausible scenarios.
V.D. Cross-Check: Comparable Transactions
In addition to the DCF as the primary valuation methodology, Pemberton will perform a cross-check of the DCF result using comparable upstream oil and gas transactions in the Caribbean basin and Latin America. This cross-check is a standard component of a damages expert report and serves to validate the reasonableness of the DCF result by reference to actual market data.
The comparable transactions analysis will focus on the following valuation metrics:
(a) USD per proved barrel — the implied transaction price per barrel of proved reserves;
(b) USD per flowing barrel — the implied transaction price per barrel of daily production; and
(c) EV/EBITDA multiples — the ratio of enterprise value to EBITDA for comparable transactions.
Preliminary indications from a review of publicly available transaction data suggest that comparable upstream transactions in the region support a valuation range that is broadly consistent with the USD 312,000,000 DCF figure. This cross-check analysis will be fully developed and documented in Pemberton's expert report, with detailed comparisons to specific transactions, adjustments for differences in asset quality, country risk, fiscal terms, and other relevant factors, and a statistical analysis of the resulting valuation range.
V.E. Role of Ridgewell Subsurface Consultants Ltd.
Ridgewell Subsurface Consultants Ltd. has been retained to provide an independent petroleum engineering opinion in support of the quantum claim. The lead expert is Dr. Alistair Greaves, P.Eng., based at Ridgewell's offices at 700 – 6th Avenue SW, Suite 1400, Calgary, AB T2P 0T8, Canada. Dr. Greaves is a registered professional engineer with extensive experience in upstream oil and gas reserve certification and production forecasting.
Ridgewell's scope of work includes the following:
(a) Reserves classification and quantum: Confirmation and, if necessary, updating of the independent reserve certification as of December 31, 2020 (87.4 mmboe proved reserves; 42.1 mmboe probable reserves), which serves as the foundational technical input to the DCF model;
(b) Production decline curve analysis: Preparation of a decline curve analysis for the Bloque Orinoco Sur based on available well performance data, reservoir engineering parameters, and reservoir simulation models, to project the expected production profile over the remaining concession term;
(c) Remaining development potential: Assessment of the remaining development potential of the Concession Area, including the potential for additional development drilling, infill drilling, enhanced oil recovery, and Phase II development (to the extent relevant for sensitivity analysis); and
(d) Technical basis for production assumptions: Provision of the technical basis and supporting analysis for the production assumptions used by Pemberton in constructing the DCF model.
Ridgewell's December 31, 2020 independent reserve certification will be submitted as a foundational exhibit in the ICSID proceedings. Dr. Greaves may be called upon to provide oral and written testimony before the ICSID tribunal in support of the reserve and production assumptions underlying the quantum claim.
VI. COMPONENT 3: CONSEQUENTIAL DAMAGES — USD 208,000,000
VI.A. Overview
The third component of DEH's claim comprises consequential damages arising from losses that are causally connected to the expropriation but fall outside the direct fair market value of the Concession. Total consequential damages claimed are USD 208,000,000.
Consequential damages are recoverable under the full reparation standard applicable to unlawful expropriations. As discussed in Section III.C above, DEH's position is that the expropriation was unlawful on multiple grounds, including the failure to offer or pay any compensation, the discriminatory targeting of foreign concessionaires, the absence of procedural safeguards, and the use of military force. Under the Chorzów Factory principle, the tribunal has the power to award damages that go beyond the fair market value of the investment to compensate the investor for all losses causally linked to the unlawful act, provided those losses were reasonably foreseeable.
The consequential damages claim of USD 208,000,000 comprises three sub-components:
(a) Financing Costs: USD 87,000,000
(b) Reputational Harm: USD 74,000,000
(c) Sunk Phase II Renewable Energy Pre-Development Expenditure: USD 47,000,000
Arithmetic check: USD 87,000,000 + USD 74,000,000 + USD 47,000,000 = USD 208,000,000.
The recoverability of these consequential damages is predicated on the tribunal's finding that the expropriation was unlawful, thereby triggering the full reparation standard. If the tribunal were to find the expropriation to be lawful (a finding we do not anticipate), the consequential damages component might not be recoverable in its entirety, and the claim would be limited to the fair market value of the investment.
VI.B. Financing Costs — USD 87,000,000
The first sub-component of consequential damages relates to the financing costs incurred and to be incurred by DEH as a direct result of the expropriation and the consequent default under the CCB project finance facility.
As described in Section II.E above, DVU was the borrower under a USD 175,000,000 senior secured project finance facility provided by Commonwealth Capital Bank plc, with DEH serving as guarantor. At the time of the expropriation, the outstanding principal under the facility was USD 112,400,000. The facility bore interest at SOFR + 4.25% per annum and was scheduled to mature on March 20, 2026. Following the expropriation of the collateral securing the facility, CCB declared a technical default on November 1, 2021, and the parties entered into a standstill agreement on December 22, 2021, which has been periodically extended and currently expires on March 31, 2025.
The USD 87,000,000 financing cost claim comprises the following elements:
(a) Accelerated interest and default penalties: Interest accrued at the default rate (which, under the Facility Agreement, is typically the contracted rate plus 2%, i.e., SOFR + 6.25%) from the date of the technical default, together with any default penalties or late payment charges imposed under the terms of the Facility Agreement.
(b) Cost of maintaining the standstill: Fees and costs incurred by DEH in negotiating, documenting, and maintaining the standstill agreement with CCB, including amendment fees, waiver fees, consent fees, and legal advisory costs incurred in connection with each extension of the standstill.
(c) Increased cost of capital: The existence of the technical default under the CCB facility has materially impaired DEH's creditworthiness and its ability to access financing for other (non-Valderian) operations. DEH has experienced increased borrowing costs, more onerous lending terms, and reduced availability of credit from other financial institutions as a direct consequence of the default. The increased cost of capital is quantifiable as the difference between DEH's pre-expropriation and post-expropriation cost of borrowing, applied to the quantum of financing obtained or sought during the relevant period.
(d) Loss of project-level cash flows: But for the expropriation, DVU would have continued to generate project-level cash flows from the Concession, which would have been available to service the CCB debt. The loss of these cash flows has left DEH exposed to the full liability under the parent guarantee without the corresponding revenue stream to fund debt service. The quantum of this element represents the net cash flow shortfall — the difference between what DEH would have received from DVU and what it must now fund from other sources to service or retire the CCB debt.
DEH remains liable to CCB under the parent guarantee for the full outstanding principal and accrued interest. The expropriation has fundamentally impaired DEH's balance sheet, eroded its equity value, and compromised its financial standing with counterparties and lenders. The financing cost claim will be quantified in detail by Pemberton Valuation Advisory in coordination with DEH's CFO, Thomas Rearden, and DEH's auditors, Ashworth & Palliser LLP.
VI.C. Reputational Harm — USD 74,000,000
The second sub-component of consequential damages relates to the reputational harm suffered by DEH as a result of the high-profile expropriation of its principal producing asset.
DEH has suffered material and quantifiable reputational damage in the global energy investment community as a direct consequence of the expropriation. The evidence supporting this claim includes the following:
(a) Difficulty in raising capital: Following the expropriation, DEH has experienced significant difficulty in raising equity and debt capital for its non-Valderian projects. Potential investors and lenders have cited the Valderian expropriation as a material risk factor, and several capital-raising processes have stalled or failed as a direct consequence.
(b) Loss of partnership and joint venture opportunities: DEH has lost specific partnership and joint venture opportunities that were in negotiation or under discussion at the time of the expropriation. Potential partners have withdrawn from discussions or declined to proceed, citing concerns about DEH's financial stability and the uncertainty surrounding the Valderian claim.
(c) Increased risk premiums: Potential partners and lenders who have remained willing to engage with DEH have demanded significantly increased risk premiums — in the form of higher equity returns, higher interest rates, more onerous security packages, and less favorable commercial terms — reflecting the perceived increased risk of doing business with DEH in light of the Valderian expropriation.
The methodology for quantifying the reputational harm will involve a comparison of DEH's pre-expropriation and post-expropriation cost of capital, as well as an assessment of the economic value of specific lost business opportunities that can be identified and documented. Pemberton will assess the available methodologies for quantifying reputational harm and will identify the supporting evidence required to substantiate the claim.
It is acknowledged that the reputational harm component is the most challenging element of the consequential damages claim to quantify with precision. ICSID tribunals have awarded reputational damages in only a limited number of cases, and the jurisprudence in this area is evolving. The supportability of the USD 74,000,000 reputational damages claim will need to be carefully analyzed, and the evidentiary foundation will need to be robust, including witness statements, documentary evidence of lost opportunities, and, ideally, an independent reputational impact assessment. The vulnerability of this claim component is discussed further in Section X.C below.
VI.D. Sunk Phase II Renewable Energy Pre-Development Expenditure — USD 47,000,000
The third sub-component of consequential damages relates to pre-development expenditure incurred by DEH in connection with a planned Phase II renewable energy component within the Bloque Orinoco Sur Concession Area.
Prior to the expropriation, DEH had commenced pre-development work on a Phase II project that envisaged the construction of a solar and wind generation facility within the Concession Area. The Phase II project was designed to serve a dual purpose: (a) to power the field operations of the Bloque Orinoco Sur, reducing the carbon footprint of the hydrocarbon production operations and lowering operating costs by displacing diesel-fueled power generation; and (b) to export surplus electricity to the Valderian Ostrander & Co. under a power purchase agreement to be negotiated with the Valderian state electricity utility.
DEH invested a total of USD 47,000,000 in Phase II pre-development activities, including:
(a) Feasibility studies: Comprehensive technical and economic feasibility studies for the solar and wind generation facility, including resource assessments (solar irradiance and wind speed data), site selection analyses, and technology evaluations;
(b) Environmental impact assessments: Full environmental and social impact assessments as required under Valderian environmental law, including baseline environmental surveys, ecological assessments, and community consultation programs;
(c) Engineering design: Preliminary and detailed engineering design for the solar and wind facilities, including civil, electrical, mechanical, and structural engineering;
(d) Land-use permits: Acquisition of land-use permits and other regulatory approvals required for the Phase II development within the Concession Area; and
(e) Equipment procurement: Procurement of long-lead-time equipment, including solar panel arrays and wind turbine components, pursuant to supply contracts with international equipment manufacturers.
All Phase II assets, rights, permits, and contracts were swept up in the expropriation decrees and are now in the possession or under the control of the Republic of Valderia. DEH has received no compensation for these assets.
Critically, the Phase II renewable energy expenditure is not captured in the DCF analysis of Component 2, which models only the future free cash flows from hydrocarbon production operations. The Phase II renewable energy project would have generated a separate and independent stream of revenue and cash flows (from electricity sales) that is not reflected in the hydrocarbon DCF. Accordingly, the USD 47,000,000 in sunk Phase II expenditure is claimed separately as a consequential loss, representing a distinct category of damages that would be lost if not claimed independently.
Supporting documentation for the Phase II claim includes project files, feasibility study reports, environmental impact assessment documentation, engineering design packages, land-use permits, equipment procurement contracts, invoices, and payment records. This documentation will be compiled with the assistance of DVU's management team and submitted as exhibits in the ICSID proceedings.
VII. SUMMARY QUANTUM TABLE
The following table presents the total claim quantum of USD 867,000,000, broken down by component and sub-component, with the applicable valuation methodology for each:
Arithmetic verification:
•  Component 1 + Component 2 + Component 3: USD 347,000,000 + USD 312,000,000 + USD 208,000,000 = USD 867,000,000 
•  Consequential damages sub-check: USD 87,000,000 + USD 74,000,000 + USD 47,000,000 = USD 208,000,000 
VIII. INTEREST
In addition to the principal quantum of USD 867,000,000, DEH will claim compound pre-award interest from the date of expropriation (April 17, 2021) to the date of any eventual award by the ICSID tribunal. The purpose of pre-award interest is to compensate the investor for the time value of money — the economic reality that a dollar today is worth more than a dollar tomorrow — and to ensure that the award fully restores the investor to the position it would have occupied but for the expropriation.
The interest rate to be claimed will be based on a commercially reasonable benchmark. Two principal options are under consideration:
(a) SOFR plus a reasonable spread: This approach would use the Secured Overnight Financing Rate (SOFR), or its predecessor LIBOR for the period prior to the SOFR transition, as the base rate, with a spread reflecting DEH's actual cost of capital. The precise spread will be determined in consultation with Pemberton.
(b) The CCB facility rate of SOFR + 4.25%: This approach would use the interest rate under the CCB project finance facility as the benchmark, on the basis that this rate represents the actual cost of capital incurred by DEH in financing the investment that was expropriated. The use of the CCB rate has the advantage of being directly tied to the investment and reflecting the actual economic burden on DEH.
The claim will be for compound interest, which is appropriate under international law and is the standard in ICSID practice for cases involving unlawful expropriation. ICSID tribunals have consistently recognized that compound interest, rather than simple interest, more accurately reflects the economic reality of the investor's loss, as it accounts for the compounding effect of reinvested interest over time. The choice of compounding frequency (annual, semi-annual, or quarterly) will be determined in consultation with Pemberton and will be set out in the interest calculation included in the expert report.
DEH will also claim post-award interest from the date of the award to the date of full payment, at the same rate and on the same compounding basis as the pre-award interest, to ensure that the investor is fully compensated for any delay in payment of the