Orchid Island Capital, Inc.
Annual Report 2024

Plain-text annual report

ORCA ENERGY GROUP INC. Annual Report & Accounts 2024 Orca Energy Group Inc. // Annual Report & Accounts 2024 ORCA ENERGY GROUP INC. Orca Energy Group Inc. ("Orca" or the "Company"), through its subsidiary PanAfrican Energy Tanzania Limited (“PAET”), operates the Songo Songo Production Sharing Agreement (“PSA”) as part of an integrated gas-to-power project in Tanzania. This project, which converts gas to electricity, was the first of its kind not only in Tanzania but also in the broader East Africa region. The project was conceived by the Government of Tanzania ("GoT") after a decade of thorough economic evaluations and extensive contract negotiations. The Company operates a natural gas field that spans an area of approximately 180 square kilometers. This field contains the Songo Songo reservoir, situated on and slightly offshore of Songo Songo Island. The island is about 15 kilometers off the coast and 200 kilometers south of Dar es Salaam, located in the shallow waters of the continental shelf. The license to operate this field is under a PSA with the GoT and the Tanzania Petroleum Development Corporation (“TPDC”). 1 Orca Energy Group Inc. // Annual Report & Accounts 2024 KEY FINANCIALS REVENUE $111.6m (2023: $110.2m) NET INCOME ATTRIBUTABLE TO SHAREHOLDERS $(21.6m) (2023: $7.0m) NET INCOME ATTRIBUTABLE TO SHAREHOLDERS PER SHARE $(1.09) (2023: $0.35) WORKING CAPITAL(1) $21.9m (2023: $67.3m) NET CASH FLOWS FROM OPERATING ACTIVITIES $27.1m (2023: $48.5m) CASH AND CASH EQUIVALENTS $90.1m (2023: $101.6m) GLOSSARY $ US dollar MMcfd Million standard cubic feet per day $m Million US dollar (1) “Working capital” is a non-GAAP financial measure that does not have a standardized meaning under IFRS and may not be comparable to similar financial measures disclosed by other issuers. See “Working Capital” and “Non-GAAP Financial Measures and Ratios” in the 2024 Annual Management’s Discussion & Analysis for information relating to this non-GAAP financial measure, which information is incorporated by reference into this document. 2 Orca Energy Group Inc. // Annual Report & Accounts 2024 CEO STATEMENT The demand for power in Tanzania is growing rapidly, surpassing the country’s current capacity to meet it. Both new and existing infrastructure are under significant strain, highlighting the urgent need for reliable energy solutions. Orca is committed to being a key partner in addressing this challenge and is keen to contribute to Tanzania’s long-term power generation strategy, ensuring sustainable and dependable energy for the nation’s future. The process of securing a license extension for the Songo Songo gas field has come with many challenges and delays. Despite Orca’s proactive efforts to engage with the Government of Tanzania (“GoT”) and the Tanzania Petroleum Development Corporation (“TPDC”), no resolution has been reached on critical commercial terms. This has created significant uncertainty for the Company’s operations and future investments. The lack of clarity surrounding the license extension coupled with the GoT’s decision to enforce the continued production of Protected Gas beyond the agreed contractual terms has hindered our ability to plan and execute long-term development strategies. In April 2023, Orca formally commenced the process for a license extension, attempting on multiple occasions to engage with relevant parties to extend the Songo Songo development license (“License”) in accordance with the Production Sharing Agreement (“PSA”). Despite these efforts, in July 2024, PAET, TPDC, and Pan African Energy Corporation (“PAEM”) failed to reach a commercial resolution on several outstanding gas contracts up for renewal. Contrary to the contracted terms of the Gas Agreement ("GA") and PSA, and in violation of PAEM and PAET's legitimate expectations, the Permanent Secretary of the Minister of Energy of Tanzania and TPDC sought to ensure that Protected Gas (as such term is defined in the PSA) continues to be produced until the end of the License on October 10, 2026, despite the contractual agreement that Protected Gas would end on July 31, 2024. This led Orca, via PAEM and PAET, to issue a notice of dispute against the GoT for breach, alongside notifying a contractual dispute against the GoT and TPDC for breaches of the PSA and GA, for an amount exceeding $1.2 billion. This ongoing uncertainty has had a tangible effect on our planning. On October 30, 2024, PAET was advised by Songas Limited (“Songas”) that the Interim Power Purchase Agreement (“PPA”) between TANESCO and Songas would expire on October 31, 2024, with no clarity on a new agreement. Consequently, Songas shut down the Songas Power Plant at midnight on October 31, 2024. While the shutdown removed a substantial portion of forecasted demand from our sales portfolio, TANESCO subsequently increased its gas demand above the contracted Maximum Daily Quantity (MDQ), partially offsetting the lost volumes. Meanwhile, the commencement of operations at the Julius Nyerere Hydropower Project (“JNHPP”) and an early onset of the wet season and above-average rainfall increased reliance on hydroelectricity. Though this supports the country’s diversification of energy sources, hydropower remains vulnerable to weather variability, limiting its dependability as a consistent source of power. In February 2025, the Tanzanian High Court issued a judgment against PAET relating to a contractual dispute arising from our 3D seismic acquisition program. The Court awarded damages, costs, and interest totaling $23.1 million to the contractor. We have recognized the liability in our 2024 financial statements, in line with the judgment. PAET has commenced the appeal process, and any successful outcome will be reflected in future earnings. We remain committed to protecting the Company’s interests as we navigate this matter. Despite these obstacles, Orca has continued to deliver strong operational results. In 2024, processing plant uptime reached 99.9%, and downstream distribution uptime was 100%. The Company recorded one Lost Time Incident involving a road traffic accident. Overall, health, safety, and environmental (HSE) performance remained strong. One major initiative in 2024 was the planned well intervention at SS-7. Despite extensive work and repeated attempts, only limited and unsustained gas flows were observed. Operations were terminated in December 2024, with demobilization largely complete. The total cost of the project is expected to be $25.9 million, above initial estimates. A comprehensive post-project review is underway to evaluate the results and determine lessons learned. 3 4 Orca Energy Group Inc. // Annual Report & Accounts 2024 Gas deliveries were impacted by several factors, including reduced demand due to hydropower displacement, early rainfall, and the Songas Power Plant shutdown. The unsuccessful SS-7 workover also limited production capacity. Nevertheless, the Company adjusted to changing demand, and TANESCO’s increased offtake partially mitigated the volume loss. The challenging commercial environment also included a major financial settlement with TANESCO. As of January 2025, TANESCO owed approximately $104 million, comprising $34 million in principal and $70 million in interest. To resolve this, PAET proposed a settlement to recover the full arrears and 50% of the interest, payable in full within 2025. TANESCO countered with an offer to pay a total of $52 million across Q2 and Q3 2025. A final agreement was reached, outlining weekly payments and monthly targets. Should TANESCO fail to meet the agreed payment schedule, arbitration will be pursued for the full $104 million, plus costs. As of this statement, TANESCO has commenced instalments under the agreement. Orca remains focused on ensuring compliance with the settlement agreement and maintaining transparent engagement with all stakeholders. During February 2025 PAET, TPDC and TPCPLC agreed to the terms of the Supplementary Gas Agreement (“SGA”) to sell volumes after July 31, 2024 as Additional Gas, which, prior to August 1, 2024, were supplied as Protected Gas. TPCPLC has fully paid the Company $10.4 million of the receivable outstanding as at December 31, 2024. The Company also fully prepaid the $60 million investment made by International Finance Corporation ("IFC") in PAET, pursuant to a loan agreement dated October 29, 2015 between the IFC, PAET and the Company (the "Loan Agreement"). To effect the foregoing prepayment, the Company paid to IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest and all other amounts owing in connection with the Loan as of February 21, 2025. During the year, Orca also faced currency conversion challenges, as 90% of revenues are received in Tanzanian shillings, while most costs are paid in hard currencies (USD, Euro, GBP, CDN). The Company has implemented measures to convert local revenues and manage its balance sheet effectively. Revenues for 2024 were $111.6 million, a 1% increase from 2023, despite reduced production volumes and persistent commercial uncertainties. Orca ended the year with cash and cash equivalents of $90.1 million, maintaining a strong financial position. Given the limited time remaining on the License, and the lack of a resolution on the license extension, the Company has limited its capital spending to only essential safety and maintenance activities. At this late stage of the PSA, further investment is not commercially viable unless the License is extended. It is crucial for the GoT to extend the License to enable future financing, ensuring the continued development of the Songo Songo gas field, effective management of its production decline, and the maintenance of a reliable gas supply for power generation. ​ Without this extension, the decline in Songo Songo gas field production poses a significant risk to gas availability for power generation in Tanzania. In order to preserve shareholder value, Orca has focused on reducing costs, operating efficiently, and minimizing expenditures. While the capital returns policy is subject to ongoing review due to increased commercial uncertainty, the Board of Directors intends to maintain the quarterly dividend and normal course issuer bid. Tanzania remains a fast-growing economy with increasing energy demands. Orca stands ready to invest further in the Songo Songo gas field to mitigate production decline and support national development. However, this investment depends on resolving the License extension and achieving a sustainable commercial framework. Without resolution, the Company must act to protect the interests of its shareholders, even as it continues to support Tanzania’s long-term energy goals. Jay Lyons Chief Executive Officer April 29, 2025 Orca Energy Group Inc. // Annual Report & Accounts 2024 COMPANY OPERATIONS 2024 remained a year of intense operational activity for PAET. The focus was divided between field development to sustain production, and development planning to identify, frame and confirm the feasibility of operational activities in the event PAET was awarded an extension of the License beyond the end of its current term, ending October 10, 2026. Despite the limited time remaining on the current License period, demand from existing and new downstream markets remained positive. UPSTREAM Upstream development operations in 2024 were centered around returning the SS-7 well to production following its suspension in 2019. As the only well situated in the southern compartment of the Songo Songo gas field, re-accessing the reserves was important. Although not necessary to meet contractual obligations to the end of the License, SS-7's production potential was important in meeting emergent downstream demand. Despite considerable interest from the GoT in the project, progression was hampered and the project delayed through the early part of the year due to an enduring regional shortage of US Dollars and scant support in accessing them. This caused nervousness over entering contracts with international service providers. Eventually, but slowly, the Company was able to access sufficient US Dollars and mobilization commenced with suppliers and services drawn from across 12 different nations and around 30 different locations consolidating in Mombasa for the marine construction phase, ostensibly building a workover unit on a modular jack up platform and support barges, prior to towing them to Songo Songo Island for the operational phase. Operations commenced in late Q3 2024 and initially progressed well. However, the failure of the crane saw the project suspended for a period of 18-days while a replacement was sought locally. Following several cement squeezes, and reperforation of the Neocomian sands, limited and unsustained gas flows were observed. A decision was taken to set a cement plug above the Neocomian interval and perforate the shallower Cenomanian sands. Unfortunately, having completed all possible downhole work, and after an unsuccessful attempt to produce gas from the Cenomanian sands, well intervention operations were terminated and all equipment demobilized from the SS-7 site by the end of the year. Currently, the well remains suspended. Wider operational effort focused around the results of a significant sub-surface review that updated static and dynamic models, leading to revised production forecasting. This followed the collection of data from downhole gauges, as well as production logging in wells SS-3, SS-5 and SS-10. In parallel, a number of major maintenance operations commenced, including the overhaul of wellheads, a major upgrade to the plant Computerized Maintenance Management System, and preparations for the replacement of two offshore flowlines and for the installation of well head pressure equalization lines to ensure faster plant re-starts in the event of upset conditions and a shut-down. Longer term field development planning also continued, in support of PAET’s request for an application to extend the License made in early 2023. A number of options to increase recovery of proven reserves and evaluate contingent and prospective resources were examined, as well as the sequencing of options to identify the quickest and most economical approach to fully exploit field production potential. Several options indicated considerable potential but are now on hold in anticipation of progressing the License extension negotiations in 2025. 5 Orca Energy Group Inc. // Annual Report & Accounts 2024 DOWNSTREAM AND MARKETING As the Company approached the end of the current period of the License, downstream operations necessitated a careful balance between maintaining reliable infrastructure to sustain existing demand and limited investment to meet emergent demand where it could be met. Development decisions were made increasingly difficult by the GoT's claims that the obligation to supply up to 45 MMcfd of Protected Gas to Songas and the Wazo Hill cement factory, that was to end on July 31, 2024, was now to continue indefinitely. The Company was steadfast in its position that Protected Gas ended, however the prospect of the GoT enforcing its incorrect assertion, while also managing declining field production potential, hampered our ability to confidently place new sales contracts. New demand exceeded 10 Mmcfd, but the constraints we faced meant only a limited number of customers could be added, primarily in the burgeoning Compressed Natural Gas ("CNG") sector, seeing average CNG sales increase by more than 30% over 2023 sales figures. Overall, production through the year was however below budgeted forecasts for the reasons described earlier. Consequently, average daily production through the year, not including fuel and flare gas, was 92.0 MMcfd, with annual cumulative production totaling 33.7 Bcf. Despite the uncertainties surrounding the extension of the License and PSA, and despite the continued expansion of hydro power generation in Tanzania, demand for gas from the Songo Songo gas field continues to exceed existing supply potential. 6 Orca Energy Group Inc. // Annual Report & Accounts 2024 GAS RESERVES 2024 INDEPENDENT EVALUATION The Company’s natural gas reserves as at December 31, 2024 for the period to the end of the License on October 10, 2026 were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The 2024 independent reserves evaluation prepared by McDaniel (the "McDaniel Report") is dated February 18, 2025 with the effective date of December 31, 2024. On a gross Company basis there has been a 53% decrease in proven ("1P") reserves, and a 56% decrease in the total proved plus probable ("2P") reserves compared to 2023. Total Additional Gas production in 2024 was 26.7 Bcf. The reduction in gross Company 1P reserves from year end 2023 to year end 2024 was primarily attributed to 2024 production of 26.7 Bcf and negative technical revisions of 18.1 Bcf. The technical revisions were primarily due to the lower forecasted gas sales to the end of the License (October 10, 2026) attributed to increased hydro power in Tanzania and the removal of Proved Undeveloped reserves due to the unsuccessful well intervention on SS-7. There has been a 45% decrease in the 2P net present value at a 10% discount basis from $118.7 million to $64.7 million compared to 2023. The decrease is predominantly a consequence of production in 2024 and lower 2P reserves to the end of the License. All the Company’s reserves are conventional natural gas reserves and are located in Tanzania. Additional reserves information required under NI 51-101 are included in Orca’s reports relating to reserves data and other oil and gas information under NI 51-101, which have been filed on its profile on SEDAR+ at www.sedarplus.ca and can also be found on our website www.orcaenergygroup.com. The Reserves Committee of the Board of Directors has reviewed the qualifications and appointment of the independent reserves evaluator and the procedures for providing information to the evaluators. Gross1 Net2 Gross Net Independent reserves evaluation Proved producing 40.2 28.0 69.1 42.2 Proved developed non-producing - - - - Proved undeveloped - - 15.9 10.5 Total proved (1P) 40.2 28.0 85.0 52.7 Probable 1.2 0.8 8.9 5.1 Total proved and probable (2P) 41.5 28.8 93.9 57.8 1. Gross equals the gross reserves that are available for the Company based on its effective ownership interest. 2. Net equals the economic allocation of the gross reserves to the Company as determined in accordance with the PSA. Company share of Net Present Value ($’millions) 5% 10% 15% 5% 10% 15% Proved producing 64.5 61.8 59.4 102.4 95.7 89.8 Proved developed non-producing - - - - - - Proved undeveloped - - - 13.8 12.8 11.8 Total proved (1P) 64.5 61.8 59.4 116.2 108.4 101.6 Probable 3.0 2.9 2.8 10.9 10.3 9.6 Total proved and probable (2P) 67.6 64.7 62.1 127.1 118.7 111.2 Company Conventional Natural Gas Reserves (Bcf) 2024 2023 2024 2023 7 Orca Energy Group Inc. // Annual Report & Accounts 2024 BACKGROUND TO THE 2024 YEAR END RESERVES EVALUATION The Company continued the review of the Songo Songo reservoir simulation modeling and well performance in 2024 to better understand the remaining potential of the Songo Songo gas field to the end of the License and assess the remaining resource potential beyond October 2026. The 2024 studies included a cased hole production logging campaign, in addition to annual downhole pressure data acquisition and multi-rate well testing. The 2024 cased hole production logging and well performance history matching confirmed the multi- compartment reservoir modelling developed in 2022/23. The remaining reserves to the end of the current License (October 2026) are primarily driven by gas market demand and continued declining gas deliverability from the current producing well stock. As expected, proved and proved plus probable reserves at year end 2024 continue to converge due to uncertainties associated with a potential extension of the License. With less than two years remaining on the current License, future development capital is zero (other than capital for essential safety and maintenance) in all cases as the current License is no longer investible. 1 2026 is a partial year expiring on October 10, 2026 1P Weighted Average Gas Price $/mcf 1P Gross Gas Volumes MMcfd 2P Weighted Average Gas Price $/mcf 2P Gross Gas Volumes MMcfd 2025 5.15 62.17 5.20 64.03 20261 5.25 61.80 5.32 63.72 Forecast Gas Prices and Sales Volumes 8 Orca Energy Group Inc. // Annual Report & Accounts 2024 STAKEHOLDERS Our commitment to transparency and open communication is the foundation of our stakeholder engagement strategy. We aim to build strong relationships with all our stakeholders, including employees, customers, investors, partners, suppliers, and the communities we serve. INVESTORS We prioritize transparency and engagement with our investors, keeping them informed and involved in our strategic direction and operational plans through regular reports, press releases, and discussions. We value our shareholders’ support and address their concerns promptly. Our long-term goal is to maximize the social and economic potential of our assets in Tanzania sustainably. EMPLOYEES Our employees are our greatest asset. We are dedicated to inspiring, safeguarding, and nurturing our workforce, recognizing their growth and satisfaction as key to our success. Our commitment to employees includes: Employee Engagement: Fostering a work environment that encourages active participation, open communication, and a strong sense of community. Safe Work Environments: Ensuring the highest safety standards in the workplace. Training and Development: Investing in continuous learning and career development programs. Tanzania First: Prioritizing the hiring and development of local talent to contribute to Tanzania’s economic growth. Employee Health and Wellbeing: Supporting employees’ physical and mental health through various programs and resources. Inclusive Work Culture: Celebrating diversity and creating an inclusive culture where everyone feels valued and respected. We maintain transparency about our business strategies, involve employees in decision-making, and foster open dialogue for continuous improvement. CONTRACTORS We recognize the crucial role our contractors play and try to ensure that they align with our Company’s values, especially regarding health and safety practices. We continually refine our practices to better serve our employees and create a productive and enriching workplace. We are proud of the culture we have built at Orca Energy Group and look forward to nurturing it further. CUSTOMERS Transparency is a core value in all our customer interactions. We maintain open communication, fostering trust and mutual understanding. This helps us better understand and meet our customers’ needs. We work hard to provide a stable supply of natural gas at fair and competitive prices, contributing to broader energy market stability. LOCAL COMMUNITY We strive to create shared value that positively impacts the well-being of the communities we serve. Our operations provide employment opportunities and contribute to local economic growth. Additionally, by improving access to energy, we enhance educational opportunities and health outcomes. This holistic approach to community engagement is central to our commitment to creating shared value. 9 Orca Energy Group Inc. // Annual Report & Accounts 2024 GOVERNMENT & REGULATORS We proactively engage with Tanzanian regulators, fostering strong relationships with government entities and regulatory bodies. These interactions ensure our operations align with local development plans. By working closely with the government, we understand their vision and tailor our activities to support these goals. Open communication helps us stay ahead of regulatory changes and adapt our operations accordingly. We are committed to strengthening these relationships to contribute to Tanzania’s development. PARTNERS We recognize the importance of developing relationships with our local partners, including Songas and TPDC. These collaborations address various challenges and opportunities, ensuring the continued production of high- quality, stable natural gas. Strong partnerships are key to our success and the ongoing stability of our operations. THE ENVIRONMENT As a natural gas operator, we emit greenhouse gases (GHG). We are committed to mitigating our environmental impact on both land and marine ecosystems. We aim to reduce the emissions intensity of our operations and support Tanzania’s transition to a lower-carbon economy. Transparent engagement with regulators and stakeholders about our environmental impact is central to our commitment to sustainability. 10 Orca Energy Group Inc. // Annual Report & Accounts 2024 BOARD OF DIRECTORS 11 Orca Energy Group Inc. // Annual Report & Accounts 2024 HOW WE MANAGE OUR COMPANY THE BOARD • Provides independent oversight to ensure business integrity • Sets the strategic direction for the Company • Monitors the Company's risk management framework EXECUTIVE MANAGEMENT • Manages core operations at the Songo Songo gas field • Delivers value to all stakeholders • Implements the Company's corporate strategy AUDIT AND RISK COMMITTEE • Oversees the financial reporting process • Independently assesses the audit process • Supports compliance with laws and regulations • Monitors internal controls and risk management ESG COMMITTEE • Adopts ESG principles • Guides the implementation of ESG principles • Conducts safety, environmental, and governance risk assessments REMUNERATION/COMPENSATION COMMITTEE • Reviews and determines remuneration for Executive Management and key employees RESERVES COMMITTEE • Ensures reserve disclosures comply with security regulations • Collaborates with independent reserves evaluators to ensure unrestricted reporting • Oversees Songo Songo gas field reserves and reviews associated technical risks 12 Orca Energy Group Inc. // Annual Report & Accounts 2024 EXECUTIVE MANAGEMENT TEAM 13 Orca Energy Group Inc. // Annual Report & Accounts 2024 14 MANAGEMENT’S DISCUSSION & ANALYSIS THIS MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”) OF OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS SHOULD BE READ IN CONJUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES FOR THE YEAR ENDED DECEMBER 31, 2024. THIS MD&A IS BASED ON THE INFORMATION AVAILABLE ON APRIL 30, 2025. ALL AMOUNTS ARE REPORTED IN US DOLLARS (“$”) UNLESS OTHERWISE NOTED. THIS MD&A CONTAINS NON-GAAP FINANCIAL MEASURES AND RATIOS AND FORWARD-LOOKING INFORMATION. READERS ARE CAUTIONED THAT THIS MD&A SHOULD BE READ IN CONJUNCTION WITH THE DISCLOSURE BELOW UNDER THE HEADINGS “NON-GAAP FINANCIAL MEASURES AND RATIOS”, “FORWARD- LOOKING STATEMENTS” AND “GLOSSARY” INCLUDED AT THE END OF THIS MD&A. Nature of Operations The principal asset of Orca Energy Group Inc. (“Orca” or the “Company”) is its indirect interest in the Songo Songo gas field, as set out in the Production Sharing Agreement (“PSA”) between PanAfrican Energy Tanzania Limited (“PAET”), the Tanzanian Petroleum Development Corporation (“TPDC”) and the Government of Tanzania (“GoT”) in the United Republic of Tanzania. PAET is the Company’s wholly owned subsidiary operating in Tanzania. The PSA covers the production and marketing of natural gas from the Songo Songo gas field offshore of Tanzania. The PSA defines the gas produced from the Songo Songo gas field as “Protected Gas” and “Additional Gas”. The gas agreement (“Gas Agreement”) deals further with the parties’ entitlement to Protected Gas and Additional Gas. Under the Gas Agreement, until July 31, 2024, Protected Gas was owned by TPDC and was sold to Songas Limited (“Songas”) and Tanzania Portland Cement PLC (“TPCPLC”). After July 31, 2024, Protected Gas ceased and all production from the Songo Songo gas field constitutes Additional Gas which PAET and TPDC are entitled to sell on commercial terms until the PSA expires in October 2026. Songas is the owner of the infrastructure that enables the gas to be treated and delivered to Dar es Salaam, which includes a gas processing plant on Songo Songo Island (collectively, the “Songas Infrastructure”). The Tanzanian Electric Supply Company Limited (“TANESCO”) is a parastatal organization wholly owned by the GoT with oversight by the Ministry of Energy (“MoE”). TANESCO is responsible for the majority of electricity generation, transmission and distribution throughout Tanzania. Natural gas has become an integral component of TANESCO’s power generation fuel mix as a more reliable source of supply over seasonal hydropower as well as a more cost-effective and lower carbon dioxide intensive alternative to liquid fuels. The Company and TPDC as joint sellers currently supply Additional Gas directly to TANESCO by way of the Portfolio Gas Supply Agreement (“PGSA”). The Company also supplies Additional Gas to TPDC through a long-term gas sales agreement (“LTGSA”) utilizing the National Natural Gas Infrastructure (“NNGI”). The PGSA was originally set to expire on July 31, 2024, but was extended on July 30, 2024. The PGSA and the LTGSA each expire on October 10, 2026. In addition to supplying gas to TPDC and TANESCO, the Company and TPDC have developed more than 50 contracts to supply gas to Dar es Salaam’s industrial market, and sells compressed natural gas to domestic, suitably converted vehicles in Dar es Salaam. Orca Energy Group Inc. // Annual Report & Accounts 2024 Financial and Operating Highlights for the Three Months and Year Ended December 31, 2024 (Expressed in $’000 unless indicated otherwise) 2024 2023 Q4/24 vs Q4/23 2024 2023 Ytd/24 vs Ytd/23 OPERATING Daily average gas delivered and sold (MMcfd) 78.6 80.8 (3)% 72.9 85.6 (15)% Industrial 19.7 13.4 47% 16.1 13.7 18% Power 58.9 67.4 (13)% 56.8 71.9 (21)% Daily average gas delivered and sold and revenue recognized (MMcfd) 71.8 80.8 (11)% 68.8 85.6 (20)% Industrial 19.7 13.4 47% 16.1 13.7 18% Power 52.1 67.4 (23)% 52.7 71.9 (27)% Average price ($/mcf) Industrial 7.35 8.97 (18)% 8.45 8.73 (3)% Power 3.90 3.84 2% 3.88 3.71 5% Weighted average 4.85 4.69 3% 4.95 4.51 10% Operating netback ($/mcf)1 3.56 2.28 56% 3.13 2.38 32% FINANCIAL Revenue 36,855 24,448 51% 111,593 110,235 1% Net (loss) / income attributable to shareholders (25,821) (438) n/m (21,578) 7,014 n/m per share – basic and diluted ($) (1.31) (0.02) n/m (1.09) 0.35 n/m Net cash flows from operating activities 6,254 9,858 (37)% 27,086 48,485 (44)% per share – basic and diluted ($)1 0.32 0.50 (36)% 1.37 2.44 (44)% Capital expenditures1 14,869 2,065 620% 27,548 8,103 240% Weighted average Class A and Class B Shares1 (‘000) 19,772 19,826 0% 19,780 19,841 0% December 31, As at December 31, 2024 2023 % Change Working capital (including cash) 1 21,904 67,323 (67)% Cash and cash equivalents 90,076 101,566 (11)% Long-term loan – 29,961 (100)% Outstanding shares (‘000) Class A 1,750 1,750 0% Class B 18,022 18,051 0% Total shares outstanding 19,772 19,801 0% RESERVES2 Gross Reserves (Bcf) Proved 40 85 (53)% Probable 1 9 (89)% Proved plus probable 41 94 (56)% Net Present Value, discounted at 10% ($ million) 2 Proved 62 108 (43)% Proved plus probable 65 119 (45)% 1 Please refer to the Non-GAAP Financial Measures and Ratios section of the MD&A for additional information. 2 Please refer to the Oil and Gas Advisory section of the MD&A for additional information. Management’ s sis D iscussion & Three Months Year ended ended December 31 % Change December 31 % Change 15 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Financial and Operating Highlights for 2024 and Q4 2024 • Revenue increased by 51% for Q4 2024 and by 1% for the year ended December 31, 2024 compared to the same prior year periods. Certain volumes were supplied as Protected Gas (defined below) prior to July 31, 2024. After the termination of Protected Gas after July 31, 2024, those volumes were instead supplied as Additional Gas (defined below). These volumes, which were delivered to Songas Limited ("Songas") in August, September and October 2024 and for which the Company did not receive compensation, have not been recognized in revenue in 2024. These unrecognized gross revenues include 80.5% of sales to Songas in the amount of $6.2 million. • On October 30, 2024, PanAfrican Energy Tanzania Limited ("PAET"), a wholly-owned subsidiary of the Company, was advised by Songas that the Interim Power Purchase Agreement ("PPA") between Tanzania Electric Supply Company Limited ("TANESCO") and Songas would expire on October 31, 2024, and that it was unknown if a new PPA would be entered into. At midnight on October 31, 2024 Songas shut down the Songas Power Plant. In the event that a new PPA is not entered into, there is a possibility that the Songas Power Plant will be shut down indefinitely. To date the Songas Power Plant remains shutdown. This has adversely impacted demand for production volumes from the Songo Songo gas field. • Gas delivered and sold decreased by 3% for Q4 2024 and by 15% for the year ended December 31, 2024 compared to the same prior year periods. During 2024, Tanzania's Julius Nyerere Hydropower Project ("JNHPP") commenced commercial operations, with progressive commissioning of 5 turbines allowing peak output of over 700 MW. Combined with the early onset of the wet season and rainfall well above seasonal averages for the period, hydro power generation and the Songas Power Plant shutdown have been the primary factors in reduced gas liftings for the power sector. • On April 14, 2023, PAET formally requested Tanzanian Petroleum Development Corporation ("TPDC") apply for an extension of the Songo Songo Development License (the "License"). TPDC is contractually required to make this application promptly upon a request by the Company. There are currently no certainties on the timing, nature and extent of any such extensions. Until such extension has been finalized, a high degree of uncertainty exists with respect to the extent of the Company’s operating activities subsequent to October 2026, when the License is set to expire. In November 2024, TPDC submitted the application for the extension of the License to the Ministry of Energy ("MoE"), however, being uneconomical, the Company informed TPDC that it did not agree with the terms as submitted. Having declined to address PAET’s concerns itself, TPDC has refused to rescind and resubmit the application and has advised PAET to raise any issues directly to the MoE. Our Counsel subsequently submitted a letter to the MoE, requesting a meeting to address the issues, to date we haven’t had a response. • On April 15, 2024, contrary to the terms of the Gas Agreement and Production Sharing Agreement (the "PSA") and in violation of Pan African Energy Corporation (Mauritius) ("PAEM") and PAET’s expectations, the Permanent Secretary of MoE wrote to TPDC, copying PAET and Songas, directing TPDC to “ensure that Protected Gas continues to be produced to the end of the Development Licence on 10th October 2026”. Consistent with that instruction, TPDC took the position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas ceased after July 31, 2024. • PAET, TPDC and Tanzania Portland Cement PLC ("TPCPLC") subsequently agreed to the terms of the Supplementary Gas Agreement ("SGA") to sell volumes after July 31, 2024 as Additional Gas, which, prior to August 1, 2024, were supplied as Protected Gas. TPCPLC has fully paid the Company $10.4 million of the receivable outstanding as at December 31, 2024. • Following cessation of Protected Gas after July 31, 2024, despite the absence of an executed contract to do so, Songas continued to lift gas volumes in August, September and October 2024, at an average rate of 20.2 MMcfd. On September 23, 2024, the Company was notified by Songas that it acknowledges it had lifted this volume, but due to TPDC’s refusal to approve a Gas Sales Agreement for this Additional Gas, they would elect to pay for only 19.5% of such volumes. This accords with the payment arrangements for Complex Additional Gas (defined below). Payments were made on this basis by Songas in Q4 2024, in the amount of $1.9 million representing 19.5% of the total invoiced amount of $9.7 million. • On August 7, 2024, PAET and PAEM issued a notice of dispute ("Notice of Dispute") in respect of an investment treaty claim against the GoT for breach of the Agreement on Promotion and Reciprocal Protection of Investment between the Government of the Republic of Mauritius and the GoT ("BIT"), and a contractual dispute against the Government of Tanzania ("GoT") and TPDC, for breaches of the: (i) PSA, and (ii) the Gas Agreement. Initial meetings with both the Advisory and Coordinating Committees were held during the week of October 14, 2024 without any resolution on the key issues in dispute. The matters have been further referred to the relevant entity’s chief executive officers and working groups in accordance with the dispute resolution process. Discussions continued with meetings held in March 2025 . Further updates on this matter will be made as appropriate. • In February 2025, the Company received a judgment (the "Judgment") from the Tanzanian High Court (Commercial Division) (the "Court") for a claim brought by a contractor against PAET. The claim was brought by the contractor for losses arising from PAET's termination of a contract relating to the Company's 3D seismic acquisition program. The contract was signed in 2022 and works were due to be completed by the end of 2022. However, work only commenced in 2023 and was never completed. Pursuant to the Judgment, the Court ordered specific and general damages in the aggregate of $23.1 million, plus legal costs and interest at a rate of 7% per annum be paid by PAET to the contractor. PAET respectfully disagrees with the Judgement and has initiated the appeal process. PAET was required to post security for the full amount of the Judgment until the appeal is resolved. The Company has recognised the resulting liability in 2024 based on the Judgement applied. The Company has initiated the appeal process, and if successful in that process, a reversal would be recognized in earnings at that time. • The well intervention operations on SS-7 have now concluded. The work program, following a complex mobilization to Songo Songo Island, sought to restore the mechanical integrity of the well to shutoff water production in order to restart production from the southern compartment of the Songo Songo gas field. Following several remedial cement treatments to shut off the lower water producing zone and reperforation of the upper Neocomian sands, limited and unsustained gas flows were observed. The Company, in line with its contingency plans, set a cement plug above the Neocomian interval and perforated the shallower Cenomanian sands. Having completed all possible downhole work, and after an unsuccessful attempt to produce gas from the Cenomanian sands, the Company ceased well intervention operations and demobilized the barge and jack-up from the SS-7 site. The total expected project cost has increased to $25.9 million from $23.5 million, primarily as a result of the significant attempts required to shut off water and reproduce the well. A comprehensive post project analysis will be carried out to evaluate the intervention results, which have not met production expectations. During the year, the Company recorded an asset impairment expense of $25.9 million with respect to the SS-7 well workover program. • The Company completed a production and saturation logging program in three wells: SS-3, SS-10 and SS-5. Results indicate that the wells and field are performing in line with expectations, and have been used to update longer term reservoir management plans. The total expected program cost increased to $2.2 million from $1.3 million. 16 Orca Energy Group Inc. // Annual Report & Accounts 2024 17 • Net loss attributable to shareholders amounted to $21.6 million for the year ended December 31, 2024 compared to net income attributable to shareholders of $7.0 million for the same prior year period. In Q4 2024, the Company recorded an asset impairment expense of $25.9 million with respect to the SS-7 well workover program and a loss allowance of $21.7 million with respect to the ongoing litigation relating to the Judgment in the High Court of Tanzania. • Net cash flows from operating activities decreased by 37% for Q4 2024 and by 44% for the year ended December 31, 2024 compared to the same prior year periods. The decrease for the year ended December 31, 2024 over the comparable prior year period is mainly a result of changes in non-cash working capital. • Capital expenditures increased by 635% for Q4 2024 and by 244% for the year ended December 31, 2024 compared to the same prior year periods. The capital expenditures in 2024 primarily related to the well workover program. The capital expenditures in 2023 primarily related to the initial costs of the well workover program and the 3D seismic acquisition program. • The Company exited the period with $21.9 million in working capital (December 31, 2023: $67.3 million), cash and cash equivalents of $90.1 million (December 31, 2023: $101.6 million) and long-term debt of $ nil (December 31, 2023: $30.0 million). Cash held in hard currencies (USD, Euro, GBP, CDN) was $87.1 million, as at December 31, 2024 (December 31, 2023: $60.4 million). The decrease in long-term debt is related to a repayment of principal of $10.0 million in April 2024 and October 2024, representing the fourth and fifth semi-annual repayments of the Company’s long-term debt as well as maturing of the outstanding loan principal. • Subsequent to December 31, 2024, the Company fully prepaid the $60 million investment (the "Loan") made by International Finance Corporation ("IFC") in PAET, pursuant to a loan agreement dated October 29, 2015 between the IFC, PAET and the Company (the "Loan Agreement"). To effect the foregoing prepayment, the Company paid to IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. As of the date hereof, the annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. • As at December 31, 2024, the current receivable from TANESCO was $12.7 million (December 31, 2023: $5.9 million). The TANESCO long-term receivable as at December 31, 2024 and as at December 31, 2023 was $22.0 million and has been fully provided for. Subsequent to December 31, 2024, the Company has invoiced TANESCO $14.5 million for Q1 2025 gas deliveries. TANESCO has paid the Company $24.2 million to date which relate to the outstanding amount at December 31, 2024 and payments for a portion of Q1 2025 gas deliveries • Total working interest proved conventional natural gas reserves ("1P") and total proved plus probable conventional natural gas reserves ("2P") decreased by 53% and 56%, respectively, as at December 31, 2024 compared to the prior year. The decrease was primarily attributed to 26.7 Bcf of production in 2024 and 18.1 Bcf of negative technical revisions. The technical revisions were primarily due to lower forecasted gas sales to the end of the License attributed to increased hydro power use in Tanzania and the removal of Proved Undeveloped reserves due to the unsuccessful well intervention on SS-7. The net present value of lower reserves and estimated future cash flows from 2P reserves at a 10% discount rate decreased by 45% compared to the previous year mainly as a result of lower reserves at year end 2024 and the associated 33% reduction in the number of years outstanding on the current License. Orca Energy Group Inc. // Annual Report & Accounts 2024 Oil and Gas Advisory The Company’s conventional natural gas reserves as at December 31, 2024 disclosed herein were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants, in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The independent reserves evaluations prepared by McDaniel had an effective date of December 31, 2024 and December 31, 2023 and preparation date of February 18, 2025 and February 1, 2024, respectively. All of the reserves presented herein are conventional natural gas reserves. The net present value of future net revenue attributable to the Company’s reserves is stated without provision for interest costs and out of country general and administrative costs, but after providing for estimated additional profits tax, production costs, development costs, other income and future capital expenditures for only those wells assigned reserves by McDaniel. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Company’s reserves estimated by McDaniel represent the fair market value of those reserves. Such amounts do not represent the fair market value of the Company’s reserves. The recovery and reserve estimates of the Company’s conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. All of the reserves referenced herein are based on McDaniel’s forecast pricing as at December 31, 2024 and December 31, 2023, as applicable. All the Company’s reserves are located in Tanzania. Reserves included herein are stated on a Company gross reserves basis unless noted otherwise. Company gross reserves are the total of the Company’s working interest share in reserves and are based on the Company’s 100% ownership interest in the reserves (2023: 100%). Additional reserves information required under NI 51-101 is included in Orca’s reports relating to reserves data and other oil and gas information under NI 51-101, which are filed on its profile on SEDAR+ at www.sedarplus.ca. “BOEs” may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. For certainty, all references herein to “production”, “gross daily sales”, “gas sales” and “Additional Gas sales” are references to conventional natural gas production, conventional natural gas daily sales, conventional natural gas sales and conventional natural gas sales, which are classified as Additional Gas in accordance with the PSA, respectively. Operating Volumes The average gross daily sales volume decreased by 3% for Q4 2024 and by 15% for the year ended December 31, 2024 over the comparable prior year periods. Earlier in 2024 the JNHPP commenced commercial operations, with progressive commissioning of 5 turbines allowing peak output of over 700 MW. Combined with the early onset of the wet season and rainfall well above seasonal averages for the period, hydro power generation and the Songas Power Plant shutdown have been the primary factors in reduced gas liftings for the power sector. The Company’s gross sales volumes, including the volumes for which revenue was not recognized, were split between the industrial and power sectors as detailed in the table below: Three Months ended Year ended December 31 December 31 2024 2023 2024 2023 Gross sales volume (MMcf) Industrial sector 1,812 1,230 5,881 5,007 Power sector 5,415 6,205 20,798 26,249 Total volumes 7,227 7,435 26,679 31,256 Gross daily sales volume average (MMcfd) Industrial sector 19.7 13.4 16.1 13.7 Power sector 58.9 67.4 56.8 71.9 Gross daily sales volume average total 78.6 80.8 72.9 85.6 Industrial Sector Industrial sector gross daily sales volumes increased by 47% for Q4 2024 and by 18% for the year ended December 31, 2024 over the comparable prior year periods. The increases were a result of increased consumption by industrial customers due to a higher demand for services and products as well as the end of the Protected Gas regime, which resulted in higher deliveries of Additional Gas to TPCPLC from August 2024 onward. Power Sector Power sector gross daily sales volumes decreased by 13% for Q4 2024 and by 21% for the year ended December 31, 2024 over the comparable prior year periods. Although the deliverability from the currently producing wells and reservoir compartments in the Songo Songo gas field is declining over time, the inauguration of the JNHPP and the early onset of the wet season in 2024 led to increased availability of hydro power causing significantly lower lifting from power customers earlier in 2024, in conjunction with the Songas Power Plant shutdown impacting demand in Q4 2024 as detailed below. Power sector gross sales volumes in 2024 include volumes lifted by Songas in August, September and October 2024 averaging 20.2 MMcfd from August 1, 2024 to October 31, 2024. Songas elected to pay for 19.5% of these volumes referring to the lack of approval of the Additional Gas contract by TPDC. The remaining 80.5% of these volumes are not recognized in revenue at this time. Table below presents operating volumes corresponding to the revenue that has been recognized. Management’ s sis D iscussion & 18 Orca Energy Group Inc. // Annual Report & Accounts 2024 Operating volumes where revenue is recognized Three Months ended Year ended December 31 December 31 2024 2023 2024 2023 Gross sales volume (MMcf) where revenue is recognized Industrial sector 1,812 1,230 5,881 5,007 Power sector 4,792 6,205 19,304 26,249 Total volumes where revenue is recognized 6,604 7,435 25,185 31,256 Gross daily sales volume average (MMcfd) where revenue is recognized Industrial sector 19.7 13.4 16.1 13.7 Power sector 52.1 67.4 52.7 71.9 Gross daily sales volume average total where revenue is recognized 71.8 80.8 68.8 85.6 Protected Gas Volumes Protected Gas volumes decreased by 51% to 7,008 MMcf (19.1 MMcfd) for the year ended December 31, 2024 compared to 14,170 MMcf (38.8 MMcfd) for the year ended December 31, 2023. The Company received no revenue for Protected Gas volumes; however the volumes were required to calculate total gas produced from the reservoir and the allocation of certain production, distribution and transportation expenses between Protected Gas and Additional Gas. Protected Gas ceased after July 31, 2024, whereafter all gas from the Songo Songo gas field is now classified as Additional Gas. It is our belief that PAET is fully entitled to compensation at a commercial rate for all volumes of gas lifted by Songas starting on August 1, 2024. Gas continued to flow to Songas following August 1, 2024 to October 31, 2024 and there is a risk that PAET will not receive full payment or payment may form part of a contract dispute. 19 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Commodity Prices The commodity prices achieved in the different sectors during the year are detailed in the table below: Three Months ended December 31 Year ended December 3 $/mcf 2024 2023 2024 2023 Average sales price Industrial sector 7.35 8.97 8.45 8.73 Power sector 3.90 3.84 3.88 3.71 Weighted average price 4.85 4.69 4.95 4.51 Industrial Sector The average sales price for the industrial sector decreased by 18% for Q4 2024 and by 3% for the year ended December 31, 2024 over the comparable prior year periods. Subsequent to December 31, 2024, the SGA has been retroactively approved and TPCPLC became eligible for lower pricing with an effective date of August 1, 2024. Power Sector The average sales price for the power sector increased by 2% for Q4 2024 and by 5% for the year ended December 31, 2024 compared to the same prior year periods. The average power sector sales price varies depending on whether gas is delivered and sold through the NNGI or the Songas Infrastructure. Sales through the NNGI are to TPDC and do not include processing and transportation tariffs which are included in gas delivered through the Songas Infrastructure. During Q3 and Q4 2024, the Company invoiced Songas $9.6 million (including VAT and production taxes) for August, September and October 2024 liftings of Additional Gas volumes. On September 23, 2024, the Company was notified by Songas that it acknowledges it had lifted this volume, but due to TPDC’s refusal to approve a Gas Sales Agreement for this Additional Gas, they would elect to pay only 19.5% of such volumes. The Company recognized the payment of $1.9 million, being 19.5% of the August, September and October 2024 sales to Songas in revenue; these amounts were paid by Songas in Q4 2024. $7.7 million of August, September and October 2024 sales representing 80.5% of delivered volumes remain unrecognized as of the date of this report. Including these volumes in the power sector average sales price calculation would result in a Q4 2024 price of $3.45/mcf and for the year ended December 31, 2024, a price of $3.60/mcf. Including the volumes not recognized as revenue in the weighted average sales price calculation would result in a Q4 2024 price of $4.43/mcf and for the year ended December 31, 2024, a price of $4.67/mcf. Revenue Under the terms of the PSA the Company is responsible for invoicing, collecting and allocating the revenue from Additional Gas sales (see “Principal Terms of the PSA and Related Agreements”). The Company is entitled to recover all costs incurred on the exploration, development and operations of the project (“Cost Gas revenue”) up to a maximum of 75% of the net field revenue (gross field revenue less the tariff for processing and pipeline infrastructure) prior to allocating the remaining net field revenue between TPDC and the Company (“Profit Gas revenue”). Any costs not recovered in a period are carried forward for recovery out of future revenues. Once the Cost Gas revenue has been recovered, TPDC is able to recover any pre-approved marketing costs. Currently there are no pre-approved marketing costs for TPDC. The Company is liable for income tax in Tanzania, but under the terms of the PSA, TPDC’s share of revenue is reduced by the current tax payable grossed up at 30% (“income tax adjustment”). Revenue as presented on the Company’s Consolidated Statements of Comprehensive Income is calculated by adjusting the Company’s operating revenue by the income tax adjustment. The reconciliation of gross field revenue to Company operating revenue is detailed below: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Industrial sector 13,312 11,028 49,693 43,694 Power sector 18,708 23,842 74,926 97,378 Gross field revenue 32,020 34,870 124,619 141,072 TPDC share of revenue (3,226) (13,318) (25,843) (47,364) Company operating revenue 28,794 21,552 98,776 93,708 Current income tax adjustment 8,061 2,896 12,817 16,527 36,855 24,448 111,593 110,235 20 Orca Energy Group Inc. // Annual Report & Accounts 2024 Revenue increased by 51% for Q4 2024 and by 1% for the year ended December 31, 2024 over the comparable prior year periods. Volumes classified as Protected Gas prior to July 31, 2024, which were delivered to Songas in August, September and October 2024 (and as such constitutes Additional Gas for which PAET is entitled to payment) and for which PAET did not receive compensation, do not meet the definition of revenue under IFRS 15 and have not been recognized in revenue in Q3 2024 and Q4 2024. These unrecognized revenues include 80.5% of sales to Songas in the amount of $6.2 million. The average Additional Gas sales volumes for the quarters ended December 31, 2024 and December 31, 2023 as well as for the quarters ended September 30, 2024, June 30, 2024, March 31, 2024, September 30, 2023, June 30, 2023 and March 31, 2023 were above 50 MMcfd which entitled the Company to a 55% share of Profit Gas revenue. The Company was allocated a total of 89% of the Additional Gas net field revenue for Q4 2024 (Q4 2023: 58%) and a total of 77% of the Additional Gas net field revenue for the year ended December 31, 2024 (year ended December 31, 2023: 63%). 21 Orca Energy Group Inc. // Annual Report & Accounts 2024 Production, Distribution and Transportation Expenses The production, distribution and transportation costs are detailed in the table below: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Operating costs 1,036 872 5,288 3,941 Tariff for processing and pipeline infrastructure 3,345 3,180 11,968 12,390 Ring-main distribution costs 884 524 2,734 2,866 5,265 4,576 19,990 19,197 Operating costs include well maintenance costs, PSA license costs, regulatory fees, insurance, certain costs associated with evaluation of the reserves and the costs of personnel not recoverable from Songas. Operating costs increased by 19% for Q4 2024 and by 34% for the year ended December 31, 2024 compared to the same prior year periods, primarily as a result of the production and saturation logging program in Q3 2024 and Q4 2024, partially offset by decreased insurance costs. The amount paid under the tariff for processing and pipeline infrastructure increased by 5% for Q4 2024 and decreased by 3% for the year ended December 31, 2024 compared to the same prior year periods. The decrease for the year ended December 31, 2024 compared to the same prior year periods primarily was a result of decreased gas volumes processed and delivered through the Songas Infrastructure. Ring-main distribution costs increased by 69% for Q4 2024 and decreased by 5% for the year ended December 31, 2024 compared to the same prior year periods. The decrease for the year ended December 31, 2024 compared to the same prior year period is a result of higher compressor maintenance costs incurred in 2023. Operating Netback The operating netback per mcf before general and administrative expenses, tax and additional profits tax (“APT”) is detailed in the table below (see “Non- GAAP financial measures and ratios”): Three Months ended December 31 Year ended December 31 $/mcf 2024 2023 2024 2023 Weighted average price for gas 4.85 4.69 4.95 4.51 TPDC Profit Gas entitlement (0.49) (1.79) (1.03) (1.52) Production, distribution and transportation expenses (0.80) (0.62) (0.79) (0.61) Operating netback 3.56 2.28 3.13 2.38 The operating netback increased by 56% for Q4 2024 and by 32% for the year ended December 31, 2024 over the comparable prior year periods. The increases are mainly a result of higher weighted average price for natural gas and lower TPDC Profit Gas revenue entitlements as an outcome of increased capital expenditures and lower Cost Gas revenue recoveries by the Company. Songas has invoiced PAET for the production and transportation tariff consistent with all gas volumes shipped to Songas during August, September and October 2024 as being treated as Additional Gas. This amount has been fully accounted for and paid by PAET in accordance with the terms of the current agreements and forms part of the operating netback calculation above. Management’ s Discussion & Analysis 22 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED General and Administrative Expenses General and administrative expenses are split between the Company’s head office and Tanzania. A significant percentage of general and administration expenses relate to office and management costs that support the Company’s operations in Tanzania and are cost recoverable under the PSA. Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Tanzania 3,379 2,766 9,932 8,601 Corporate 2,790 2,768 9,887 9,291 6,169 5,534 19,819 17,892 General and administrative expenses are detailed in the table below: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Employee and related costs 3,100 2,855 10,315 9,988 Office costs 1,389 1,295 4,673 4,045 ESG, marketing and business development costs 115 110 285 367 Reporting, regulatory and corporate 1,565 1,274 4,546 3,492 6,169 5,534 19,819 17,892 General and administrative expenses averaged $2.1 million per month during Q4 2024 (Q4 2023: $1.8 million) and $1.7 million per month for the year ended December 31, 2024 (year ended December 31, 2023: $1.5 million). The 3% increase in employee and related costs for the year ended December 31, 2024 over the comparable prior year period was mainly a result of the annual indexation of payroll cost in Tanzania. The 16% increase in office costs for the year ended December 31, 2024 over the comparable prior year period was primarily a result of increased requirement for legal services in Tanzania. Environmental, social and governance (“ESG”) and marketing and business development costs have not significantly changed for the year ended December 31, 2024 over the comparable prior year period. The 30% increase in reporting, regulatory and corporate costs for the year ended December 31, 2024 over the comparable prior year period was due to increase in costs related to professional services, mainly legal services. Long Term Retention Plan In 2023, the Company introduced the long-term retention award plan (“Long Term Retention Plan”) effectively replacing the stock based compensation program previously in place. The total potential award amount payable to eligible participants (employees and directors) under the plan is $4.8 million, with an award payment date of September 30, 2026, subject to certain conditions. This award amount is being recognized on a straight-line basis over the four-year period in general and administrative expenses. 23 Orca Energy Group Inc. // Annual Report & Accounts 2024 Depletion and Depreciation Natural gas properties are depleted using the unit of production method based on the production for the period as a percentage of the total future production from the Songo Songo proved reserves. As at December 31, 2024 the estimated proved reserves remaining to be produced over the term of the PSA as determined by McDaniel in their report dated February 18, 2025 with an effective date of December 31, 2024 and prepared in accordance with NI 51-101 and the COGE Handbook were 40.2 Bcf (December 31, 2023: 85.0 Bcf). The average depletion rate was $1.14/mcf for the year ended December 31, 2024 compared to $1.12/mcf for the comparable prior year. Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Oil and natural gas interests 9,075 15,052 30,506 41,857 Office and other 59 35 209 120 Right-of-use assets 76 53 308 252 9,210 15,140 31,023 42,229 The depletion charge for natural gas interests decreased by 40% for Q4 2024 and by 27% for the year ended December 31, 2024 over the comparable prior year periods. The decreases were primarily the result of decreased gas produced and sold. Additionally, during Q4 2023 accelerated depletion totaling $7.0 million was recognized with respect to the 3D seismic acquisition and processing program. Finance Income and Expense Finance income is detailed in the table below: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Interest income 867 748 3,665 1,888 867 748 3,665 1,888 Finance expense is detailed in the table below: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Base interest expense 828 1,092 3,808 4,850 Participation interest (recovery) / expense (222) 702 914 2,970 Lease interest expense 10 9 48 14 Interest expense 616 1,803 4,770 7,834 Net foreign exchange (gain) / loss (1,077) 526 7,681 5,001 Indirect tax 325 298 1,300 1,273 Trade and other receivables write off – 830 – 830 (136) 3,457 13,751 14,938 Management’ s sis D iscussion & 24 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Base interest expense and participation interest expense relate to the Loan from IFC to PAET. Base interest on the Loan was payable quarterly in arrears at 10% per annum on a “pay-if-you-can-basis” using a formula to calculate the net cash available for such payments as at any given interest payment date. The participation interest expense is paid annually in arrears. It equates to 6.4% of PAET’s net cash flows from operating activities less the net cash flows used in investing activities for the year. Such participation interest will continue to accrue until October 15, 2026 regardless of the early prepayment of the Loan. The decrease in participation interest expense is primarily a result of the decrease in PAET’s net cash flows from operating activities net of net cash used in investing activities. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan. To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. Net foreign exchange losses are the result of transactions in foreign currencies recorded at the rate of exchange prevailing on the date of such transactions and include both realized and unrealized revaluation gains and losses. Specifically, unrealized revaluation gains or losses represent temporary changes in the fair value of cash balances denominated in Tanzanian shillings. Following a prolonged period of weakness in the value of the Tanzanian shilling versus the US dollar, these movements are now considered permanent in nature and recognized as realized exchange losses in 2024. Monetary assets and liabilities in foreign currencies are translated at period-end rates. Non-monetary items are translated at historic rates, unless such items are carried at market value, in which case they are translated using the exchange rates that existed when the values were determined. The indirect tax is for value added tax ("VAT") associated with invoices to TANESCO for interest on late payments. The trade and other receivables write off in 2023 relates to VAT on interest invoices to Songas relating to unpaid invoices and an advance which was paid to a supplier and could not be recovered. Loss Allowance Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Loss allowance 21,700 – 21,700 – Reversal of loss allowance – (4,901) – (6,915) 21,700 (4,901) 21,700 (6,915) The loss allowance in 2024 follows $21.7 million allowed with respect to ongoing litigation in the High Court of Tanzania and represents the amount required to increase the provision to cover the current gross liability before any cost recovery, following the criteria of IAS 37 (Provisions, Contingent Liabilities and Contingent Assets). The reversal of loss allowance in 2023 follows: (i) the recognition of $4.9 million resulting from agreement with Songas on a revision to the cost sharing in respect of the 2015-2016 workover of the SS-5 and SS-9 wells; and (ii) indirect taxation of $2.0 million relating to the 2020 and 2021 take or pay invoices to TANESCO that were paid in 2023. Asset Impairment Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Asset impairment 26,651 – 26,651 – 26,651 – 26,651 – During the year, the Company performed a workover on the SS-7 well. The work program sought to restore the mechanical integrity of the well to shutoff water production in order to restart production from the southern compartment of the Songo Songo gas field. Following water shut off and reperforation of the Neocomian sands, limited and unsustained gas flows were observed. Having completed all possible downhole work the Company has ceased well intervention operations. The program will not be pursued in the foreseeable future. Accordingly, the Company has tested the SS-7 well workover project for impairment on a stand-alone basis and recorded an impairment expense of $25.9 million, the full project cost. At December 31, 2024, the Company evaluated the remaining CGU assets for indicators of impairment and as a result of this assessment management determined that an impairment test was not required to be performed. In addition during the year, the Company recorded a write off of a trade receivable of $0.8 million which relates to an advance which was paid to a supplier and could not be recovered. 25 Orca Energy Group Inc. // Annual Report & Accounts 2024 Tax Income Tax Three Months ended December 31 Year ended December 31 $’000 2024 2023 2024 2023 Current tax 6,834 3,354 13,737 16,133 Deferred tax (12,792) (986) (15,508) (6,161) (5,958) 2,368 (1,771) 9,972 Under the terms of the PSA with TPDC and the GoT, the Company is liable for income tax in Tanzania at the corporate tax rate of 30%. However, the PSA provides a mechanism by which income tax payable is recovered from TPDC by reducing TPDC’s share of Profit Gas revenue and increasing the allocation to the Company. This is reflected in the accounts by increasing the Company’s share of revenue by an amount equivalent to current year income taxes payable grossed up by 30%. As at December 31, 2024 there were temporary differences between the carrying value of the assets and liabilities for financial reporting purposes and the amounts used for taxation purposes under the Income Tax Act 2004. Applying the 30% Tanzanian tax rate, the Company has recognized a deferred tax liability of $4.6 million (December 31, 2023: $20.1 million). The deferred tax has no impact on cash flow until it becomes a current income tax, at which point the tax is paid and recovered from TPDC’s share of Profit Gas revenue. Additional Profits Tax Three Months ended December 31 Year ended December 31 $’000 2024 2023 2024 2023 APT 777 1,753 6,190 8,162 Under the terms of the PSA, APT is payable when the Company has recovered its costs plus a specified return out of Cost Gas revenue and Profit Gas revenue. As a result: (i) no APT is payable until the Company recovers its costs out of Additional Gas revenue plus an annual operating return under the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum APT rate is 55% of the Company’s Profit Gas revenue when costs have been recovered with an annual return of 35% plus the percentage change in PPI. The timing and the effective rate of APT depends on the realized value of Profit Gas revenue which in turn depends on the level of expenditure. The Company provides for APT by annually forecasting the total APT payable in the future as a proportion of the forecast Profit Gas revenue over the term of the PSA. The forecast takes into account the timing of future development capital spending. As at December 31, 2024, the current portion of APT payable was $7.8 million (December 31, 2023: $16.0 million) with a long-term APT payable of $5.9 million (December 31, 2023: $7.5 million). APT of $16.0 million was paid in Q1 2024 based on the 2023 results (Q1 2023: $13.1 million paid based on 2022 results). The effective APT rate of 19.7% (Q4 2023: 11.5%) has been applied to the Company’s share of Profit Gas revenue of $3.9 million for Q4 2024 (Q4 2023: $15.3 million), and average effective rate of 20.2% (2023: 14.5%) has been applied to the Company’s share of Profit Gas revenue of $30.7 million for the year ended December 31, 2024 (year ended December 31, 2023: $56.2 million). Accordingly, $0.8 million for the quarter ended December 31, 2024 (Q4 2023: $1.8 million) and $6.2 million for the year ended December 31, 2024 (year ended December 31, 2023: $8.2 million) of APT has been recorded in the Consolidated Statements of Comprehensive Income. 26 Orca Energy Group Inc. // Annual Report & Accounts 2024 Working Capital Working capital as at December 31, 2024 was $21.9 million (December 31, 2023: $67.3 million) and is detailed in the table below (also see “Non-GAAP financial measures and ratios”): As at December 31 $’000 2024 2023 Cash and cash equivalents1 90,076 101,566 Trade and other receivables Songas 2,161 8,146 TPDC 5,592 3,841 TANESCO 12,731 5,851 TPCPLC 10,409 3,625 Industrial customers and other receivables 14,321 12,551 Loss allowance (1,177) 44,037 (1,177) 32,837 Prepayments 1,586 1,637 135,699 136,040 Trade and other liabilities TPDC share of Profit Gas revenue2 16,359 17,199 Songas 2,741 2,981 Deferred income – take or pay contracts 943 1,144 Other trade payables and accrued liabilities 46,808 17,083 Current portion of long-term loan 30,122 10,000 Current portion of APT 7,824 105,105 15,984 64,391 Tax payable 8,998 4,326 113,795 68,717 Working capital 21,904 67,323 1 As of the date of this report, $24.7 million of the amount was posted as security for the full amount of the seismic Judgment and will be restricted until the appeal is resolved. 2 The balance of $16.4 million payable to TPDC is the liability for TPDC’s share of Profit Gas revenue, primarily related to unpaid gas deliveries to TANESCO. For their allocation of Profit Gas revenue, the Company paid TPDC $2.4 million in February 2024, $3.8 million in April 2024, $5.4 million in July 2024, $2.3 million in October 2024 and $3.8 million in April 2025. Financial Instruments Current financial instruments of the Company include cash and cash equivalents, trade and other receivables, trade and other liabilities and tax payable. The carrying values of the financial instruments approximate fair values due to their relatively short periods to maturity. The risks associated with the Company’s financial instruments are primarily attributed to the inherent riskiness of the Tanzanian cash holdings and the ability to exchange Tanzanian shillings for hard currencies, and the risk that trade and other receivables may not be paid when due. The Company mitigates these risks by (i) holding, when possible, the majority of its cash (other than Tanzanian shillings) outside of Tanzania in reputable international financial institutions primarily in Jersey and Mauritius which reduces the Company’s exposure to geo-political risks; (ii) monitoring and reviewing the trade and other receivables on a regular basis to determine if allowances are required for overdue amounts or action is required to restrict deliveries on past due accounts to reduce exposure on outstanding receivables; and (iii) seeking payments from its customers, when possible, in US dollars. As of December 31, 2024, over 90% of receipts from domestic customers are denominated in Tanzanian shillings. There are no restrictions on the movement of cash from Jersey, Mauritius or Tanzania. Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets cease to be recognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has transferred substantially all risks and rewards of ownership. Working Capital Requirements Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan. The Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The Company expects to have sufficient cash flow from operating activities to maintain adequate working capital to cover both short-term and long-term obligations for 2025. The Company maintains adequate US dollars and other hard currencies on hand to ensure it can meet all its foreign denominated capital expenditure obligations and deal with possible fluctuations in liquidity from operational problems and US dollar liquidity issues in Tanzania. The global growth slowdown has seen an increased decline in foreign exchange reserves in Tanzania, which has given rise to decreased availability of US dollars in Tanzania and impaired the Company’s ability to convert Tanzanian shillings directly to US dollars in 2024 and 2023. There is a risk that the Company may not be able to convert Tanzanian shillings to hard currencies, such as US dollars, in the future as and when required. It is not known when the foreign exchange reserve deficiency in Tanzania will be remedied, if ever. Management’ s sis D iscussion & 27 Orca Energy Group Inc. // Annual Report & Accounts 2024 On April 15, 2024, contrary to the terms of the Gas Agreement and PSA and in violation of PAEM and PAET’s legitimate expectations, the Permanent Secretary of the MoE wrote to TPDC, copying PAET and Songas, directing TPDC to “ensure that Protected Gas continue to be produced to the end of the Development Licence on 10th October 2026”. Consistent with that instruction, TPDC has taken the position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas would cease after July 31, 2024. PAET, TPDC and TPCPLC entered into a Supplementary Gas Agreement that recognises all volumes supplied to TPCPLC from August 1, 2024 as Additional Gas, and TPCPLC has fully paid for all volumes lifted since such date. The supply of gas to Songas from August 1, 2024 to October 31, 2024 has not yet been resolved. It is our belief that PAET is entitled to payment at a commercial rate for all volumes of gas lifted by Songas starting on August 1, 2024. Gas continued to be lifted by Songas post August 1, 2024 and until October 31, 2024. During Q3 and Q4 2024, the Company invoiced Songas $9.6 million (including VAT and production taxes) for August, September and October 2024 liftings of Additional Gas volumes. Songas, referring to the lack of approval of the Additional Gas contract by TPDC, elected to pay for 19.5% of the total invoiced amount. There is a risk that the remaining amount will not be paid or recognized as revenue. This may adversely impact the Company’s ability to finance its capital requirements. On October 30, 2024, PAET was advised by Songas that the Interim PPA between TANESCO and Songas, would expire on October 31, 2024, and that it is unknown if a new PPA would be entered into. At midnight on October 31, 2024 the Interim PPA expired and Songas shut down the Songas Power Plant. To date, the Songas Power Plant remains shut down. 28 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED TANESCO Receivable As at December 31, 2024, the current receivable from TANESCO was $12.7 million (December 31, 2023: $5.9 million). During 2024 the Company invoiced TANESCO $51.1 million (2023: $32.9 million) for gas deliveries made during the year. As at December 31, 2024, the Company had received $44.2 million (2023: $30.8 million) in payments. Based on the consistent payments from TANESCO, the Company recognized all amounts invoiced for gas deliveries in 2023 and 2024 as revenue. In addition, in 2023 TANESCO paid the Company $13.2 million against the 2020 and 2021 take or pay invoices. $11.2 million of this amount was released to the Company’s Statements of Comprehensive Income as revenue in 2023. $2.0 million, being the VAT component of the take or pay invoices, was reversed out of loss allowance in 2023. The TANESCO long-term receivable as at December 31, 2024 and December 31, 2023 was $22.0 million which has been fully provided for. Subsequent to December 31, 2024, the Company has invoiced TANESCO $14.5 million for Q1 2025 gas deliveries, and TANESCO has paid the Company $24.2 million to date which relate to the outstanding amount at December 31, 2024 and payments for a portion of Q1 2025 gas deliveries. Capital Expenditures The capital expenditures (see “Non-GAAP financial measures and ratios”) in 2024 primarily related to the well workover program. The capital expenditures in 2023 primarily related to the initial costs of the well workover program and the 3D seismic acquisition program. Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Pipelines, well workovers and infrastructure 14,869 2,067 27,233 7,984 Other capital expenditures – (2) 315 119 14,869 2,065 27,548 8,103 Capital Requirements Except as described below, there are no contractual commitments for exploration or development drilling or other field development, either in the PSA or otherwise agreed, which would give rise to significant capital expenditure with respect to the Songo Songo gas field. Any additional significant capital expenditure in Tanzania is discretionary. During the year, the Company recorded asset impairment expense of $25.9 million with respect to the SS-7 well workover program which has now concluded. The work program sought to restore the mechanical integrity of the well to shutoff water production in order to restart production from the southern compartment of the Songo Songo gas field. Following several remedial cement treatments to shut off the lower water producing zone and reperforation of the Neocomian sands, limited and unsustained gas flows were observed. Having completed all possible downhole work the Company has ceased well intervention operations. It is not known if further attempts to return the well to production will be pursued in the foreseeable future. Given the time remaining on the existing License, lack of progress on the License extension application, and ongoing and potential disputes regarding Protected Gas, all capital projects, other than maintenance and those necessary for essential safety are currently on hold. Long-term Receivables As at December 31 $’000 2024 2023 Lease deposit 10 10 10 10 The following table details the amounts receivable from TANESCO: As at December 31 $’000 2024 2023 105,210 89,809 (12,731) (5,851) (70,461) (61,940) Total amounts invoiced to TANESCO Current trade receivable – TANESCO Unrecognized amounts 1 Loss allowance (22,018) (22,018) – – 1 The amount includes invoices for interest on late payments from TANESCO. 29 Orca Energy Group Inc. // Annual Report & Accounts 2024 All issued capital stock is fully paid. Cash Flow Summary Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Operating activities Net (loss)/income (25,821) (438) (21,578) 7,014 Non-cash adjustments 23,308 16,194 46,647 48,619 Interest expense 616 1,803 4,770 7,834 Changes in non-cash working capital 1 8,151 (7,701) (2,753) (14,982) Net cash flows from operating activities 6,254 9,858 27,086 48,485 Net cash used in investing activities (10,744) (2,209) (17,960) (8,794) Net cash used in financing activities (7,513) (7,905) (23,071) (31,738) (Decrease)/Increase in cash (12,003) (256) (13,945) 7,953 1 See Consolidated Statements of Cash Flows The Company recorded net loss of $25.8 million in Q4 2024 and $21.6 million for the year ended December 31, 2024 primarily as a result of the asset impairment expense of $25.9 million with respect to the SS-7 well workover program. In addition, in Q4 2024 the Company recorded a loss allowance of $21.7 million with respect to ongoing litigation in the High Court of Tanzania. The Company’s net cash flows from operating activities decreased by 37% for Q4 2024 and by 44% for the year ended December 31, 2024 over the comparable prior year periods. The decrease for the year ended December 31, 2024 over the comparable prior year period mainly is a result of changes in non-cash working capital, particularly increase in trade receivables. The increase in net cash used in investing activities for Q4 2024 and for the year ended December 31, 2024 over the comparable prior year periods was mainly a result of higher expenditure in relation to the costs of the SS-7 well workover program. The decrease in net cash used in financing activities for Q4 2024 and for the year ended December 31, 2024 over the comparable prior year periods was mainly an outcome of the distribution to non-controlling interest shareholder in Q3 2023 as well as lower interest payments throughout 2024 as a result of repayments of three instalments of the Loan in Q4 2023, Q2 2024 and Q4 2024. Management’ s Discussion & Analysis 30 Long-term Loan In 2015 PAET took out the Loan with the IFC, a member of the World Bank Group, for $60 million. The Loan was fully drawn down in 2016. The Loan was to be paid out through six semi-annual payments of $5.0 million starting October 15, 2022 and one final payment of $25.2 million due on October 15, 2025. The Loan was an unsecured subordinated obligation of PAET. Pursuant to the sale of the non-controlling interest in PAEM, the parent company of PAET, in 2018, the Company agreed with the IFC to reduce the outstanding amount of the Loan by the percentage interest sold of 7.933% ($4.8 million) before the fourth anniversary of the first drawdown. PAET made this payment on October 16, 2019. Dividends and distributions from PAET to PAEM were restricted at any time whenever amounts of interest, principal or participating interest are due and outstanding. All amounts under the Loan have been paid when due. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan. To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The annual variable participating interest granted by PAET to the IFC under the terms of the loan agreement with the IFC remains outstanding. Outstanding Shares The Class A Shares are convertible at any time at the option of the holder into Class B Shares on a one-for-one basis. Subject to the terms and conditions of conversion specified in the memorandum of association and articles of association of the Company, the Class B Shares are convertible into Class A Shares on a one-for-one basis if an offer is made to purchase Class A Shares that: (i) must, by reason of applicable securities legislation or the requirements of a stock exchange on which the Class A Shares are listed, be made to all or substantially all of the holders of Class A Shares; and (ii) are not made concurrently with an offer to purchase Class B Shares that is identical to the offer to purchase Class A Shares and that has no condition attached other than the right not to take up and pay for shares tendered if no shares are purchased pursuant to the offer for Class A Shares. The conversion right does not come into effect under certain events specified in the memorandum of association of the Company, including, without limitation, the prior delivery to the Company’s transfer agent and to the Secretary of the Company of a certificate signed by one or more shareholders owning more than 50% of the then outstanding Class A Shares. On November 1, 2023, the Company announced a normal course issuer bid (“2023 NCIB”) to commence on November 6, 2023 to purchase Class B Shares through the facilities of the TSX Venture Exchange ("TSXV") and alternative trading systems in Canada. As at November 5, 2024 the Company had repurchased for cancellation 70,200 Class B Shares at a weighted average price of CDN$4.38 pursuant to the 2023 NCIB. On November 15, 2024, the Company announced a normal course issuer bid (“2024 NCIB”) to commence on November 18, 2024 to purchase Class B Shares through the facilities of the TSXV and alternative trading systems in Canada. As at December 31, 2024 the Company had not repurchased any Class B Shares for cancellation pursuant to the 2024 NCIB. As at April 29, 2025 the Company has repurchased for cancellation 7,100 Class B Shares at a weighted average price of CDN$3.17 pursuant to the 2024 NCIB. 1,749,895 Class A Shares and 18,022,114 Class B Shares were outstanding as at December 31, 2024. 1,749,895 Class A Shares and 18,015,014 Class B Shares were outstanding as at April 29, 2025. See “Normal Course Issuer Bid and Dividends” in this MD&A. Orca Energy Group Inc. // Annual Report & Accounts 2024 Shareholders may obtain a copy of the notice regarding the 2024 NCIB filed with the TSXV from the Company without charge. Dividend Summary Declaration date Record date Payment date Amount per share (CDN$) February 14, 2025 March 31, 2025 April 14, 2025 0.10 November 12, 2024 December 31, 2024 January 14, 2025 0.10 August 21, 2024 September 30, 2024 October 14, 2024 0.10 May 15, 2024 June 28, 2024 July 12, 2024 0.10 February 1, 2024 March 29, 2024 April 12, 2024 0.10 Consolidation The companies which are being consolidated for the purposes of this MD&A are: Subsidiary Incorporated Holding Orca Energy Group Inc. British Virgin Islands Parent Company Orca Exploration UK Services Limited United Kingdom 100% PAE PanAfrican Energy Corporation Mauritius 100% PanAfrican Energy Tanzania Limited Jersey 100% 31 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Related Party Transactions The Chair of the Company’s Board of Directors is Counsel of Burnet, Duckworth & Palmer LLP, a law firm that provides legal advice to the Company and its subsidiaries. Fees for services provided by this firm totaled $0.1 million for the quarter ended December 31, 2024 (Q4 2023: $0.3 million) and $0.7 million for the year ended December 31, 2024 (year ended December 31, 2023: $0.8 million). As at December 31, 2024, the Company had a total of $0.05 million (December 31, 2023: $0.6 million) recorded in trade and other liabilities in relation to related parties. Normal Course Issuer Bid and Dividends On July 5, 2022 the Company announced a normal course issuer bid (“2022 NCIB”) to purchase Class B Shares through the facilities of the TSXV and alternative trading systems in Canada. Purchases pursuant to the 2022 NCIB were made by Research Capital Corporation (“Research Capital”) on behalf of the Company and were not to exceed 500,000 Class B Shares, representing approximately 2.75% of the total outstanding Class B Shares as of July 4, 2022. The 2022 NCIB was in effect from July 11, 2022 until July 11, 2023. An aggregate of 81,000 Class B Shares were repurchased and cancelled by the Company pursuant to the 2022 NCIB at a weighted average price per Class B Shares of CDN$4.89. On November 1, 2023 the Company announced the 2023 NCIB to purchase Class B Shares through the facilities of the TSXV and alternative trading systems in Canada. Purchases pursuant to the 2023 NCIB were made by Research Capital on behalf of the Company and were not to exceed 500,000 Class B Shares, representing approximately 2.76% of the total outstanding Class B Shares as of October 31, 2023. The 2023 NCIB was in effect from November 6, 2023 until November 5, 2024. Purchases of Class B Shares were made by Research Capital based on the parameters prescribed by the TSXV and applicable securities laws. The acquisition price of Class B Shares under the 2023 NCIB was not to exceed the market price of the Class B Shares at the time of acquisition and the funds available to acquire the Class B Shares were to come from the Company’s working capital and cash flow. All Class B Shares purchased under the 2023 NCIB were to be cancelled. As at November 5, 2024, being the last day of the 2023 NCIB, the Company had repurchased for cancellation 70,200 Class B Shares at a weighted average price of CDN$4.38 pursuant to the 2023 NCIB. On November 15, 2024 the Company announced the 2024 NCIB to purchase Class B Shares through the facilities of the TSXV and alternative trading systems in Canada. Purchases pursuant to the 2024 NCIB will be made by Research Capital on behalf of the Company and will not exceed 500,000 Class B Shares, representing approximately 2.77% of the total outstanding Class B Shares as of November 13, 2024. The 2024 NCIB is in effect from November 18, 2024 until the earlier of the purchase of the maximum number of Class B Shares or November 17, 2025. Purchases of Class B Shares under the 2024 NCIB are made by Research Capital based on the parameters prescribed by the TSXV and applicable securities laws. The acquisition price of Class B Shares under the 2024 NCIB will not exceed the market price of the Class B Shares at the time of acquisition and the funds available to acquire the Class B Shares will come from the Company’s working capital and cash flow. All Class B Shares purchased under the 2024 NCIB will be cancelled. As at December 31, 2024 the Company had not repurchased any Class B Shares for cancellation pursuant to the 2024 NCIB. As at April 29, 2025 the Company has repurchased for cancellation 7,100 Class B Shares at a weighted average price of CDN $3.17 pursuant to the 2024 NCIB. Orca Energy Group Inc. // Annual Report & Accounts 2024 Non-Controlling Interest The Company sold 7.933% (7,933 Class A common shares) of PAEM to a wholly owned subsidiary of Swala Oil & Gas (Tanzania) plc (“Swala TZ”), Swala (PAEM) Limited (“Swala UK”), in 2018 for $15.4 million cash and $4.0 million of Swala TZ’s preference phares (“Preference Shares”) pursuant to a share purchase agreement. The Preference Shares entitled the Company to a 10% per annum distribution payable 15 days after each quarter end commencing from the closing date, January 16, 2018. Payment of the quarterly distributions was at the discretion of Swala TZ based on funds available, however, the liability accrued if any amount was unpaid when due. For any distributable amount remaining unpaid at December 31, 2021, the Company could demand settlement and Swala TZ was obligated to comply by transferring and returning the Class A common shares of PAEM sold to Swala TZ. The aggregate value of these shares was to be equal tothe amount of the outstanding distributions. On April 3, 2023, Swala TZ announced that its creditors resolved that Swala UK be placed into liquidation at a creditors’ meeting held on March 31, 2023. On March 31, 2023, Apex Corporate Trustees (UK) Limited appointed representatives of Grant Thornton UK LLP as administrators of Swala UK. On July 21, 2023, the Company repurchased the 7.933% shares in PAEM held by Swala UK for $7.5 million and the non-controlling interest was therefore eliminated in 2023. Contingencies Taxation As at December 31 Amounts in $’millions 2024 2023 Area Period Reason for dispute Principal Interest and penalties Total Total Income tax 2008-09, 2011-20 Deductibility of capital expenditures and expenses (2012, 2015 and 2016), additional income tax (2008, 2011 and 2012), foreign exchange rate application (2013 to 2015, 2018 to 2020), underestimation of tax due (2014, 2016 and 2020) and methodology of grossing up income taxes paid (2015 to 2017). 21.8 15.9 37.7(1) 34.1 Tax on repatriated income 2012-21 Applicability of withholding tax on repatriated income (2012 to 2021) 21.4 5.7 27.1(2) 24.4 VAT 2012-23 VAT already paid (2012 to 2014), VAT on imported services (2015 and 2016); interest on VAT decreasing adjustments (2017), input VAT on services (2017 to 2020) and VAT on income tax and production taxes (2019 to 2023). 13.1 3.5 16.6(3) 1.5 56.3 25.1 81.4 60.0 During 2022, following the expiry of the statutory deadline for the Tanzanian Revenue Authority (“TRA”) to respond to the Company’s objections, the Company filed notices of intention to appeal to the Tanzania Revenue Appeals Board (“TRAB”) against the corporate income tax assessments for the years of 2012 to 2016, tax on repatriated income for the years of 2012 to 2014, and VAT for the years of 2015 to 2016. In May 2023, the TRA issued final corporate income tax assessments for the years of 2012 to 2016 agreeing to drop certain claims with respect to previously assessed corporate income tax for the years of income of 2012 and 2016. These claims are no longer represented in the table above. As of December 31, 2024, years of income of 2021 to 2024 remain open for audit.. Corporate income tax In 2024, the Company withdrew its application for the Court of Appeal of Tanzania (“CAT”) to review its judgment on the corporate income tax for the year of 2009 ($2.3 million). The matter is now marked withdrawn. Parties will now negotiate on the implementation of CAT’s judgment of 2018 in favor of TRA. At an earlier judgment, TRAB, while ruled in favour of the TRA, also allowed the Company to utilize the depreciation allowance, which was the issue in dispute, in subsequent years. The Company had already made provision in the accounts for the amount in dispute. In Q2 2022, the Tax Revenue Appeals Tribunal (“TRAT”) pronounced its judgment on the corporate income tax appeal for the year 2010 ($2.3 million) in favor of the TRA. The Company filed a notice of intention to appeal at the CAT. In Q3 2022, the Company filed a memorandum of appeal. The hearing took place on February 25, 2025 and was adjourned for a later date. The Company had already made provision in the accounts for the amount in dispute. In Q3 2023, the TRAT pronounced its judgment on the corporate income tax appeal for the year 2011 ($1.6 million) in favor of the TRA. The Company filed a notice of intention to appeal at the CAT. In Q4 2023, the Company filed a memorandum of appeal and is now awaiting a hearing date. In Q4 2023, the Company recorded a provision of approximately $0.3 million being the Company's share of the interest assessed. On January 31, 2025 and February 7, 2025 the Company’s appeals against the corporate income tax assessments for the years of 2012 and 2013 ($12.2 million) came for a hearing at TRAB. The hearing is ongoing and is now scheduled to continue in Q2 2025. In Q4 2022, the TRA issued six assessments for income tax and for ensuing interest on deemed delayed payments ($0.5 million) for the years of 2018 to 2020. The Company objected to the assessments on the grounds of incorrect disallowance of expenses and use of exchange rates. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q4 2023, the Company filed statements of appeal at the TRAB. In Q1 2024, the appeals were heard at the TRAB and the parties are now awaiting TRAB’s decision. D Management’ s Discussion & Analysis 32 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Tax on repatriated income In Q4 2023, during the TRAB hearing of the appeals against the notice of assessment for tax on repatriated income for the years of 2012 to 2013 ($11.6 million), the TRA was allowed to file a preliminary objection. In Q1 2024, the parties filed their written submissions. In Q1 2025, TRAB heard the appeals and the parties are now awaiting TRAB’s decision. The TRAB hearing of the appeal against the notice of assessment for tax on repatriated income for the year of 2014 ($3.8 million) is scheduled for May 8, 2025. In Q4 2022, the TRA issued seven assessments for tax on repatriated income ($11.7 million) for the years of 2015 to 2021. The Company objected to the assessments on the grounds of the assessments lacking merit; additionally, the assessments for the years of 2015 and 2016 were time-barred. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q4 2023, the Company filed statements of appeal at the TRAB. In Q1 2024, the parties filed their respective final written submissions and are awaiting TRAB’s decision. VAT On May 22, 2023, the TRAB pronounced its judgment on the VAT appeal for the years of 2015 and 2016 ($0.2 million) in favour of the Company. A written judgment is still pending. The TRA did not file a notice of intention to appeal at the TRAT by the statutory filing deadline. The Company continues to monitor actions taken by the TRA. In Q4 2022, the TRA issued an assessment for VAT ($0.1 million) for the years of 2019 and 2020. The Company objected to the assessment on the grounds that the TRA incorrectly disallowed input VAT on certain services. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q1 2024, the Company filed statements of appeal at the TRAB. In Q1 2024, the appeals were heard at the TRAB. Subsequently, the parties filed their written submissions and are now awaiting TRAB’s decision. On November 29, 2024 the TRA issued assessments for VAT ($14.9 million) for the years of 2019 to 2023. The Company objected to the assessments on the ground that the TRA incorrectly imposed VAT on a contractual adjustment made to the TPDC’s Profit Gas share and to the regulatory levy charged to customers. The Company is awaiting TRA’s determination of the objections. Management, with advice from its legal counsel, has reviewed the Company’s position on the objections and appeals related to the disputed amounts and has concluded that no further provision is required. However, if the TRA assesses the Company’s tax returns for open taxation years on a similar basis, the Company may be required to make future deposits to object such assessments. The process of appealing assessments issued by the TRA starts by initially filing an appeal with the TRA. If this is not successful, claims can be taken to higher authorities starting with the TRAB, followed by an appeal to the TRAT and finally to the CAT. Below is a summary of the status of the various assessments: (e) 2015-21 ($11.7 million): The Company appealed to the TRAB objecting to the TRA assessments for the year of income of 2015 ($1.9 million), 2016 ($1.9 million), 2017 ($1.6 million), 2018 ($1.1 million), 2019 ($1.6 million), 2020 ($1.1 million) and 2021 ($1.4 million) for being without merit and is awaiting TRAB’s judgment; (3) (a) 2012-16 ($0.2 million): The TRAB ruled in favour of the Company, parties are awaiting the written judgment. The TRA has not appealed the decision to the TRAT; (b) 2017-18 ($1.4 million): The Company filed an objection to a TRA assessment and is awaiting a response. The Company objected to incorrect imposition of interest on VAT decreasing adjustments in respect of delayed TANESCO payment ($1.2 million) and disallowing input VAT claimed in certain services ($0.1 million); (c) 2019-20 ($0.1 million): The Company appealed to the TRAB objecting to a TRA assessment on the grounds of incorrectly disallowing input VAT claimed and is awaiting TRAB’s judgment; (d) 2019-23 ($14.9 million): The Company has filed an objection to the TRA assessments and is awaiting a response. The Company objected to the imposition of VAT on a component of the profit sharing mechanism with TPDC and under the PSA and on the EWURA levy included in invoices to certain customers. 33 (1) (a) 2008 ($0.6 million): The Company objected to the TRA assessment that did not recognize a tax loss carried forward and is awaiting a response; (b) 2009 ($0.8 million): The Company objected to an amended assessment from the TRA for being time-barred and arbitrary and is awaiting a TRA response; (c) 2010 ($2.3 million): The TRAT ruled in favour of the TRA; CAT hearing took place on February 25, 2025 and was adjourned for a later date. The Company had already made provision in the accounts for the amount in dispute; (d) 2011 ($1.6 million): The Company is awaiting a CAT hearing date following the TRAT ruling in favour of the TRA; (e) 2012 ($10.2 million): The Company appealed to the TRAB objecting to the TRA assessment with respect to understated revenue and deductibility of capital expenditures and expenses. Hearing is ongoing; (f) 2013 ($2.0 million): The Company appealed to the TRAB objecting to the TRA assessment as being time-barred and without merit. Hearing is ongoing; (g) 2014 ($5.5 million): The Company appealed to the TRAB objecting to the TRA assessment on the ground that the TRA assessment incorrectly disallowed certain expenses and applied erroneous foreign exchange rates. Hearing is scheduled for May 8, 2025; (h) 2015-16 ($9.0 million): The Company appealed to the TRAB as to TRA’s assessments on the ground that the TRA assessments failed to recognize provisional tax payments, incorrectly disallowed capital expenditures and certain expenses and applied erroneous foreign exchange rates; (i) 2017 ($7.4 million): The TRA issued an assessment for corporation tax which questioned the Company’s methodology of grossing up already paid corporation tax ($6.5 million) and raised the issue of imposing interest on deemed delayed payment ($0.1 million). The Company filed an objection and is awaiting the TRA’s response; (j) 2018 ($0.02 million): The Company appealed to the TRAB objecting to the TRA’s assessment on the grounds that the TRA incorrectly disallowed certain expenses and applied erroneous foreign exchange rates. The Company is awaiting TRAB’s judgment; (k) 2018-20 ($0.6 million): The Company appealed to the TRAB objecting to the TRA assessment on the ground that the TRA incorrectly disallowed certain expenses and failed to recognise payments already made. The Company is awaiting TRAB’s judgment; (2) (a) 2012 ($3.3 million): The Company objected to the TRA assessment as being without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; (b) 2013 ($8.3 million): The Company objected to the TRA assessment as being time-barred and without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; (c) 2014 ($3.8 million): The Company objected to the TRA assessment as being without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; Orca Energy Group Inc. // Annual Report & Accounts 2024 In 2016, the TRA introduced significant changes in relation to the income tax treatment of the extractive sector with separate new chapters in Part V of the Income Tax Act 2004 (“ITA, 2004”) for mining and for petroleum to be effective commencing in 2018. Further changes were subsequently made by the Written Laws (Miscellaneous Amendments) Act, 2017 (“WLMAA, 2017”) and in particular section 36(a)(ii) of the WLMAA, 2017. The WLMAA, 2017 amended sections 65M and 65N of the ITA, 2004 to exclude cost oil/cost gas from inclusion in both income and expenditure. The Company continues to review the tax effects of the changes as there are a number of uncertainties and ambiguities as to the interpretation and application of certain provisions of the WLMAA, 2017. In the absence of guidance on these matters, the Company has used what it believes are reasonable interpretations and assumptions in applying the WLMAA, 2017 for purposes of determining its tax liabilities and the results of operations, which may change as it receives additional clarification and implementation guidance. The Company does not expect a significant impact from the changes as it is able to recover taxes payable from the TPDC Profit Gas revenue entitlement under the terms of the PSA. 34 Orca Energy Group Inc. // Annual Report & Accounts 2024 Accounting Changes The following pronouncements from the International Accounting Standards Board (“IASB”) became effective or were amended for financial reporting periods beginning on or after January 1, 2024. There has been no impact on the Company. • Lease Liability in a Sale and Leaseback – Amendments to IFRS 16 Leases • Classification of liabilities as Current or Non-Current and Non-current Liabilities with Covenants – Amendments to IAS 1 Presentation of Financial Statements • Amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures – Supplier Finance Arrangements The following standards have been issued but are not yet effective: • Lack of Exchangeability – Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates • Amendments to the Classification and Measurement of Financial Instruments – Amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures • Annual Improvements to IFRS Accounting Standards – Amendments to: o IFRS 1 First-time Adoption of International Financial Reporting Standards; o IFRS 7 Financial Instruments: Disclosures and its accompanying Guidance on implementing IFRS 7; o IFRS 9 Financial Instruments; o IFRS 10 Consolidated Financial Statements; and o IAS 7 Statement of Cash flows • Contracts Referencing Nature-dependent Electricity – Amendments to IFRS 9 and IFRS 7 • IFRS 18 Presentation and Disclosure in Financial Statements • IFRS 19 Subsidiaries without Public Accountability: Disclosures The Company intends to adopt these standards when they become effective and is currently evaluating the potential impact. Disclosure Controls and Procedures and Internal Controls over Financial Reporting The Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”) for Orca. DC&P, as defined in National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian securities law and include controls and procedures designed to ensure that information required to be so disclosed is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure. The CEO and CFO of Orca evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on the evaluation, the officers concluded that Orca’s DC&P were effective as at December 31, 2024. Quarterly Results Summary The following is a summary of key results for the Company for the last eight quarters: Figures in $’000 except where otherwise stated Q4 2024 Q3 Q2 Q1 Q4 2023 Q3 Q2 Q1 Revenue 36,855 24,787 25,014 24,937 24,448 27,374 28,006 30,407 Net (loss) / income attributable to shareholders (25,821) 2,086 1,188 969 (438) 256 3,282 3,914 (Loss) / earnings per share – basic and diluted ($) (1.31) 0.10 0.06 0.06 (0.02) 0.01 0.17 0.19 Net cash flows from operating activities 6,254 10,255 16,747 (6,170) 9,858 14,995 16,160 7,472 Capital expenditures 14,869 9,354 1,912 1,470 2,065 2,928 1,405 1,705 Management’ s Discussion & Analysis 35 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Revenue decreased in Q2 2023 as a result of a decrease in sales to both the industrial sector and the power sector partially offset by a decreased TPDC share of revenue. Revenue decreased in Q3 2023 as a result of an increased TPDC share of revenue. Revenue decreased in Q4 2023 as a result of a decrease in sales to the industrial sector, an increase in TPDC share of revenue and a lower current income tax adjustment. Revenue increased in Q1 2024 as a result of an increase in sales to the industrial sector and decreased TPDC share of revenue, partially offset by a decrease in sales to the power sector and a lower current income tax adjustment. Revenue increased in Q2 2024 as a result of a decrease of TPDC share of revenue and a higher current income tax adjustment, partially offset by a decrease in sales to the power and industrial sectors. Revenue decreased in Q3 2024 primarily as a result of a lower current income tax adjustment and the revenues from gas deliveries to Songas in August and September not meeting revenue recognition criteria under IFRS 15. Revenue increased in Q4 2024 as a result of a decrease of TPDC share of revenue and a higher current income tax adjustment, partially offset by a decrease in sales to the industrial sector. Net (loss) / income attributable to shareholders was affected by several factors, other than changes in revenue, including: • the decrease in Q2 2023 was a result of higher general and administrative and finance expenses; • the decrease in Q3 2023 was a result of lower reversal of loss allowance for receivables, an expense in relation to the Long Term Retention Plan and a higher foreign exchange loss; • the decrease in Q4 2023 was a result of a higher depletion expense; • the increase in Q1 2024 was a result of a lower depletion expense, partially offset by a reversal of allowance in the previous quarter; • the increase in Q2 2024 was a result of a lower depletion expense, higher deferred income tax recovery and a lower APT expense, partially offset by a higher finance expense; • the increase in Q3 2024 was a result of lower G&A and finance expenses; and • the decrease in Q4 2024 was a result of recording of (i) asset impairment of $25.9 million with respect to the SS-7 well workover program, and (ii) loss allowance of $21.7 million with respect to ongoing litigation. In addition to the factors impacting net income attributable to shareholders, net cash flows from operating activities were primarily affected by the timing and amount of payments received from TANESCO. The increase in Q2 2023 was primarily a result of the changes in the non-cash working capital, namely the decrease in trade and other receivables. Similarly, the decrease in Q3 2023 was primarily a result of the changes in the non-cash working capital, namely the decrease in trade and other payables. The decrease in Q4 2023 was primarily a result of the changes in the non-cash working capital, namely the increase in trade and other receivables. The decrease in Q1 2024 was primarily a result of the annual 2023 current liability associated with APT paid in Q1 2024. The increase in Q2 2024 was primarily a result of the changes in the non-cash working capital, namely the decrease in trade and other receivables. The decreases in Q3 2024 and Q4 2024 were primarily a result of the increases in trade and other receivables. Capital expenditures in Q1, Q2 and Q3 2023 were mainly related to the 3D seismic acquisition program. Capital expenditures in Q4 2023 and Q1, Q2, Q3 and Q4 2024 were mainly related to well workover activities. Selected Annual Financial Information Selected annual financial information derived from the audited consolidated financial statements for the years ended December 31, 2024, 2023 and 2022 is set out below: Figures in $’000 except per share amount 2024 2023 2022 Revenue 111,593 110,235 118,089 Net (loss) / income attributable to shareholders (21,578) 7,014 27,726 (Loss) / earnings – basic and diluted ($ per share) (1.09) 0.35 1.39 Cash dividends declared (CDN$ per Class A and B Shares) 0.40 0.40 0.40 Net cash flows from operating activities 27,086 48,485 67,660 Total non-current liabilities 10,695 58,036 81,378 Total assets 185,766 215,431 248,083 The 7% decrease of revenue in 2023 compared to 2022 was primarily a result of higher TPDC share of revenue as an outcome of decreased capital expenditures and lower Cost Gas revenue. This was partially offset by higher sales to the power sector. The 1% increase of revenue in 2024 compared to 2023 was primarily a result of a lower TPDC share of revenue partially offset by decreased sales to the power sector. The decrease in net income attributable to shareholders in 2023 was a result of the decreased revenue, increased depletion expense and higher net foreign exchange loss. The decrease in net income attributable to shareholders in 2024 was a result of the asset impairment and the loss allowance. In 2024, 2023 and 2022, the Company approved quarterly dividends, CDN$0.10 per share for Q1, Q2, Q3 and Q4 in each of 2024, 2023 and 2022. Please refer to the table in the "Normal Course Issuer Bid and Dividends" section of this MD&A. The changes in net cash flows from operating activities are primarily related to the changes in non-cash working capital primarily associated with variations in prepayments, trade and other receivables and trade and other liabilities. 36 Orca Energy Group Inc. // Annual Report & Accounts 2024 The $23.3 million decrease in total non-current liabilities in 2023 compared to 2022 was primarily a result of the payment of a portion of the APT and the repayment of the Loan. The $47.3 million decrease in total non-current liabilities in 2024 compared to 2023 was primarily a result of the payment of a portion of the APT, further repayment of the Loan and maturing of the outstanding Loan principal. Total assets decreased by 13% in 2023 compared to 2022 mainly as a result of depletion of capital assets including one time accelerated depletion of costs related to the 3D seismic acquisition and processing program. Total assets decreased by 14% in 2024 compared to 2023 mainly as a result of depletion of capital assets and well as one-time asset impairment with respect to the well workover program. 37 Orca Energy Group Inc. // Annual Report & Accounts 2024 Non-GAAP Financial Measures and Ratios In this MD&A, the Company has disclosed the following non-GAAP financial measures, non-GAAP ratios and supplementary financial measures: capital expenditures, operating netback, operating netback per mcf, working capital, net cash flows from operating activities per share and weighted average Class A and Class B Shares. These non-GAAP financial measures and ratios disclosed in this MD&A do not have any standardized meaning under IFRS and may not be comparable to similar financial measures disclosed by other issuers. These non-GAAP financial measures and ratios should not, therefore, be considered in isolation or as a substitute for, or superior to, measures and ratios of Company’s financial performance defined or determined in accordance with IFRS. These non-GAAP financial measures and ratios are calculated on a consistent basis from period to period. Non-GAAP Financial Measures Capital expenditures Capital expenditures is a useful measure as it provides an indication of our investment activities. The most directly comparable financial measure is net cash from (used in) investing activities. A reconciliation to the most directly comparable financial measure is as follows: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Pipelines, well workovers and infrastructure 14,869 2,067 27,233 7,984 Other capital expenditures – (2) 315 119 Capital expenditures 14,869 2,065 27,548 8,103 Right of use – 852 57 852 Change in non-cash working capital (4,125) (708) (9,645) (161) Net cash used by investing activities 10,744 2,209 17,960 8,794 Operating netback Operating netback is calculated as revenue less processing and transportation tariffs, TPDC’s revenue share, and operating and distribution costs (see “Operating Netback” in this MD&A). The operating netback summarizes all costs that are associated with bringing the gas from the Songo Songo gas field to the market, and is a measure of profitability. A reconciliation to the most directly comparable financial measure is as follows: Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Revenue 36,855 24,448 111,593 110,235 Production, distribution and transportation expenses (5,265) (4,576) (19,990) (19,197) Net Production Revenue 31,590 19,872 91,603 91,038 Less current income tax adjustment (recorded in revenue) (8,061) (2,896) (12,817) (16,527) Operating netback 23,529 16,976 78,786 74,511 Sales volumes MMcf where revenue is recognized 6,604 7,435 25,185 31,256 Netback $/mcf 3.56 2.28 3.13 2.38 Non-GAAP Ratios Operating netback per mcf Operating netback per mcf represent the profit margin associated with the production and sale of Additional Gas and is calculated by taking the operating netback and dividing it by the volume of Additional Gas delivered and sold. This is a key measure as it demonstrates the profit generated from each unit of production. Songas has invoiced PAET for the production and transportation tariff consistent with all gas volumes shipped to Songas during August, September and October 2024 as being treated as Additional Gas. This amount has been fully accounted for and paid by PAET in accordance with the terms of the current agreements and forms part of the operating netback calculation above. Supplementary Financial Measures Working capital Working capital is defined as current assets less current liabilities, as reported in the Company’s Consolidated Statements of Financial Position. It is an important measure as it indicated the Company’s ability to meet its financial obligations as they fall due. Net cash flows from operating activities per share Net cash flows from operating activities per share is calculated as net cash flows from operating activities divided by the weighted average number of shares, similar to the calculation of earnings per share. Net cash flow from operations is an important measure as it indicates the cash generated from the operations that is available to fund ongoing capital commitments. 38 Orca Energy Group Inc. // Annual Report & Accounts 2024 Weighted average Class A and Class B Shares In calculating the weighted average number of shares outstanding during any period, the Company takes the opening balance multiplied by the number of days until the balance changes. It then takes the new balance and multiplies that by the number of days until the next change, or until the period end. The resulting multiples of shares and days are then aggregated and the total is divided by the total number of days in the period. Use of Estimates and Judgments The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. The reader is referred to Orca’s December 31, 2024 audited consolidated financial statements for a description of estimates and judgments. Business Risks Contractual, regulatory and legal License extension The principal asset of the Company is its indirect interest in the Songo Songo gas field under the PSA between PAET, TPDC and GoT. The PSA covers the production and marketing of natural gas from the Songo Songo gas field. The Company has the right to conduct petroleum operations on certain specified blocks within the Songo Songo gas field, market and sell all Additional Gas produced and share the net revenue with TPDC for a term of the development license of 25 years, expiring in October 2026. Under the PSA, the Company may submit a request to TPDC to apply for an extension of the License, and TPDC has a contractual obligation to seek an extension at PAET’s request. TPDC is required to make this application promptly upon a request by the Company. Upon receipt of this application, the MoE will, in consultation with the PURA, consider such request on its own merit and respond accordingly, subject to the license holder not being in default and approval of the Tanzanian Cabinet. On April 14, 2023, PAET formally requested TPDC to apply for an extension of the License. In November 2024, TPDC submitted the application for the extension of the License to the MoE, however, being uneconomical, the Company informed TPDC that it did not agree with the terms as submitted. Having declined to address PAET’s concerns itself, TPDC has advised PAET to raise any issues directly to the MoE. On August 7, 2024, PAET and PAEM, issued the Notice of Dispute in respect of an investment treaty claim under the BIT against the GoT for breach of the BIT, alongside notifying a contractual dispute against the GoT and TPDC for breaches of the PSA and the Gas Agreement, for damages in excess of $1.2 billion. For further details of the Notice of Dispute, see "Outcome of the Notice of Dispute" below. Given the conduct of TPDC and the GoT to date, there is no certainty that the License will be extended, and if there is an extension of the License the terms that will be granted under the extended License. The Company cannot predict the timing for when the License will be extended, if it will be extended, the terms of such extension, or the costs associated with seeking such extension. Failure to extend the License could result in negative publicity and adversely affect the price of our Shares and relationships in Tanzania. In addition, efforts to extend the License distract management and other personnel from their primary responsibilities. Should the License not be extended beyond October 10, 2026, the Company’s estimated proved reserves will continue to decline to zero by October 10, 2026. Outcome of the Notice of Dispute On August 7, 2024, PAET and PAEM, issued the Notice of Dispute in respect of an investment treaty claim under the BIT against the GoT for breach of the BIT, alongside notifying a contractual dispute against the GoT and TPDC for breaches of the PSA and the Gas Agreement, for damages in excess of $1.2 billion. Initial meetings with both the Advisory and Coordinating Committees were held during the week of October 14, 2024 without any resolution on the key issues in dispute. The matters have been further referred to the relevant entity’s chief executive officers and working groups in accordance with the dispute resolution process. Discussions have since continued with the most recent meetings being held during March 2025. Further updates on this matter will be made as appropriate. The Company cannot predict the outcome of proceedings relating to the Notice of Dispute with certainty, the costs associated with proceedings related to the Notice of Dispute, and possible awards of damages relating to the Notice of Dispute. Further the Company cannot predict if we are unsuccessful in the proceedings relating to the Notice of Dispute, the effect it will have on our business, and whether this will have a material adverse effect on the Company’s business and operations. The Notice of Dispute proceedings could result in negative publicity and adversely affect the price of our Shares and relationships in Tanzania. In addition, the Notice of Dispute proceedings distract management and other personnel from their primary responsibilities. There is a risk of a continuing action relating to the Notice of Dispute post October 2026, the current date on which the License will expire. Outcome of the litigation with seismic contractor On October 25, 2023, the Company terminated the contract with the contractor responsible for the 3D seismic acquisition program on the basis that the contractor had failed to meet its obligations under the contract by not fully mobilising to progress the project more than a year after it was scheduled to do so; and that, as a result of mission critical assets being recalled by suppliers, and with no prospect of securing replacement assets, the contractor had unilaterally suspended its operations without the right to do so and with no realistic plan offered to complete the project. On March 20, 2024 PAET received a summons from the High Court of Tanzania (Commercial Division) to file a written statement of defense against a claim made by the contractor for losses arising from PAET’s termination of the contract. The contractor sought to claim $30.0 million for losses incurred plus legal costs, interest and general damages. In Q2 2024, the Company in consultation with its legal advisors lodged its own counterclaim for specific damages in the amount of $5.5 million and general damages in the amount of $25.8 million. In February 2025, the Company received the Judgment from the Court relating to the claim brought by a contractor against PAET. Pursuant to the Judgment, the Court ordered specific and general damages in the aggregate of $23.1 million, plus legal costs and interest at a rate of 7% per annum be paid by PAET to the contractor. PAET respectfully disagrees with the Judgment and has initiated the appeal process. PAET was required to post security for the full amount of the judgment until the appeal is resolved. The Company has treated the Judgment as an adjusting event to the 2024 financial statements and recognised the resulting liability in 2024. 39 Orca Energy Group Inc. // Annual Report & Accounts 2024 The Company cannot predict the outcome of the appeal, the costs associated with the appeal, and damages, if any, relating to the appeal. Further the Company cannot predict if we are unsuccessful in the appeal, the effect it will have on our business, the timing of the outcome of the appeal, and whether this will have a material adverse effect on the Company’s business and operations. Legal proceedings could result in a substantial liability and/or negative publicity and adversely affect the price of our Shares and relationships in Tanzania. In addition, legal proceedings distract management and other personnel from their primary responsibilities. Should any payment eventually be required, the Company anticipates it will be cost recoverable under the PSA. However there is a risk of a continuing action relating to the appeal post October 2026, the current date on which the License will expire. Tax disputes We have a number of ongoing disputes ranging from 2008 to 2023 with the TRA, most of which haven’t been resolved historically in favour of any of the parties. There has been little, if any, progress with respect to resolution of these disputes. Most, if not all, of these disputes may survive the PSA, particularly in case that there is no extension of the License. There is a risk of a continuing litigation relating to these disputes post October 2026. The Company cannot predict the outcome of these disputes, the costs associated with these disputes. Further the Company cannot predict if we are unsuccessful in any of these disputes and the effect they will have on our business. Each dispute could result in a liability and adversely affect the price of our Shares. In addition, these disputes distract management and other personnel from their primary responsibilities. We have had, and continue to have, disagreements with TPDC regarding certain of our rights and responsibilities under the PSA All of our proved reserves are located onshore and offshore Tanzania. The PSA and other material contracts to which we are a party relate to the Songo Songo gas field, and the activities and commercial arrangements that form the basis of our current operations in Tanzania. Pursuant to these petroleum contracts, most significant decisions, including our plans for development and annual work programs, must be submitted to TPDC for comment. We have previously had, and continue to have, disagreements with TPDC and the GoT regarding Protected Gas. Our belief is Protected Gas ceased after July 31, 2024, TPDC has taken the position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas ceased after July 31, 2024. There can be no assurance that all of these disagreements will be resolved in our favour or that future disagreements will not arise in Tanzania. Our uncertainty in respect of payment by counterparts for Additional Gas The PSA defines the gas produced from the Songo Songo gas field as “Protected Gas” and “Additional Gas”. Until its cessation, Protected Gas was owned by TPDC and was sold under the Gas Agreement to Songas. Protected Gas ceased after July 31, 2024. Under the terms of the PSA, following the cessation of Protected Gas, all gas from the Songo Songo gas field is classified as Additional Gas, which PAET is entitled to sell on commercial terms until the PSA expires in October 2026. It is our belief that PAET will be entitled to compensation at a commercial rate for all volumes of gas lifted by Songas starting on August 1, 2024. Uncontracted gas continued to flow post August 1, 2024 to October 31, 2024, and there is a risk that PAET will not receive payment for such uncontracted gas, or payment may form part of a contract dispute. There can be no assurance that PAET will receive all or any payment in respect of the uncontracted gas being supplied from August 1, 2024 to October 31, 2024, and if any payment is received, timing as to when payment is received. The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results We may be liable for certain unascertainable costs if third parties who contract with us are unable to meet their contractual commitments. In Tanzania, we are dependent on TPDC for access and operation of the National Natural Gas Infrastructure (“NNGI”) and to Songas for access to the Songas Facilities. If access is limited by either party being unable (or unwilling) to meet their contractual obligations, this would impact our ability to meet our contractual delivery of Additional Gas. See “Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production.” In addition, we contract with third parties to conduct drilling and related services on our producing assets and development projects. Such third parties may not perform the services they provide us with on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our activities caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs and cause an adverse effect on our business, financial position and results of operations. In Tanzania, our principal exposure to credit risk will be through receivables resulting from the sale of Additional Gas. The inability or failure of our significant customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. This includes our ability to meet our interest and principal repayment obligations under the Loan. The Company is unable to predict sudden changes in the creditworthiness of our customers. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses. See “Risks associated with the collectability of receivables could adversely affect our business”. Contractual We operate in a litigious environment which could result in title or contractual disputes during the ordinary course of business. The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results. Legislation The GoT has passed several new laws in the past eight years impacting the Company’s operation in Tanzania. The National Energy Policy (2015) and the Petroleum Act, passed in 2015 provided regulatory framework over upstream, mid-stream and downstream gas activity. The Petroleum Act created PURA, a new regulator to oversee the upstream sectors and conferred upon TPDC the status of “National Oil Company” as the sole aggregator of natural gas in the country. Article 260(3) of the Petroleum Act preserves the Company’s pre-existing right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party natural gas customers. There remain differences of opinion between the Company and TPDC on the effect of certain provisions within the Petroleum Act and their application to the Company. 40 Orca Energy Group Inc. // Annual Report & Accounts 2024 On October 7, 2016, the GoT issued the Petroleum (Natural Gas Pricing) Regulation made under Sections 165 and 258(I) of the Petroleum Act, which may give rise to additional uncertainty. Changes resulting from this regulation could impact the Company’s ability to set gas pricing and the introduction of regulated gas pricing could result in operations becoming uneconomical and anticipated revenues could be materially affected. While the PSA has been grandfathered under the Petroleum Act, we can provide no assurances that this situation will remain unchanged in the future. On July 15, 2017, the GoT passed into law the Natural Wealth and Resources (Permanent Sovereignty) Act, 2017, the WLMAA, 2017, and the Natural Wealth and Resources Contracts (Review and Re-Negotiation of Unconscionable Terms) Act, 2017 (“NWRCA”). The first and second of these acts are forward looking and only apply to agreements entered into on or after July 15, 2017. The GoT may argue that the NWRCA has retrospective effect in terms of its ability to renegotiate pre-existing contracts. On January 31, 2020, the government released the Natural Wealth and Resources Contracts (Review and Renegotiation of Unconscionable Terms) Regulations, 2020 which set out further guidance as to how contracts may be renegotiated. These acts contain new regulations including but not limited to regulations that all arbitration processes must be heard within Tanzania and potentially restrict the ability to move funds out of Tanzania. In 2016, the TRA introduced significant changes to the income tax treatment of the extractive sector with separate new chapters in Part V of the ITA, 2004 for mining and for petroleum to be effective commencing in 2018. Subsequent to this, further changes were made by the WLMAA, 2017 to exclude cost oil/cost gas from inclusion in both income and expenditure. We are still evaluating the tax effects of the changes as there are a number of uncertainties and ambiguities as to the interpretation and application of certain provisions of the WLMAA, 2017 as there is an absence of regulations and guidance from TRA on the implementation of the changes. In the absence of guidance on these matters, we will continue to use what we believe are reasonable interpretations and assumptions in applying the WLMAA, 2017 for purposes of determining our tax liabilities and filing our tax returns, which interpretations and assumptions may change as we receive additional clarification and implementation guidance. As necessary, we will seek adjustments to the PSA to preserve our economic benefits. In addition, the Natural Wealth and Resources (Permanent Sovereignty) Act, 2017 and the WLMAA 2017 restrict the ability of companies to repatriate funds out of Tanzania and it is possible that the GoT will seek to argue at some stage that these provisions apply to the Company even though the Company’s contracts with the GoT permit the repatriation of funds out of Tanzania. Intervening policy and legislative changes such as those described above may conflict with our pre-existing rights under the PSA and other agreements, though it remains unclear how such legislative actions will be implemented and whether and to what extent they will impact us. We are unable to predict what legislation may be proposed that might affect our business or when any such proposals, if enacted, might become effective. Such changes could require increased capital and operating expenditure and could prevent or delay certain of our operations. If, for reasons beyond our control, we are unable to maintain compliance with any legislative changes, whether in the future or past, we may have to cease operations in certain locations. Foreign operations and concentration Our asset concentration, operational dependence and the local focus of our existing contracts may have a material impact on our ability to operate profitably Our Tanzanian operations are anticipated to be our sole source of our near-term revenue earnings. Due to our asset concentration, the success of our operations is dependent on positive commercial relationships with a small number of organizations (including state and parastatal organizations) and certainty with respect to our rights and obligations arising from those relationships. Given our belief that Protected Gas ceased after July 31, 2024 under the Gas Agreement, and TPDC's position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas ceased after July 31, 2024, our ongoing relationship with TPDC is uncertain. Furthermore, due to our asset concentration and operational dependence, damage to our reputation within the jurisdictions in which we currently or may in the future operate due to the actual or perceived occurrence of any number of events, such as environmental incidents, could negatively impact us. Reputation loss may result in negative publicity and diminished or adversarial stakeholder relationships, which could lead to increased challenges in developing and maintaining community relations, decreased investor confidence, and would likely impede our overall ability to advance our projects, thereby having a material adverse impact on financial performance, cash flows and growth prospects. Additionally, the Company's natural gas reserves are currently limited to one producing property, the Songo Songo gas field, and the productive potential from this field is limited. There is no assurance that the Company will have sufficient deliverability through existing wells. In addition, any difficulties relating to the operation and performance of the Songo Songo gas field would have a material adverse effect on the Company. A loss or material reduction in production capabilities will have a material adverse effect on the total production and funds flow from operating activities of the Company, Access to infrastructure The Company is dependent upon access to the Songas Infrastructure and the GoT owned NNGI to deliver gas to customers. The Company operates the Songas Infrastructure however Songas is the owner of the facilities including the 12-inch subsea and the 16-inch surface pipeline systems which transport natural gas from Songo Songo Island to Dar es Salaam. There are agreements in place to allow the Company to process and transport gas, but there is no assurance that these rights could not be challenged or access curtailed. The inability to access infrastructure would materially impair the Company’s ability to realize revenue from natural gas sales. Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of processing facilities and other infrastructure, owned and operated by third parties. Our failure to obtain access to such facilities on acceptable terms could materially harm our business. We may be required to shut in production due to the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until alternative arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations. In addition, the shutting in of wells can lead to mechanical problems when attempting to bring production back on-line, and this results in decreased production and increased remediation costs. Additionally, the future exploitation and sale of natural gas will be subject to the availability of commercial processing facilities and marketing of these products, which will in turn be dependent upon the contracting, financing, construction and operating of infrastructure by ourselves or third parties, the relationships and agreements related to which can, at times, be uncertain. iscussion & 41 Orca Energy Group Inc. // Annual Report & Accounts 2024 Our operations may be adversely affected by political, social and economic circumstances We operate, and may in the future operate, in foreign jurisdictions that may be considered politically and/or economically unstable. We are also subject to foreign laws and regulations that themselves may change in response to shifting political and economic circumstances. Through our operations in foreign jurisdictions, we may become subject to risks that are materially different than those present in markets with better established and more mature hydrocarbon industries. Such risks include (but are not necessarily limited to): • the renegotiation, cancellation or forced modification of existing contracts and production sharing agreements; • expropriation, whether direct or indirect, including by confiscatory tax regimes or other regulatory actions, or nationalization of property; • lack of certainty with respect to intellectual property; • changes in laws or policies or increasing legal and regulatory requirements of particular countries, such as those relating to taxation, royalties, imports, exports, duties, currency, in-country beneficiation or other claims by government entities, including retroactive claims and/or changes in the administration of laws, policies and practices; • uncertain political, legislative and economic environments, war, terrorism, sabotage and civil disturbances, territorial disputes and insurrection; • lack of certainty with respect to foreign legal systems, corruption and other factors that are inconsistent with the rule of law; • counterfeiting; • exchange controls; • delays or inability to obtain or maintain necessary government permits or to operate in accordance with such permits or regulatory requirements; • currency fluctuations; • restrictions on the ability of local operating companies to sell products for foreign currency, and on the ability of such companies to hold foreign currencies in offshore bank accounts; • import and export regulations, including restrictions on the export of hydrocarbons; • restrictions on the repatriation of earnings and various other foreign exchange restrictions; • reliance on advisors and consultants in foreign jurisdictions in connection with regulatory, permitting or other governmental requirements; and • increased financing costs. Our operations in these areas also increase our exposure to risks of war, local economic conditions, political disruption, civil disturbance, expropriation, piracy, tribal conflicts and governmental policies that may: • disrupt our operations; • require us to incur greater security costs; • restrict the movement of funds or limit repatriation of profits; • lead to international sanctions from overseas governments; or • limit access to markets for periods of time. The regions in which we operate, and may in the future operate, have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future, and losses caused by these disruptions and not covered by insurance may occur. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. Country risk The geographic location of the Songo Songo gas field offshore Tanzania exposes us to an increased risk of loss of revenue or curtailment of production as a result of factors generally associated with foreign operations or arising from factors specifically affecting the area in which we operate or may operate. Tanzania may be considered to be politically and/or economically unstable. Development and operational activities in Tanzania may require protracted negotiations with host governments, national oil companies and third parties, and are frequently subject to economic and political considerations, such as, the risks of war, actions by terrorist or insurgent groups, expropriation, nationalization or emerging nationalization, renegotiation or nullification of existing contracts and production sharing agreements, taxation policies, foreign exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign governmental regulations that favour or require the award of drilling and construction contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In addition, if a dispute arises with foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts. In Tanzania the state retains ownership of its minerals and consequently retains control of the exploration and production of hydrocarbon reserves. The GoT has historically been supportive of foreign investment in resource development projects in Tanzania however it has recently adopted a more conservative approach toward foreign involvement in the extractive sector, including the production, transmission, processing and marketing of natural gas. Factors such as changes in government, an increased nationalist sentiment and pressure to preserve development opportunities for local enterprises can result in legal and regulatory changes that can impact our ability to maintain our business operations. 42 Orca Energy Group Inc. // Annual Report & Accounts 2024 Countries in Africa may lack the resources to effectively contain outbreaks of disease quickly. Such outbreaks if uncontained, may impact our ability to explore for natural gas, develop or produce our license areas by limiting access to qualified personnel, increase costs associated with ensuring the safety and health of our personnel, restricting transportation of personnel, equipment, supplies and natural gas production to and from our areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies. If travel bans are implemented or extended to the countries in which we operate, or contractors or personnel refuse to travel to such locations, we could be adversely affected. If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow. We may be exposed to liabilities under anti-money laundering and/or anti-corruption laws, and any determination that we violated such laws could have a material adverse effect on our business We are subject to laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage. We do business, and may do additional business in the future, in countries and regions in which we may face, directly or indirectly, corrupt demands by officials. We face the risk of unauthorized payments or offers of payments by one of our employees, contractors or consultants or accusations by government authorities or local citizens or other organizations that our employees, contractors or consultants have made or offered such payments. Our existing safeguards and any future improvements may prove to be less than effective in preventing such unauthorized payments, and our employees and consultants may engage in conduct for which we might be held responsible. Violations of such laws may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the United States, United Kingdom and Canadian governments may seek to hold us liable for successor liability under their anticorruption laws for violations committed by companies in which we invest in (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire. Corruption remains an issue in Tanzania. Tanzania ranked 82 out of 180 countries on the 2024 Transparency International Corruption Index, with a score of 41/100. On the 2019 World Bank’s Ease of Doing Business Index, Tanzania ranked 144/190 countries, with a score of 53.63 (the regional average for Sub- Saharan Africa is 51.61). At the end of 2014, there was a significant corruption scandal in Tanzania’s energy sector involving a number of senior government officials. There can be no assurance that corruption may not indirectly affect or otherwise impair the Company’s ability to operate in Tanzania and effectively pursue its business plan in that country. Industry and business conditions Competition and operational risk The natural gas industry is intensely competitive and the Company competes with other companies which possess greater technical and financial resources. Natural gas drilling and production operations are subject to all the risks typically associated with such operations, including but not limited to risks of fires, blowouts, spills, cratering and explosions, mechanical and equipment problems, uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials, marine hazards with respect to offshore operations, formations with abnormal pressures, adverse weather conditions, natural or man-made disasters, premature decline of reservoirs and invasion of water into producing formations. Drilling wells is speculative and involves significant costs that may be more than estimated and may not result in any discoveries or additions to our future production or reserves. Operational activities have numerous inherent risks and our license area is located on an island, 25 km offshore mainland Tanzania, and partially in shallow water. This generally increases the operating costs, chances of delay, planning time, technical challenges and risks associated with production activities. Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to natural gas markets or delay our natural gas production. The development of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns. The Company may be affected by the inability to respond to changing technological developments and remain competitive. Slower economic growth rates may materially adversely impact our operating results and financial position. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business. Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters: • licenses for drilling operations; • tax increases, including retroactive claims; • unitization of oil accumulations; • local content requirements (including the mandatory use of local partners and vendors; and • safety, health and environmental requirements, liabilities and obligations, including those related to remediation, investigation or permitting. Under these and other laws, regulations and the terms of our material contracts, we could be liable for personal injuries, property, environmental and other types of damages. Failure to comply with these laws, regulations and certain of our contractual obligations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct, and may in the future conduct, the majority of our operations, where there could be a lack of clarity or lack of consistency in the application of these laws, regulations and the interpretation of contractual obligations, if any. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations. 43 Orca Energy Group Inc. // Annual Report & Accounts 2024 Marketability, pricing and contract management The marketability and price of natural gas which may be acquired, discovered or marketed by the Company will be affected by numerous factors beyond its control. The natural gas market in Tanzania is developing and there is currently limited access to infrastructure with which to serve potential new markets beyond that being constructed by the Company, Songas and TPDC. The ability of the Company to market any natural gas from current or future reserves in Tanzania may depend upon its ability to develop natural gas markets in Tanzania and the surrounding region, obtain access to the necessary infrastructure to process gas and to deliver sales gas volumes, including acquiring capacity on pipelines which deliver natural gas to commercial markets. In addition, the remaining period on the PSA, which will expire in October 2026, is presently a considerable constraint that may make new markets unlikely in the next two years. The Company is subject to market fluctuations in the prices of natural gas, uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas and many other aspects of the oil and gas business. The prices that the Company receives for its natural gas affect the Company’s revenue, profitability, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil prices have experienced significant and sustained declines in the past and may continue to be volatile in the future; though gas prices are less volatile, they may also be significantly affected in the longer run. The natural gas prices the Company receives from its industrial customers fluctuate with the price of heavy fuel oil against which most of the Company’s industrial customer contracts are priced. Prices can also be affected by gas on gas competition from other producers in Tanzania. There have been significant onshore and offshore discoveries of gas in Tanzania over the last ten years and it is expected that the development of these discoveries will increase competition in the future. There is also scope for greater government intervention on gas prices as TPDC owns and operates the majority of the gas processing and pipeline infrastructure in Tanzania. A substantial or extended decline in both global and local oil and natural gas prices may adversely affect our business, financial condition and results of operations. Localized competition with other gas producers and alternative power sources such as hydropower could adversely impact our financial results. Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves The process of estimating oil and natural gas reserves is technically complex and imprecise. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in the annual reserves report. See SEDAR+ at www.sedarplus.ca. or our website to review our NI 51-101 for information about our estimated natural gas reserves and the present value of our net reserves as of December 31, 2024. To prepare our estimates, we must predict production rates and the timing of development expenditure. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic assumptions about factors such as commodity prices, drilling and operating expenses, capital expenditure, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditure, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves. In addition, we may adjust estimates of our reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas reserves You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the requirements of the Canadian Securities Administrators, we have based the estimated net present value of future net revenue attributable to our reserves utilizing forecast price and cost assumptions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as: • changes to the contractual terms and production sharing arrangements; • actual prices we receive for oil and natural gas; • actual cost of development and production expenditure; • derivative transactions; • demand from customers; • the amount and timing of actual production; and • changes in governmental regulations or taxation. The timing of both our production and expenses incurred in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the discount factors we use when calculating discounted future net revenues may not be the most appropriate discount factors based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in our estimated reserves. Oil and natural gas prices have recently experienced significant volatility. 44 Orca Energy Group Inc. // Annual Report & Accounts 2024 We are subject to drilling and other operational and environmental risks and hazards The oil and natural gas industry involves a variety of business, operational and environmental risks, including, but not limited to: • fires, blowouts, spills, cratering and explosions; • mechanical and equipment problems, including unforeseen engineering complications; • uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials; • gas flaring operations; • marine hazards with respect to offshore operations; • formations with abnormal pressures; • pollution, environmental risks, and geological problems; and • adverse weather conditions and natural or man-made disasters. Any of these events could result in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation of our operations, lower production rates, adverse publicity, substantial losses and civil or criminal liability. We expect to maintain insurance against some, but not all, of these risks and losses; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability and the occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations. Furthermore, the costs and risks associated with these events cannot be readily estimated or accounted for and we cannot predict whether any insurance we obtain will be sufficient or continue to be available at a reasonable cost or at all. Key staff Our performance and success are largely dependent on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate and develop reserves. We are dependent on members of our management and technical team that may not be easily replaced. Cyber attack The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss. There can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber-incident. Effects of climate change Risks related to climate change may have an impact on the Company’s operations and the Company may be subject to additional disclosure requirements in the future. The International Sustainability Standards Board issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. In addition, the Canadian Securities Administrators also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian reporting issuers. We continue to monitor developments on these reporting requirements and the impact they may have on the Company’s financial position and results of operating activities in future periods. The oil and natural gas industry is subject to varying environmental regulations and evolving views on climate change in each of the jurisdictions in which the Company may operate. Environmental regulations place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas and can impact the selection of drilling sites and facility locations, potentially resulting in increased capital expenditures. The Company operates in Tanzania, where extreme hot weather, heavy rains and floods or other severe weather conditions may cause operational difficulties, including downtime and increased costs of maintenance and construction. Extreme weather conditions may also impact workovers of existing wells and drilling of new wells. As of the date of this report, it is difficult to estimate the effect of the climate change-related legislations on our business or whether additional evolving climate-change legislation, regulations or other measures will be adopted in Tanzania. There are uncertainties regarding timing and effects of the emerging climate-change regulations, making it difficult to accurately determine the cost impacts and effects on the Company’s operations. Russian Ukrainian War The Corporation's business may be adversely affected by geopolitical conflicts abroad. In February 2022, Russian military forces invaded Ukraine. Ukrainian military personnel and civilians continue to actively resist the invasion. Many countries throughout the world have provided aid to Ukraine in the form of financial aid and in some cases military equipment and weapons to assist in its resistance to the Russian invasion. The North Atlantic Treaty Organization ("NATO") has also mobilized forces to NATO member countries that are close to the conflict as deterrence to further Russian aggression in the region. Additionally, certain countries including Canada have imposed strict financial and trade sanctions against Russia. The outcome of the ongoing conflict remains uncertain and may have wide-ranging consequences on the peace and stability of the region and the world economy. Middle Eastern Conflicts The Corporation's business may be adversely affected by geopolitical conflicts abroad. On October 7, 2023, Hamas terrorists infiltrated Israel's southern border from the Gaza Strip and conducted a series of attacks on civilian and military targets. Hamas also launched extensive rocket attacks on the Israeli population and industrial centres located along Israel's border with the Gaza Strip and in other areas within the State of Israel. Following the attack, Israel's security cabinet declared war against Hamas and the military campaign against these terrorist organizations has launched a series of responding attacks in Palestine. This conflict has significantly broadened with Israel also battling Hezbollah in Lebanon and significant conflict between Israel and Iran and other Iran backed proxies in the area. In addition, recently the Syrian Assad regime has fallen and it is unknown whether a stable Syrian government will develop. The outcome of these conflicts has the potential to have wide-ranging consequences on the world economy. There is a risk that these conflicts and developments could lead to wider regional instability in the Middle East, home to some of the world's biggest oil producers. The long-term impacts of these conflicts remain uncertain on oil and natural gas prices and the world economy. Such developments could have an impact on the oil and natural gas industry as a whole including the Corporation. 45 Orca Energy Group Inc. // Annual Report & Accounts 2024 Balances as at December 31, 2024 $’millions Tanzanian shillings Euros US dollars Other Total Cash and cash equivalents 3.0 0.1 85.6 1.4 90.1 Fluctuations in currency exchange rates could adversely impact the Company’s financial results. Cost of capital Our long-term business plan is based on the assumption that the License will be extended and requires substantial additional capital that we may be unable to fund out of working capital and cash flow generated from operations or raise on acceptable terms or at all in the future and which may in turn limit our ability to develop our appraisal, development and production activities. The Company’s ability to meet its financing obligations or to arrange financing in the future will depend in part upon the prevailing capital market conditions as well as the Company’s business performance. There can be no assurance that the Company would be successful in its efforts to meet its current commitments or arrange additional financing on terms satisfactory to the Company. Debt financing From time to time the Company may enter into transactions to acquire assets or the shares of other companies. These transactions may be financed in part or in whole with debt, which may temporarily increase the Company’s debt levels above industry standards. PAET had a Loan that included covenants that, among other things, restricted the incurrence of additional indebtedness, payment of dividends under certain conditions, granting of liens, mergers and sale of all or a substantial part of our business or license. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan made by the IFC to PAET, pursuant to the Loan Agreement. To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. As of the date hereof, the annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. 46 Financial Risks associated with the collectability of receivables could adversely affect our business We evaluate the collectability of our receivables on the basis of payment history, frequency and predictability, as well as our assessment of the customer’s willingness and ability to pay. We have been impacted by TANESCO’s stated inability to pay for past deliveries and to pay down arrears since 2012. Prior to 2017, TANESCO payments had been inconsistent and resulted in the Company recording provisions for doubtful accounts for amounts outstanding from TANESCO for more than 60 days. Commencing the last quarter of 2016, we began recording revenues for sales to TANESCO based on the expected amount to be collected, which represents a percentage of the amounts invoiced to TANESCO determined by comparison of TANESCO’s payment history with the amounts that we invoiced over the previous three years. Since April 1, 2018 we have recorded 100% of the invoices to TANESCO for gas sales given cash receipts from TANESCO have been sufficient to pay for current gas deliveries. As at December 31, 2024, the current receivable from TANESCO was $12.7 million (December 31, 2023: $5.9 million). The TANESCO long-term receivable as at December 31, 2024 and as at December 31, 2023 was $22.0 million with a provision of $22.0 million. Subsequent to December 31, 2024, the Company has invoiced TANESCO $14.5 million for Q1 2025 gas deliveries and TANESCO has paid the Company $24.2 million to date. There is a risk that we may not be able to recover all or any of the outstanding TANESCO receivables, or that we may need to suspend gas deliveries or initiate dispute resolution mechanisms to recover the TANESCO receivables. Any inability to collect on the TANESCO receivables and resulting actions by our operating subsidiary in Tanzania, PAET to enforce its rights may materially adversely affect our operations, financial condition or operational results. Foreign exchange The Company operates internationally and is exposed to foreign exchange risk arising from currency fluctuations against the US dollar when transactions and recognized assets and liabilities of the Company are denominated in a currency that is not the US dollar functional currency. The main currencies to which the Company has an exposure are Tanzanian shillings, Euros, British pounds sterling, and Canadian dollars. The majority of the expenditure associated with the operation of the gas distribution system is denominated in Tanzanian shillings. Whilst conversion of Tanzanian shillings into US dollars or Euros is unrestricted, the foreign exchange market for Tanzanian shillings is limited and not highly liquid, reducing the Company’s ability to convert large amounts of Tanzanian shillings into US dollars or Euros at any given time. To mitigate the risk of Tanzanian shilling devaluation, the Company regularly converts Tanzanian shilling receipts into US dollars or Euros to the extent practicable. Capital stock and equity financing are denominated in Canadian dollars. The operational revenue and the majority of capital expenditures are denominated in US dollars. All Loan repayments are also denominated in US dollars. The global growth slowdown and the impact of the war in Ukraine has seen an increasing decline in foreign exchange reserves due to inflationary pressures on imports in Tanzania and decreased foreign direct investment. This has given rise to decreased availability of US dollars and has impaired the Company’s ability to convert Tanzanian shillings to US dollars in 2024. The majority of the Company’s revenue is collected in Tanzanian shillings and there is a risk that in the future the Company may not be able to convert Tanzanian shillings to US dollars as and when required. It is not known when the foreign exchange reserve deficiency in Tanzania may be remedied. The following table illustrates cash and cash equivalents allocation between Tanzania and corporate locations: Orca Energy Group Inc. // Annual Report & Accounts 2024 We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all. For example, we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Further, even in instances where we maintain adequate insurance coverage, potential delays related to receipt of insurance proceeds as well as delays associated with the repair or rebuilding of damaged facilities could also materially and adversely affect our business, financial condition and results of operations. Furthermore, we cannot predict whether insurance will continue to be available at a reasonable cost or at all. We are a holding company and our ability to declare and pay dividends and purchase our Shares is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise We are a holding company, and our subsidiaries and affiliates own all of our assets and conduct all of our operations. Accordingly, our ability to declare and pay dividends and purchase our Shares will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Our subsidiaries and affiliates may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of dividends and purchases of Shares. Each subsidiary and affiliate is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries and affiliates. The Loan and local laws limit the ability of our subsidiaries to pay dividends and distribute funds to the parent companies. If we do not receive distributions from our subsidiaries, we may be unable to pay dividends and purchase our Shares. In addition, the ability of our subsidiaries to make payments to us may be constrained by, among other things: (i) the level of taxation, particularly corporate profits and withholding taxes, in the jurisdictions in which they operate; and (ii) the introduction of foreign exchange and/or currency controls or repatriation restrictions that impact the availability of hard currency to be repatriated If we do not receive distributions from our subsidiaries, we may be unable to pay dividends and purchase our Shares. 47 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Principal Terms of the PSA and Related Agreements The principal terms of the PSA and related agreements are as follows: Obligations and Restrictions (a) The PSA covers two blocks within the Songo Songo gas field where there are gas reserves (“Discovery Blocks”). The Company has the right to conduct petroleum operations on the Discovery Blocks, market and sell all Additional Gas produced and share the net revenue with TPDC for a term of 25 years, expiring in October 2026. (b) No sale of Additional Gas may be made from the Discovery Blocks if in the Company’s reasonable judgment such sales would jeopardize the supply of Protected Gas. Protected Gas ceased after July 31, 2024. Any Additional Gas contracts entered into are subject to interruption. Songas has the right to request that the Company and TPDC obtain security reasonably acceptable to Songas prior to making any sales of Additional Gas from the Discovery Blocks to secure the Company’s and TPDC’s obligations in respect of Insufficiency (as defined in (c) below). (c) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas requirements or if the gas is so expensive to develop that its cost exceeds the market price of alternative fuels at Ubungo. Protected Gas ceased after July 31, 2024, whereafter all gas from the Songo Songo field is now classified as Additional Gas. Where there have been third party sales of Additional Gas by the Company and TPDC from the Discovery Blocks prior to the occurrence of the Insufficiency, the Company and TPDC shall be jointly liable for the Insufficiency and shall satisfy their related liability by either replacing the Indemnified Volume (as defined in (d) below) at the price for Protected Gas with natural gas from other sources; or by paying monetary damages equal to the difference between: (a) the market price for a quantity of alternative fuel that is appropriate for the five gas turbine electricity generators at Ubungo without significant modification together with the costs of any modification; and (b) the sum of the price for such volume of Protected Gas (at $0.55/MMbtu escalated) and the amount of transportation revenues previously credited by Songas to the state electricity utility, TANESCO, for the gas volumes. (d) The “Indemnified Volume” means the lesser of the total volume of Additional Gas sales supplied from the Discovery Blocks prior to an Insufficiency and the Insufficiency Volume. “Insufficiency Volume” means the volume of natural gas determined by multiplying the average of the annual Protected Gas volumes for the three years prior to the Insufficiency by 110% and multiplied by the number of remaining years (initial term of 20 years) of the power purchase agreement entered into between Songas and TANESCO in relation to the five gas turbine electricity generators at Ubungo from the date of the Insufficiency. Access and Development of Infrastructure (e) The Company is able to utilize the Songas Infrastructure including the gas processing plant and main pipeline to Dar es Salaam. Access to the Songas Infrastructure is open and can be utilized by any third party that wishes to process or transport gas. Revenue Sharing Terms and Taxation (f) 75% of the gross field revenues derived from the Discovery Blocks, less processing and pipeline tariffs and direct sales taxes in any year (“field net revenue”), can be used to recover past costs incurred. Costs recovered out of field net revenue are termed “Cost Gas”. The Company pays and recovers costs of exploring, developing and operating the Additional Gas with two exceptions: (i) TPDC may recover reasonable market and market research costs as defined under the PSA; and (ii) TPDC has the right to elect to participate in the drilling of at least one well for Additional Gas in the Discovery Blocks for which there is a development program as detailed in an Additional Gas plan (“Additional Gas Plan”) as submitted to the MoE, provided that TPDC may to elect to participate in a development program only once and TPDC pays a proportion of the costs of such development program by committing to pay between 5% and 20% of the total costs (“Specified Proportion”). If TPDC does not notify the Company within 90 days of notice from the Company that the MoE has approved the Additional Gas Plan, then TPDC is deemed to have elected not to participate. If TPDC elects to participate, then it will be entitled to a ratable proportion of the Cost Gas and their profit share percentage increases by the Specified Proportion for that development program. To date, TPDC has neither elected to back in within the prescribed notice period nor contributed any costs associated with backing in. The Company has therefore determined that to date there has been no working interest earned by TPDC. For the purpose of the reserves certification as at December 31, 2024, there are no planned drilling activities to the end of the license. (g) The Company’s long-term gas price to the Power sector as set out in the ARGA between the GoT, TPDC and Songas and the PGSA is based on the price of gas at the wellhead. As at the date of this report, the ARGA remains an initialed agreement only and the parties are not in agreement with all the terms in the ARGA, however the parties are conducting themselves in terms of pricing as though the ARGA is in force. D iscussion & 48 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Revenue Sharing Terms and Taxation continued In Q3 2017 the Company received approval of the Additional Gas Plan 2 (“AGP2”) from the MoE to produce and sell increased volumes of Additional Gas. Currently the SS-10, SS-11 and SS-12 wells are connected to the NNGI and the SS-12 well started flowing gas through the NNGI in December 2018. In May 2019 the Company and TPDC signed the LTGSA, initially for volumes up to 20 MMcfd which was increased subsequently to 30 MMcfd on a best endeavors basis. In 2020 the parties established a 12-month renewable agreement for the supply of volumes above 30MMcfd on an ad-hoc basis, allowing TPDC to meet fluctuating demand and compensate for shortfalls in production from their Madimba plant without being penalized due to a higher, fixed contractual limit and the subsequent take-or-pay penalties should the demand reduce again. The agreement has allowed the Company to supply volumes in excess of 50 MMcfd on occasion, increasing average sales volumes and revenues. In Q4 2023 the Company advised TPDC that the maximum daily quantity (“MDQ”) would revert to the original and contractually agreed 20 MMcfd on the basis TPDC had not fulfilled its obligations under the 12-month renewable agreement. (h) Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the Company, the proportion of which is dependent on the average daily volumes of Additional Gas sold or cumulative production. The Company receives a higher share of the field net revenue after cost recovery, based on the higher of the cumulative production or the average daily sales. The Profit Gas share available to the Company is a minimum of 25% and a maximum of 55%. Average daily sales of Additional Gas Cumulative sales of Additional Gas TPDC’s share of Profit Gas Company’s share of Profit Gas MMcfd Bcf % % 0 – 20 0 – 125 75 25 > 20 <= 30 > 125 <= 250 70 30 > 30 <= 40 > 250 <= 375 65 35 > 40 <= 50 > 375 <= 500 60 40 > 50 > 500 45 55 For Additional Gas produced outside of the Proven Section, the Company’s Profit Gas share is 55%. Where TPDC elects to participate in a development program, its profit share percentage increases by the Specified Proportion (for that development program) with a corresponding decrease in the Company’s percentage share of Profit Gas. The Company is liable for income tax in Tanzania. Where income tax is payable, the Company pays the tax and there is a corresponding deduction in the amount of the Profit Gas payable to TPDC. (i) APT is payable when the Company recovers its costs out of Additional Gas revenues plus an annual operating return under the PSA of 25%, plus the percentage change in the PPI. The maximum APT rate is 55% of the Company’s Profit Gas when costs have been recovered with an annual return of 35% plus PPI return. The PSA is, therefore, structured to encourage the Company to develop the market and the gas fields with the knowledge that the Profit Gas share can increase with larger daily gas sales and that the costs will be recovered with a 25% plus PPI annual return before APT becomes payable. APT can have a significant negative impact on project economics if only limited capital expenditure is incurred. (j) Under the Operatorship Agreement between the Company and Songas, the Company is appointed to develop, produce and process Protected Gas and operate and maintain the Songas Infrastructure, including the staffing, procurement, capital improvements, contract maintenance, maintenance of books and records, preparation of reports, maintenance of permits, waste handling, liaison with the GoT and taking all necessary safety, health and environmental precautions, all in accordance with good oilfield practices. In return, the Company is paid or reimbursed by Songas so that it neither benefits nor suffers a loss as a result of its performance. The Protected Gas regime ended on July 31, 2024. (k) In the event of loss arising from Songas’ failure to perform, and the loss is not fully compensated by Songas or through insurance coverage, then the Company is liable to a performance and operational guarantee of $2.5 million when (i) the loss is caused by the gross negligence or willful misconduct of the Company, its subsidiaries or employees, and (ii) Songas has insufficient funds to cure the loss and operate the project. Protected Gas Under the terms of the Gas Agreement for the Songo Songo project, in the event that there is a shortfall/insufficiency in Protected Gas as a consequence of the sale of Additional Gas, the Company is liable to pay the difference between the price of Protected Gas ($0.55/MMbtu escalated) and the price of an alternative feedstock multiplied by the volumes of Protected Gas up to a maximum of the volume of Additional Gas sold (258 Bcf as at December 31, 2023). The Company did not have a shortfall during the reporting period up to July 31, 2024, when the Protected Gas regime ended. 49 Orca Energy Group Inc. // Annual Report & Accounts 2024 Re-Rating Agreement In 2011 the Company, TPDC and Songas signed the Re-Rating Agreement which evidenced an increase to the gas processing capacity of the Songas Infrastructure to a maximum of 110 MMcfd. Under the terms of the Re-Rating Agreement, the Company paid additional compensation of $0.30/mcf for sales between 70 MMcfd and 90 MMcfd and $0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in addition to the tariff of $0.59/mcf payable to Songas as set by the energy regulator, EWURA. Although Songas notified the Company in 2014 that the Re-Rating Agreement was terminated, the parties have continued to produce, transport and sell gas volumes in line with the re-rated plant capacity. In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd would no longer be paid effective June 2016. The additional compensation was always intended to be temporary in nature until the expansion of the Songas Infrastructure, at which time Songas would apply to EWURA to obtain approval of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff charged to the Company should a new tariff be approved. The parties to the Re-Rating Agreement are in the process of negotiating a replacement agreement which may address the additional compensation paid. In the interim, the processing capacity at the Songas Infrastructure remains unaltered and is fully available for utilization by the Company. This capacity is in addition to the capacity available within the NNGI. Portfolio Gas Supply Agreement In June 2011 the PGSA was signed (term to June 30, 2023) between TANESCO (as the buyer) and the Company (through its subsidiary PAET) and TPDC (collectively as the seller). TANESCO requested a change to the PGSA MDQ which PAET and TPDC approved effective January 29, 2018. In accordance with the PGSA, when calculating aggregate excess, extra and overtake gas through the supply period, the MDQ was reduced and the seller is now obligated, subject to infrastructure capacity, to sell a maximum of approximately 16 MMcfd (previously 26 MMcfd) for use in any of TANESCO’s current power plants, except those operated by Songas at Ubungo. The PGSA, which was due to expire on June 30, 2023, was extended to a new expiry date of July 31, 2024. As part of the extension, the MDQ was increased from 16.0 MMcfd to 26.0 MMcfd. Under the agreement, the basic wellhead price of approximately $2.98/mcf increased to $3.04/ mcf on July 1, 2018, to $3.10/mcf on July 1, 2019, $3.14/mcf on July 1, 2020, $3.20/mcf on July 1, 2021, $3.32/mcf on July 1, 2022, $3.50/mcf on July 1, 2023, and $3.56/mcf on July 1, 2024. The PGSA was extended on July 30, 2024 and will expire on October 10, 2026. Long-term Gas Sales Agreement On May 14, 2019 the Company and TPDC signed the LTGSA for an initial delivery of 20 MMcfd through the NNGI, at a price of $3.10/MMbtu as at January 1, 2019, (escalating 2% per annum) exclusive of any processing and transportation tariff associated with the NNGI. The LTGSA was amended on September 24, 2019 to increase the volumes supplied through the NNGI up to a MDQ of 30 MMcfd. In 2020 the parties established a 12-month renewable agreement for the supply of volumes above 30 MMcfd on an ad-hoc basis, allowing TPDC to meet fluctuating demand and compensate for shortfalls in production from their Madimba plant without being penalized due to a higher, fixed contractual limit and the subsequent take-or-pay penalties should the demand reduce again. The agreement has allowed the Company to supply volumes in excess of 50 MMcfd on occasion, increasing average sales volumes and revenues. In Q4 2023 the Company advised TPDC that the MDQ would revert to the original and contractually agreed 20 MMcfd on the basis TPDC had not fulfilled its obligations under the 12-month renewable agreement. The LTGSA will expire on October 10, 2026. TPDC Back-in TPDC has the rights under the PSA to ‘back in’ to the Songo Songo field development and to convert this into a carried working interest in the PSA. The current terms of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has neither provided notice nor contributed any costs and the definition period has closed. Management’ s sis iscussion & Management’ s Discussion & Analysis 50 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S DISCUSSION & ANALYSIS CONTINUED Forward-Looking Statements This MD&A contains forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation. All statements, other than statements of historical fact included in this MD&A, which address activities, events or developments that Orca expects or anticipates to occur in the future, are forward-looking statements. Forward-looking statements often contain terms such as may, will, should, anticipate, expect, continue, estimate, believe, project, forecast, plan, intend, target, outlook, focus, could and similar words suggesting future outcomes or statements regarding an outlook. More particularly, this MD&A contains, without limitation, forward-looking statements pertaining to the following: the Company’s expectations regarding the demand for natural gas and power supply; anticipated Additional Gas sales for 2025; assessment by the Company of the merits of the appeal made by the Company pursuant to the Judgment; costs, outcomes and timing in respect to the outcome of the appeal of the Judgement; the Company’s liabilities pursuant to the claims brought forth by the seismic contract and recoverability of damages claimed by the Company; merit, outcomes, position and timing in respect of the Notice of Dispute; expectations regarding damages in relation to the Notice of Dispute; the Company’s expectation that all capital allocation decisions will be based upon prudent economic evaluations and returns; extension of the License and the Company’s expectation to continue to actively engage with the GoT to progress the License extension; the expected terms and costs associated with the License extension; the Company’s expectation that PAET will receive payment in respect of Protected Gas supplied after July 31, 2024; expectations around entering into a new PPA; expectations in respect of the Songas Power Plant; maintenance of gas sale contract discipline by the Company in accordance with its gas supply agreements; expectations regarding customers' ability to pay for supplied gas; continued accrual of participation interest in respect of the Loan until the specified date; the receipt of the payment of arrears from TANESCO; forecasts regarding future development capital spending and the anticipated source of funding; the timing and effective rate of the APT payable by the Company; the Company’s expectation that there will be no future restrictions on the movement of cash from Jersey, Mauritius or Tanzania; availability of necessary regulatory approvals; the Company’s expectation that it will maintain adequate working capital to cover the Company’s long-term and short-term obligations; the Company’s expectation that it will be receiving payment for certain Additional Gas that as a result of the dispute between PAET and TPDC as to whether Protected Gas ceased after July 31, 2024, such that all gas produced falls to be treated as Additional Gas; if any payment is eventually required in respect of the Judgement, that such payment will be cost recoverable under the PSA; that TANESCO will pay such amounts owing under the Settlement Agreement; the amount that PAET is expected to retain in relation to the Settlement Agreement; expectations that an indefinite shutdown of the Songas Power Plant will adversely impact demand for production volumes from the Songo Songo gas field; expectation that forecasted Additional Gas will decrease; expectations that the PPA will be replaced; the concern that if the Protected Gas is not resolved, the Company will be required to reduce costs and ensure capital expenditure projects on the Songo Songo gas field are in line with contracts and economic returns; the expectations regarding future revenues of the Company; expectations as to the resolution of the Notice of Dispute; the Company’s plans to provide updates on the Notice of Dispute; expectations that Songas will pay the balance of the invoice in respect to Additional Gas; that the Company does not expect to incur any losses from debtors in 2025; the Company’s expectations that no circumstances will significantly impact the Company’s cash flow or liquidity other than disclosed in this MD&A, as applicable; the Company’s expectations that it will be able to convert Tanzanian shillings into US dollars and other hard currencies during and after the current foreign exchange deficiency; the Company’s expectations regarding supply and demand of natural gas; the Company’s expectation and evaluations on the timing and results of its objections and appeals to the decisions and assessments of the TRA, TRAB and CAT under “Contingencies – Taxation” in this MD&A; the Company’s view that all costs are correctly included in the Cost Pool and the Company’s expectations regarding changes to its tax liabilities and the results of its operations as a result of amendments made to the ITA, 2004, the WLMAA, 2017 and the implementation of further legislation. In addition, statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be produced profitably in the future. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Although management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, access to resources and infrastructure, performance or achievement since such expectations are inherently subject to significant business, economic, operational, competitive, political and social uncertainties and contingencies. These forward-looking statements involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company’s control, and many factors could cause the Company’s actual results to differ materially from those expressed or implied in any forward-looking statements made by the Company, including, but not limited to: risk that PAET will not receive payment or payment may form part of a contract dispute, in respect of uncontracted gas that continued to flow post August 1, 2024 to October 31, 2024; uncertainties involving the Notice of Dispute and the Judgment; various uncertainties involved in the extension of the License; risk that meetings related to the Notice of Dispute are not held on the anticipated timing; risk the PPA will not be replaced; risk of decreased demand for production volumes from the Songo Songo gas field; risk the Songas Power Plant will shut down indefinitely; negative effect on the Company’s rights under the PSA and other agreements relating to its business in Tanzania; fluctuations in demand for natural gas and power supply in Tanzania; the Company’s average gas sales including the sale of Additional Gas are different than anticipated; uncertainties involving the negotiation of new commercial terms under the Gas Agreement with Songas and necessary approvals from TPDC; risk that the Company may incur losses and legal expenses as a result of the claims brought forth by the seismic contractor; uncertainties regarding quantum of damages payable by the seismic contractor and/or the Company; risk that the Company may incur losses and legal expenses as a result of the Notice of Dispute and appeal of the Judgment; uncertainties regarding quantum of damages payable to the Company in respect of the Notice of Dispute; uncertainties regarding quantum of damages payable to the Company in respect of the appeal of the Judgment; risk that the budgeted expenditures, timing of the completion and anticipated benefits from the Company’s various development programs and studies in 2025 are different than expected; risk of damage to the Company's infrastructure assets; that not all capital allocation decisions will be based upon prudent economic evaluations and returns; inability to extend the License and inability to maintain gas sale contract discipline; accrual of participation interest is different than expected; failure to receive payment of arrears from TANESCO; if any payment is eventually required in respect of the Judgement, that it will not be cost recoverable under the PSA; risk that TANESCO will not pay such amounts owing under the Settlement Agreement; changes to the timing and effective rate of the APT payable by the Company; changes to forecasts regarding future development capital spending and source of capital spending; risk of future restrictions on the movement of cash from Jersey, Mauritius or Tanzania; occurrence of circumstance or events which significantly impact the Company’s cash flow and liquidity and the Company’s ability cover its long-term and short-term obligations or fund planned capital expenditures; incurrence of losses from debtors in 2025; prolonged foreign exchange reserves deficiency in Tanzania; inability to convert Tanzanian shillings into US dollars or other hard currencies as and when required; discontinuation of work by the Company with the GoT on alternative development plan for longer term field development; failure to obtain necessary regulatory approvals; risks regarding the uncertainty around evolution of Tanzanian legislation; 51 Orca Energy Group Inc. // Annual Report & Accounts 2024 risk of unanticipated effects regarding changes to the Company’s tax liabilities and its operations as a result of amendments made to the ITA, 2004, the WLMAA, 2017, the implementation of further legislation and the Company’s interpretation of the same; risk of a lack of access to Songas processing and transportation facilities; risk that the Company may be unable to complete additional field development to support the Songo Songo production profile through the life of the license; risks associated with the Company’s ability to complete sales of Additional Gas; negative effect on the Company’s rights under the PSA and other agreements relating to its business in Tanzania as a result of recently enacted legislation, as well as the risk that such legislation will create additional costs and time connected with the Company’s business in Tanzania; risk relating to the Company's relationship with the GoT; the impact of general economic conditions in the areas in which the Company operates; civil unrest; risk of pandemic; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations; impact of local content regulations and variances in the interpretation and enforcement of such regulations; impact of local content regulations and variances in the interpretation and enforcement of such regulations; uncertainty regarding results through negotiations and/or exercise of legally available remedies; failure to successfully negotiate agreements; risks of non-payment by recipients of natural gas supplied by the Company; lack of certainty with respect to foreign legal systems, corruption, and other factors that are inconsistent with the rule of law; risk of loss due to acts of war, terrorism, sabotage and civil disturbances; timing of receipt of, or failure to comply with, necessary permits and approvals; and potential damage to the Company’s reputation due to the actual or perceived occurrence of any number of events, including negative publicity with respect to the Company’s dealings with the GoT, TPDC and TANESCO, whether true or not; increased competition; the lack of availability of qualified personnel or management; fluctuations in commodity prices, foreign exchange or interest rates; stock market volatility; competition for, among other things, capital, oil and gas field services and skilled personnel; failure to obtain required equipment or replacement parts for field development; effect of changes to the PSA on the Company as a result of the implementation of new government policies for the oil and gas industry; inaccuracy in reserve estimates; incorrect forecasts in production and growth potential of the Company’s assets; inability to obtain required approvals of regulatory authorities; risks associated with negotiating with foreign governments; failure to successfully negotiate agreements; failure to successfully negotiate the extension of the License on favorable terms; risk that the Company will not be able to fulfil its contractual obligations; risk that trade and other receivables may not be paid by the Company’s customers when due; the risk that the Company’s Tanzanian operations will not provide near term revenue earnings; risk that any costs in respect of the Cost Pool, are rejected as not being cost recoverable, and the Company being required to retroactively adjust its share of revenue for the period under dispute; and such additional risks listed under “Business Risks” in this report. In addition, there are risks and uncertainties associated with oil and gas operations, therefore the Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by these forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. Readers are cautioned that the foregoing list of factors is not exhaustive. Such forward-looking statements are based on certain assumptions made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors the Company believes are appropriate in the circumstances, including, but not limited to: increased demand for gas supply; risk that any costs in respect of the Cost Pool, are rejected as not being cost recoverable, and the Company being required to retroactively adjust its share of revenue for the period under dispute Company’s average Additional Gas sales are in line with forecasts; successful negotiation and execution of new gas sales contracts under the Gas Agreement; successful negotiation of the License extension, on terms favorable to the Company; successful implementation of various development and study programs at the budgeted expenditures; accurate assessment by the Company of the merits of its claim under the Notice of Dispute and the appeal of the Judgment; that all capital allocation decisions will be based upon prudent economic evaluations and returns; successful extension of the License and maintenance of gas sale contract discipline on a go-forward basis pursuant to the Company’s gas supply agreements; anticipated award amount payable under the Long Term Retention Plan; accrual of participation interest as expected; that the Company will receive payment of arrears from TANESCO; the Company’s relationship with TPDC and the GoT; the current status of negotiations in respect of the GA and PSA; the current status of actions involved in the Notice of Dispute; accurate assessment by the Company of the merits of its rights and obligations in relation to TPDC and the GoT and other stakeholders in the Songo Songo gas field; receipt of required regulatory approvals; the Company’s ability to maintain strong commercial relationships with the GoT and other state and parastatal organizations and other stakeholders in the Songo Songo gas field; the current and future administration in Tanzania continues to honor the terms of the PSA and the Company’s other principal agreements; correct forecast on the timing and effective rate of the APT payable by the Company; that there will continue to be no restrictions on the movement of cash from Mauritius, Jersey or Tanzania; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and participation interest obligations as needed; the Company does not incur any losses from debtors in 2025; absence of circumstances or events that significant impact the Company’s cash flow and liquidity; the Company will continue to be able to convert Tanzanian shillings into US dollars; long term field development will be carried out as planned; continued work by the Company with the GoT on alternative development plan for longer term field development as anticipated; timing and amount of capital expenditures and source of funding are in line with forecasts; the Company’s ability to obtain necessary regulatory approvals; the anticipated supply and demand of natural gas are in line with the Company’s expectations; accurate assessment by the Company of the merits of appeal brought forward by the Company pursuant to the Judgment; that the amount of damages recoverable by the Company under the Notice of Dispute will be in line with expectations; that the amount of damages recoverable by the Company will be in line with expectations; the Company’s interpretation and prediction of the effects regarding changes to the Company’s tax liabilities and its operations as a result of amendments made to the ITA, 2004, the WLMAA, 2017 and the implementation of further legislation is accurate in all material respects; the Company’s ability to obtain revenue earnings from its operations; access to customers and suppliers; availability of employees to carry out day-to-day operations, and other resources; that the Company will successfully negotiate agreements; receipt of required regulatory approvals; the ability of the Company to increase production as required to meet demand; infrastructure capacity; commodity prices will not deteriorate significantly; the ability of the Company to obtain equipment and services in a timely manner to carry out exploration, development and exploitation activities; availability of skilled labour; uninterrupted access to infrastructure; the impact of increasing competition; conditions in general economic and financial markets; effects of regulation by governmental agencies; that the Company’s appeal of various tax assessments will be successful; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the effect of any new environmental and climate change related regulations will not negatively impact the Company; and other matters. The forward-looking statements contained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. Additional Information Additional information relating to the Company is available on SEDAR+ at www.sedarplus.ca 52 Orca Energy Group Inc. // Annual Report & Accounts 2024 GLOSSARY mcf Thousand standard cubic feet MMcf Million standard cubic feet Bcf Billion standard cubic feet MMcfd Million standard cubic feet per day MMbtu Million British thermal units 1P Proven reserves 2P Proven and probable reserves $ United States dollars CDN$ Canadian dollars iscussion & 53 Orca Energy Group Inc. // Annual Report & Accounts 2024 MANAGEMENT’S REPORT TO SHAREHOLDERS The accompanying consolidated financial statements of Orca Energy Group Inc. are the responsibility of Management. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements. The consolidated financial statements have been prepared by Management, on behalf of the Board, in accordance with the accounting policies disclosed in the notes to the consolidated financial statements. Where necessary, management has made informed judgments and estimates in accounting for transactions which were not complete at the balance sheet date. In the opinion of management, the consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Financial Reporting Standards (“IFRS”) as adopted by the International Accounting Standards Board (“IASB”) appropriate in the circumstances. Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance that transactions are properly authorised, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial statements. An independent firm of Chartered Professional Accountants, as appointed by the Shareholders, audited the consolidated financial statements in accordance with the Canadian Generally Accepted Auditing Standards to enable them to express an opinion on the fairness of the consolidated financial statements in accordance with IFRS as adopted by the IASB. The Board of Directors carries out its responsibility for the financial reporting and internal controls of the Company principally through an Audit Committee. The committee has met with the independent auditors and Management in order to determine if Management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The consolidated financial statements have been approved by the Board of Directors on the recommendation of the Audit Committee. With an extension of the Company's operating license not yet granted beyond October 2026, the Board of Directors have considered whether it is appropriate for the financial statements to be prepared on a going concern basis and following a review of a range of cashflow forecasts for possible outcomes over the next twelve months, have reached the conclusion that it is appropriate to do so. 54 Jay Lyons Chief Executive Officer April 29 2025 Lisa Mitchell Chief Financial Officer April 29, 2025 KPMG LLP 205 5th Avenue SW Suite 3100 Calgary AB T2P 4B9 Tel 403-691-8000 Fax 403-691-8008 www.kpmg.ca KPMG LLP, an Ontario limited liability partnership and member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee. KPMG Canada provides services to KPMG LLP. INDEPENDENT AUDITOR’S REPORT To the Shareholders of Orca Energy Group Inc. Opinion We have audited the financial statements of Orca Energy Group Inc (the “Entity”), which comprise: • The consolidated statements of financial position as at December 31, 2024 and December 31, 2023 • the consolidated statements of comprehensive income (loss) for the years then ended • the consolidated statements of changes in shareholders’ equity for the years then ended • the consolidated statements of cash flows for the years then ended • and consolidated notes to the financial statements, including a summary of material accounting policy information (Hereinafter referred to as the “financial statements”). In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Entity as at December 31, 2024 and December 31, 2023, and its financial performance and its cash flows for the years then ended in accordance with IFRS Accounting Standards. Basis for Opinion We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the “Auditor’s Responsibilities for the Audit of the Financial Statements” section of our auditor’s report. We are independent of the Entity in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements for the year ended December 31, 2024. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. We have determined the matters described below to be the key audit matters to be communicated in our auditor’s report. Assessment and recognition of income tax provision related to positions taken in tax filings in Tanzania Description of the matter We draw your attention to note 3, note 4 (c), note 5(h), and note 21 to the financial statements. The Entity operates in Tanzania where tax authorities may audit income tax filings and the resolution of such audits may span multiple years. Tax law in Tanzania is complex and often subject to changes and to varied interpretations; accordingly, the ultimate outcome with respect to positions taken on income tax filings may differ from the amounts recognized. The Entity has taken certain tax positions in its tax filings and these tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax impact may differ significantly from that estimated and recorded by management. The Entity’s assessment of whether it is probable that the position taken by the Entity will be accepted by tax authorities in Tanzania is a significant management judgment. The Entity will record a tax provision where management concludes it is probable the filing position taken by the Entity will not be accepted by the relevant taxing authority. At December 31, 2024, the Entity estimated that the total tax contingencies related to uncertain income tax filing positions with Tanzanian tax authorities is $81.4 million. Why the matter is a key audit matter We identified the assessment and recognition of income tax provision related to positions taken in tax filings in Tanzania as a key audit matter. This matter represented an area of significant risk of material misstatement. In addition, significant auditor judgment and specialized skills and knowledge were required to evaluate the Entity’s assessment of the probability of the taxation authorities accepting the tax filing positions taken by the Entity. How the matter was addressed in the audit The primary procedures we performed to address this key audit matter included the following: We involved income tax professionals in Canada and Tanzania with specialized skills and knowledge who assisted in evaluating the Entity’s tax filing positions including interpretation of income tax legislation by: • Developing an independent assessment of the Entity’s tax filing positions based on their understanding and interpretation of tax laws in Tanzania and comparing it to the Entity’s assessment • Inspecting the Entity’s correspondence with Tanzanian tax authorities and evaluating the implications of the matters raised by such authorities • Inspecting evaluations and opinions provided by the Entity’s tax advisors We assessed whether it was probable that the tax filing positions taken by the Entity would be accepted by the Tanzanian tax authorities by obtaining legal enquiry letter responses from law firms engaged by the entity related to identified tax claims and contingencies. Assessment of the impact of estimated proven natural gas reserves on depletion expense Description of the matter We draw attention to note 3, note 4 and note 13 to the financial statements. The Entity amortizes its costs associated with tangible natural gas assets using the unit of production method by reference to the ratio of production in the period to the related proven gas reserves, taking into account estimated forecasted future development costs necessary to bring those reserves into production. The Entity recorded depletion expense related to its tangible natural gas assets of $30.5 million for the year ended December 31, 2024. The estimated proven gas reserves includes significant assumptions related to: • Forecasted natural gas prices • Forecasted production rates • Forecasted operating costs • Forecasted future development costs • Forecasted cost recovery provisions and additional profit tax The Entity engages independent petroleum engineers to evaluate the proven natural gas reserves and the related cash flows. Why the matter is a key audit matter We identified the assessment of the impact of estimated proven natural gas reserves on depletion expense as a key audit matter. Significant auditor judgement was required to evaluate the results of our audit procedures regarding the estimate of proven natural gas reserves. How the matter was addressed in the audit The primary procedures we performed to address this key audit matter include the following: We assessed the depletion expense calculation for compliance with IFRS Accounting Standards. With respect to the estimate of proven natural gas reserves: • We evaluated the competence, capabilities and objectivity of the independent petroleum engineers engaged by the Entity • We compared the 2024 actual production rates, operating costs, additional profit tax, and future development costs of the Entity to those estimates used in the prior year’s estimate of proven natural gas reserves to assess the Entity’s ability to accurately forecast • We evaluated the appropriateness of forecasted natural gas prices, forecasted production rates, forecasted operating costs, forecasted cost recovery provisions and additional profit tax, and forecasted future development cost assumptions by comparing to 2024 actual results. We took into account changes in conditions and events affecting the Entity to assess the adjustments or lack of adjustments made by the Entity in arriving at the assumptions. Other Information Management is responsible for the other information. Other information comprises: • the information included in Management’s Discussion and Analysis filed with the relevant Canadian Securities Commissions. • the information, other than the financial statements and the auditor’s report thereon, included in a document likely to be entitled “Annual Report & Accounts 2024”. Our opinion on the financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit and remain alert for indications that the other information appears to be materially misstated. We obtained the information Management’s Discussion and Analysis filed with the relevant Canadian Securities Commissions and the information, other than the financial statements and the auditor’s report thereon, included in a document likely to be entitled “Annual Report & Accounts 2024” as at the date of this auditor’s report. If, based on the work we have performed on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact in the auditor’s report. We have nothing to report in this regard. Responsibilities of Management and Those Charged with Governance for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with IFRS Accounting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, management is responsible for assessing the Entity's ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Entity or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Entity's financial reporting process. Auditor’s Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of the financial statements. As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Entity's internal control. • Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. • Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Entity's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Entity to cease to continue as a going concern. • Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation. • Communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. • Provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards. • Plan and perform the group audit to obtain sufficient appropriate audit evidence regarding the financial information of the entities or business units within the group as a basis for forming an opinion on the group financial statements. We are responsible for the direction, supervision and review of the audit work performed for the purposes of the group audit. We remain solely responsible for our audit opinion. • Determine, from the matters communicated with those charged with governance, those matters that were of most significance in the audit of the financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our auditor’s report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. The engagement partner on the audit resulting in this auditor’s report is Jason Grodziski. Chartered Professional Accountants Calgary, Canada April 29, 2025 Orca Energy Group Inc. // Annual Report & Accounts 2024 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Years ended December 31 $’000 Note 2024 2023 Revenue 7 111,593 110,235 Production, distribution and transportation 19,990 19,197 Net production revenue 91,603 91,038 Operating expenses General and administrative 19,819 17,892 Stock based compensation 17 – 6 Depletion 13 30,506 41,857 Loss allowance 9 21,700 (6,915) Finance income 9 (3,665) (1,888) Asset impairment 13 26,651 – Finance expense 9 13,751 14,938 (Loss) / income before tax (17,159) 25,148 Income tax expense – current 10 13,737 16,133 Income tax recovery – deferred 10 (15,508) (6,161) Additional Profits Tax 11 6,190 8,162 Net (loss) / income attributable to shareholders (21,578) 7,014 Foreign currency translation (loss) / gain from foreign operations (16) 288 Comprehensive (loss) / income (21,594) 7,302 Net (loss) / income attributable to shareholders per share ($) Basic and diluted 18 (1.09) 0.35 See accompanying notes to the consolidated financial statements. Financial Statements 61 Orca Energy Group Inc. // Annual Report & Accounts 2024 CONSOLIDATED STATEMENTS OF FINANCIAL POSITION As at December 31 $’000 Note 2024 2023 ASSETS Current assets Cash and cash equivalents 90,076 101,566 Trade and other receivables 12 44,037 32,837 Prepayments 1,586 1,637 135,699 136,040 Non-current assets Long-term receivables 15 10 10 Capital assets 13 50,057 79,381 50,067 79,391 Total assets 185,766 215,431 EQUITY AND LIABILITIES Current liabilities Trade and other payables 14 66,851 38,407 Tax payable 8,998 4,326 Current portion of long-term loan 16 30,122 10,000 Current portion of Additional Profits Tax 11 7,824 15,984 113,795 68,717 Non-current liabilities Deferred income taxes 10 4,587 20,095 Lease liabilities 13 217 456 Long-term loan 16 – 29,961 Additional Profits Tax 11 5,891 7,524 10,695 58,036 Total liabilities 124,490 126,753 SHAREHOLDERS’ EQUITY Capital stock 17 46,992 47,067 Accumulated other comprehensive income – 16 Accumulated income 14,284 41,595 61,276 88,678 Total equity and liabilities 185,766 215,431 Director Director 62 See accompanying notes to the consolidated financial statements. Nature of operations (Note 1); Contractual obligations (Note 20); Contingencies (Note 21); Subsequent events (Note 25). The consolidated financial statements were approved by the Board on April 28, 2025. Orca Energy Group Inc. // Annual Report & Accounts 2024 CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31 $’000 Note 2024 2023 OPERATING ACTIVITIES Net (loss) / income (21,578) 7,014 Adjustment for: Depletion and depreciation 13 31,023 42,229 Indirect tax 9 1,300 1,273 Stock based compensation 17 – 6 Asset impairment 13 26,651 – Deferred income tax 10 (15,508) (6,161) Additional Profits Tax 11 6,190 8,162 Unrealized (gain) / loss on foreign exchange (3,009) 2,869 Interest expense 9 4,770 7,834 Finance income – 241 Change in non-cash operating working capital 23 (2,753) (14,982) Net cash flows from operating activities 27,086 48,485 INVESTING ACTIVITIES Capital expenditures 13 (17,960) (8,794) Net cash used in investing activities (17,960) (8,794) FINANCING ACTIVITIES Lease payments 13 (343) (324) Normal course issuer bid 17 (88) (271) Long-term loan repayment 16 (10,000) (10,000) Loan interest paid 9 (6,795) (7,770) Dividends paid to shareholders 17 (5,845) (5,873) Purchase of minority interest in subsidiary 24 – (7,500) Net cash used in financing activities (23,071) (31,738) (Decrease) / increase in cash (13,945) 7,953 Cash and cash equivalents at the beginning of the year 101,566 96,321 Effect of change in foreign exchange on cash for the year 2,455 (2,708) Cash and cash equivalents at the end of the year 90,076 101,566 See accompanying notes to the consolidated financial statements. Financial Statements 63 Orca Energy Group Inc. // Annual Report & Accounts 2024 CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY Accumulated other Capital comprehensive Accumulated $’000 stock loss income Total Note 17 17 Balance as at December 31, 2023 47,067 16 41,595 88,678 Share repurchase (75) – (13) (88) Dividends declared – – (5,736) (5,736) Foreign currency translation adjustment on foreign operations – (16) 16 – Net loss – – (21,578) (21,578) Balance as at December 31, 2024 46,992 – 14,284 61,276 Accumulated other Non- Capital comprehensive Accumulated Controlling $’000 stock loss income Interest Total Note 17 17 24 Balance as at December 31, 2022 47,257 (272) 42,631 5,670 95,286 Share repurchase (190) – (81) – (271) Dividends declared – – (5,896) – (5,896) Distribution to non-controlling interest shareholder – – (1,830) (5,670) (7,500) Foreign currency translation adjustment on foreign operations – 288 (243) – 45 Net income – – 7,014 – 7,014 Balance as at December 31, 2023 47,067 16 41,595 – 88,678 See accompanying notes to the consolidated financial statements. 64 Orca Energy Group Inc. // Annual Report & Accounts 2024 Subsidiary Registered Holding Functional currency Orca Energy Group Inc. British Virgin Islands Parent Company US dollar Orca Exploration UK Services Limited United Kingdom 100% British pound PAE PanAfrican Energy Corporation (“PAEM”) Mauritius 100% US dollar PanAfrican Energy Tanzania Limited Jersey 100% US dollar Financial Statements 65 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS General Information Orca Energy Group Inc. was incorporated on April 28, 2004 under the laws of the British Virgin Islands with its registered office located at Vistra Corporate Service Centre, Wickhams Cay II, Road Town, Tortola, British Virgin Islands, VG110. The Company produces and sells natural gas to the power and industrial sectors in Tanzania. The Company maintains central management and control and has established tax residency in the United Kingdom. The consolidated financial statements of the Company as at and for the year ended December 31, 2024 comprise accounts of the Company and its subsidiaries (collectively, the “Company” or “Orca Energy”) and were authorized for issue in accordance with a resolution of the directors on April 29, 2025. The Company is controlled by Shaymar Limited who is the registered holder of 24.8% of the equity and controls 71.6% of the total votes of the Company. The shares are held in a trust that is independently managed for the beneficiaries. 1. Nature of Operations The Company’s principal operating asset is an interest held by a subsidiary, PanAfrican Energy Tanzania Limited (“PAET”), in a Production Sharing Agreement (“PSA”) with the Tanzania Petroleum Development Corporation (“TPDC”) and the Government of Tanzania (“GoT”) in the United Republic of Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo Block offshore Tanzania. The PSA defines gas in the Songo Songo field as “Protected Gas” and “Additional Gas”. The gas agreement (“Gas Agreement”) deals further with the parties’ entitlements to Protected Gas and Additional Gas. Under the Gas Agreement, the “Protected Gas” was owned by TPDC and was sold to Songas Limited (“Songas”) and Tanzania Portland Cement PLC (“TPCPLC”). Songas is the owner of the infrastructure that enables the gas to be delivered to Dar es Salaam, which includes a gas processing plant on Songo Songo Island (“Songas Infrastructure”). Protected Gas ceased after July 31, 2024 and all production from the Songo Songo gas field following August 1, 2024 constitutes Additional Gas which PAET is entitled to sell on commercial terms. The Tanzanian Electric Supply Company Limited (“TANESCO”) is responsible for the majority of electricity generation, transmission and distribution throughout Tanzania. Natural gas has become an integral component of TANESCO’s power generation as a more reliable source of supply over seasonal hydropower as well as a more cost-effective and lower carbon dioxide intensive alternative to liquid fuels. The Company and TPDC as joint sellers currently supply Additional Gas directly to TANESCO by way of the Portfolio Gas Supply Agreement (“PGSA”). The Company also supplies Additional Gas to TPDC through a long-term gas sales agreement (“LTGSA”) utilizing the National Natural Gas Infrastructure (“NNGI”). The PGSA was extended on July 30, 2024. The PGSA and the LTGSA expire on October 10, 2026. In addition to supplying gas to TPDC and TANESCO, the Company has developed more than 50 contracts to supply gas to Dar es Salaam’s industrial market, and sells compressed natural gas to domestic, suitably converted vehicles in Dar es Salaam. On April 14, 2023, PAET formally requested TPDC to apply for an extension of the Songo Songo Development License (the “License”). In November 2024, TPDC submitted the application for the extension of the License to the MoE, however, being uneconomical, the Company informed TPDC that it did not agree with the terms as submitted. Having declined to address PAET’s concerns itself, TPDC has advised PAET to raise any issues to the MoE, which results in the Company having to have the submission rescinded and resubmitted. There are currently no certainties on the timing, nature and extent of any such extensions. Until such extension has been finalized, a high degree of uncertainty exists with respect to the extent of the Company’s operating activities subsequent to October 2026. On April 15, 2024, contrary to the terms of the Gas Agreement and PSA and in violation of PAEM and PAET’s legitimate expectations, the Permanent Secretary of the Minister of Energy of Tanzania wrote to TPDC, copying PAET and Songas, directing TPDC to “ensure that Protected Gas continue to be produced to the end of the Development Licence on 10th October 2026”. Consistent with that instruction, TPDC has taken the position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas would end after July 31, 2024. We believe that PAET will be entitled to compensation at a commercial rate for all volumes of gas lifted by Songas from August 1, 2024 to October 31, 2024. There is a risk that PAET will not receive payment or payment may form part of a contract dispute. On August 7, 2024 PAET and PAEM, issued a notice of dispute in respect of an investment treaty claim under the Agreement on Promotion and Reciprocal Protection of Investment between the Government of the Republic of Mauritius and the GoT (the “BIT”) against the GoT for breach of the BIT, alongside notifying a contractual dispute against the GoT and TPDC for breaches of: (i) the PSA, and (ii) the Gas Agreement between the GoT, TPDC, Songas and PAET, for damages in excess of $1.2 billion. Initial meetings with both the Advisory and Coordinating Committees were held during the week of October 14, 2024 without any resolution on the key issues in dispute. The matters have been further referred to the relevant entity’s chief executive officers and working groups in accordance with the dispute resolution process. Discussions have since continued with the most recent meetings having been held in March 2025. 2. Basis of Preparation Statement of Compliance The consolidated financial statements have been prepared in accordance with IFRS Accounting Standards. Basis of Measurement These consolidated financial statements have been prepared on a historical cost basis using the accrual basis of accounting. The consolidated financial statements are presented in US dollars (“$”) unless otherwise stated. Basis of Consolidation Subsidiaries Subsidiaries are those enterprises controlled by the Company. The following companies have been consolidated within the Orca Energy financial statements: Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED Transactions Eliminated Upon Consolidation Inter-company balances and transactions and any unrealized gains or losses arising from inter-company transactions are eliminated in preparing the consolidated financial statements. Foreign Currency i) Foreign Currency Transactions Transactions in foreign currencies are recorded at the rate of exchange prevailing at the date of the transaction. Monetary assets and liabilities in foreign currencies are translated at period-end rates. Non-monetary items are translated at historic rates, unless such items are carried at market value, in which case they are translated using the exchange rates that existed when the values were determined. Any resulting exchange rate differences are recognized in earnings. ii) Foreign Currency Translation Foreign currency differences are recognized in comprehensive income and accumulated in the translation reserve. The assets and liabilities of these companies are translated into the functional currency at the period-end exchange rate. The income and expenses of the companies are translated into the functional currency at the average exchange rate for the period. Translation gains and losses are included in other comprehensive income. Climate change regulations Risks related to climate change may have an impact on the Company’s operations and the Company may be subject to additional disclosure requirements in the future. The International Sustainability Standards Board issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. In addition, the Canadian Securities Administrators also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian reporting issuers. We continue to monitor developments on these reporting requirements and the impact they may have on the Company’s financial position and results of operating activities in future periods. 3. Summary of Material Accounting Policies The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements. Capital Assets i) Capital Assets Capital assets comprises the Company’s tangible natural gas assets, development wells, leasehold improvements, computer equipment, motor vehicles and fixtures and fittings carried at cost, right-of-use assets less any accumulated depletion, depreciation and accumulated impairment losses. Cost includes purchase price and construction costs for qualifying assets. Depletion of these assets commences when the assets are ready for their intended use. Only costs that are directly related to the discovery and development of specific oil and gas reserves are capitalized. The cost associated with tangible natural gas assets are amortized on a unit of production method based on commercial proven reserves, taking into account estimated forecasted future development costs necessary to bring those reserves to production. The calculation of the unit of production method by reference to the ratio of production in the period to the related proven gas reserves. ii) Impairment of Property, Plant and Equipment At each balance sheet date, the Company reviews the carrying amounts of its property, plant and equipment to determine if indicators of impairment exist. Individual assets are grouped together as a cash generating unit (“CGU”) for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are independent from other group assets. If any such indication of impairment exists, the Company makes an estimate of its recoverable amount. The recoverable amount is the higher of fair value less costs to sell and value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. In assessing the value in use, the estimated future cash flows are adjusted for the risks specific to the CGU and are discounted to their present value with a pre-tax discount rate that reflects the current market indicators. The fair value less costs to sell is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. Where an impairment loss subsequently reverses, the carrying amount of the asset CGU is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the CGU in prior years. A reversal of an impairment loss is recognized in earnings. Operatorship The Company operates the Songo Songo gas field, flowlines and gas processing plant. The Songas wells, flowlines and gas plant are operated by the Company on behalf of Songas on a ‘no gain no loss’ basis. The cost of operating and maintaining the wells and flowlines is paid for by the Company beginning from the end of the Protected Gas regime on July 31, 2024. The cost of operating the gas processing plant and pipeline to Dar es Salaam is paid by Songas. Costs incurred by the Company in connection with the operatorship of the Songas plant are recorded as receivables which are re-charged to Songas. Subsequent payments received from Songas are credited to receivables. A tariff is paid to Songas as compensation for using the gas processing plant and pipeline. Employment Benefits Long Term Retention Plan In 2023, the Company approved the cash-based long term retention award plan effective for the period from October 1, 2022 to September 30, 2026 (“Long Term Retention Plan”) to encourage retention of its employees, promote employee performance to increase shareholder value over the four year period, and align the Company’s approach to compensation with the Company’s strategy to continue and expand its operations in Tanzania. The total potential award amount payable to eligible participants is payable at an award payment date of September 30, 2026. This award amount is being recognized on a straight line basis over the four year period. Asset Retirement Obligations No provision has been made for future site restoration costs in Tanzania because the Company currently has no legal or contractual or constructive obligation under the PSA to restore the fields at the end of their commercial lives, should such occur within the term of the PSA. If an amendment to the PSA is agreed requiring the Company to restore the fields at the end of the commercial lives, a provision will be made for future site restoration costs. 66 Orca Energy Group Inc. // Annual Report & Accounts 2024 Revenue Recognition, Production Sharing Agreements and Additional Profits Tax Pursuant to the terms of the PSA, the Company has exclusive rights (i) to carry on Exploration Operations in the Songo Songo gas field; (ii) to carry on Development Operations in the Songo Songo gas field; and (iii) jointly with TPDC, to sell or otherwise dispose of Additional Gas. The Company recognizes revenue related to Additional Gas sales to all customers at specified delivery points at benchmark and contractual prices. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of natural gas occurs at the metering points at the inlet to the customer’s facility. Under the terms of the PSA, the Company pays both its share and TPDC’s share of operating, administrative and capital costs. The Company recovers all reasonably incurred operating, administrative and capital costs including TPDC’s share of these costs from future revenues over several years (“Cost Gas”). All recoveries are recorded as Cost Gas revenue in the year of recovery. The Company has gas sales contracts under which the customers are required to take, or pay for, a minimum quantity of gas. In the event that a customer has paid for gas that was not delivered, the additional income received by the Company is carried on the balance sheet as deferred revenue. If the customer consumes volumes in excess of the minimum, it will be charged at the current rate, but may receive a credit for volumes paid but not delivered. At the end of each reporting period the Company reassesses the volumes for which the customer may receive credit, any remaining balance is credited to income. In any given year, the Company is entitled to recover as Cost Gas up to 75% of the net revenue (gross revenue less processing and pipeline tariffs). Any net revenue in excess of the Cost Gas (“Profit Gas”) is shared between the Company and TPDC in accordance with the terms of the PSA. Under the PSA the Profit Gas payable to TPDC is adjusted by the amount necessary to fully pay and discharge the Company’s liability for taxes on income. Revenue represents the Company’s share of Profit Gas and Cost Gas during the period. The Company sells its natural gas to power customers (TANESCO, TPDC and Songas) and one industrial customer (a cement manufacturer) pursuant to fixed- price contracts. Sales to other industrial customers are at fixed-price discounts (subject to certain floors and ceilings) to the lowest alternative fuel source in Dar es Salaam, Heavy Fuel Oil (“HFO”) and coal. Under all contracts, the Company is required to deliver volumes of natural gas to the contract counterparty. Natural gas revenue is recognized when the Company gives up control of the natural gas which occurs at metering points located at the inlets of customers’ facilities. The amount of production revenue recognized is based on the agreed transaction price and the volumes delivered. The Company records revenues for sales to TANESCO to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract (“constrained revenue”). When determining if consideration should be constrained, management considers whether there are factors outside the Company’s control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required. The Company recognized revenue for 100% of amounts invoiced for deliveries to TANESCO during 2024 and 2023. Additional Profits Tax Under the terms of the PSA, in the event that all costs have been recovered with an annual return from the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price Index, an additional profits tax (“APT”) is payable to the Government of Tanzania. APT is provided for by forecasting the total APT payable in the future as a proportion of the forecast Profit Gas over the term of PSA license. The actual APT that will be paid is dependent on the achieved value of the Additional Gas sales and the quantum and timing of the operating costs and capital expenditure program. The PSA states that APT shall be calculated for each year and shall vary with the real rate of return earned by the Company on the net cash flow from the Contract Area (as defined in the PSA). The calculation of APT includes a working capital adjustment reflecting the effect of the timing of actual receipt of amounts owing from TANESCO on net cash flow. Income Taxes Income tax expense comprises current and deferred tax. It is recognized in profit or loss except to extent they relate to items recognized directly in equity, in which case the tax is recognized in equity. Current tax comprises the expected tax payable or receivable on the taxable income or loss for the year and any adjustments to the tax payable or receivable in respect to previous years. Where current income tax is payable, this is shown as a current tax liability. The amount of the current tax payable is the best estimate of the tax amount expected to be paid that reflects uncertainty related to income taxes, if any. It is measured using tax rates enacted or substantively enacted at the reporting date. Deferred tax is recognized using the asset and liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The amount of deferred tax provided is based on the expected manner of realization or settlement of carrying amounts of assets and liabilities using tax rates substantively enacted at the balance sheet date. A deferred tax asset is recognized only to the extent that it is probable that future taxable profits will be available, against which the asset can be utilized. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be realized. Uncertainties over positions taken in income tax filings are evaluated on the basis of whether it is probable the position taken by the Company in the tax filing will be accepted upon examination by the relevant taxing authorities. These uncertainties impact the amount of income taxes recognized. Financial Statements 67 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED Financial Instruments All financial instruments are initially recognized at fair value on the Consolidated Statements of Financial Position. The Company has classified each financial instrument into one of the following categories: (i) fair value through the statement of comprehensive income (loss), (ii) loans and receivables, and (iii) other financial liabilities. Measurement in subsequent periods depends on the classification of the financial instrument as described below: • Fair value through profit or loss: financial instruments under this classification include cash and cash equivalents and derivative assets and liabilities. • Amortized cost: financial instruments under this classification include trade and other receivables, trade and other payables, current portion of long- term loan and lease liabilities. Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has transferred substantially all risks and rewards of ownership. Financial assets and liabilities are offset and the net amount is reported on the statement of financial position when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously. Financial Instruments Classification and Measurement The Company’s financial instruments include trade and other receivables, long-term receivables, trade and other liabilities and long-term loan. The Company classifies the fair value of these financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument. • Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. • Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. The fair value of trade and other receivables and trade and other liabilities approximate their carrying amount due to the short-term nature of those instruments. The fair value of long-term receivables also approximates their carrying amount. The Company’s long-term loan (“Loan”) with the International Finance Corporation (“IFC”) is classified as Level 2 measurements. The Loan bears interest at a fixed rate which is close to the current market rates and accordingly the fair market value of the Loan approximates the carrying value. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, term deposits and short-term highly liquid investments with the original term to maturity of three months or less, which are convertible to known amounts of cash and which, in the opinion of management, are subject to an insignificant risk of changes in value. The fair value of cash and cash equivalents approximates their carrying amount. There are no restrictions on the movement of funds out of Tanzania. As of the date of this report, $24.7 million was posted as security for the full amount of the judgment in the seismic dispute and will be restricted cash until the appeal is concluded. Impairment of Financial Assets A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in earnings. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in earnings. 68 Orca Energy Group Inc. // Annual Report & Accounts 2024 Accounting Changes The following IFRS Accounting Standards became effective or were amended for financial reporting periods beginning on or after January 1, 2024. There has been no impact on the Company. • Lease Liability in a Sale and Leaseback – Amendments to IFRS 16 Leases • Classification of liabilities as Current or Non-Current and Non-current Liabilities with Covenants – Amendments to IAS 1 Presentation of Financial Statements • Amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures – Supplier Finance Arrangements The following standards have been issued but are not yet effective: • Lack of Exchangeability – Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates • Amendments to the Classification and Measurement of Financial Instruments – Amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures • Annual Improvements to IFRS Accounting Standards – Amendments to: o IFRS 1 First-time Adoption of International Financial Reporting Standards; o IFRS 7 Financial Instruments: Disclosures and its accompanying Guidance on implementing IFRS 7; o IFRS 9 Financial Instruments; o IFRS 10 Consolidated Financial Statements; and o IAS 7 Statement of Cash flows • Contracts Referencing Nature-dependent Electricity – Amendments to IFRS 9 and IFRS 7 • IFRS 18 Presentation and Disclosure in Financial Statements • IFRS 19 Subsidiaries without Public Accountability: Disclosures The Company intends to adopt these standards when they become effective and is currently evaluating the potential impact. 4. Use of Estimates and Judgments The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the accounts recognized in these consolidated financial statements. Critical Judgments in Applying Accounting Policies: A. Natural gas assets The Company assesses its natural gas assets for impairment when events or circumstances indicate that the carrying amount of its assets may not be recoverable. If any indication of impairment exists, the Company performs an impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The carrying amount of the CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell and value in use and is subject to management estimates. These estimates include quantities of reserves and future production, future commodity pricing, development costs, operating costs, and discount rates. Any changes in these estimates may have an impact on the recoverable amount of the CGU. B. Recognition of revenue and collectability of receivables The Company recognizes revenue and evaluates the collectability of its receivables on the basis of payment history, frequency and predictability, as well as Management’s assessment of the customer’s willingness and ability to pay. Management performs impairment tests each period on the Company’s current and long-term receivables. C. Statutory taxes The Company operates in Tanzania where tax authorities may audit income tax filings and the resolution of such audits may span multiple years, regardless of a successful License extension or not. Tax law in Tanzania is complex and often subject to changes and to varied interpretations; accordingly, the ultimate outcome with respect to positions taken on income tax filings may differ from the amounts recognized. The Company has taken certain tax positions in its tax filings and these tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax impact may differ significantly from that estimated and recorded by management. The recognition or reversal of deferred tax assets requires judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. The Company’s assessment of whether it is probable that the position taken by the Company will be accepted by tax authorities in Tanzania is a significant management judgment. The Company will record a tax provision where management concludes it is probable the filing position taken by the Company will not be accepted by the relevant taxing authority. Key Sources of Estimation of Uncertainty A. Reserves There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be derived therefrom, including many factors beyond the control of the Company. The reserves and estimated future net cash flow from the Company’s properties have been evaluated by independent petroleum engineers. These evaluations include a number of significant assumptions relating to factors which includes forecasted natural gas prices, production rates, operating costs, future development costs and cost recovery provisions and additional profits tax. Other assumptions include transportation costs, TPDC “back-in” methodology and other Government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Company. To date, TPDC has neither elected to back in within the prescribed notice period nor contributed any costs associated with backing in. Reserves are integral to the amount of depletion and impairment test. Financial Statements 69 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 4. Use of Estimates and Judgments continued B. Cost Recovery The Company is able to recover reasonable costs incurred on the development of the Songo Songo project out of 75% of the gross field revenue less processing and pipeline tariffs (“field net revenue”). There are inherent uncertainties in estimating when costs have been recovered as these costs are subject to Government audit and under certain circumstances a potential reassessment after the lapse of a considerable period of time. 5. Risk Management The Company, by its activities in oil and gas exploration, development and production, is exposed to the risk associated with the unpredictable nature of the financial markets as well as political risk associated with conducting operations in an emerging market. The Company seeks to manage its exposure to these risks wherever possible. A. Foreign Exchange Risk Foreign exchange risk arises when transactions and recognized assets and liabilities of the Company are denominated in a currency that is not the US dollar functional currency. The Company operates internationally and is exposed to foreign exchange risk arising from currency exposures to US dollars. The main currencies to which the Company has an exposure are: Tanzanian shillings, British pounds sterling, Euros and Canadian dollars. As of December 31, 2024, $4.0 million of the total cash and cash equivalents of $90.1 million were held in Tanzania. Of the $4.0 million, the equivalent of $3.0 million was denominated in Tanzanian shillings. The majority of contracts with customers are based on US dollar prices for gas delivered however the majority of invoices and sales receipts are paid in Tanzanian shillings. Invoices are priced and then converted to Tanzanian shillings at the time of invoicing however payments are based on the US dollar invoiced amount translated to shillings at the time of payment. While conversion of Tanzanian shillings into US dollars is unrestricted, the foreign exchange market for Tanzanian shillings is limited and not highly liquid, reducing the Company’s ability to convert large amounts of Tanzanian shillings into US dollars at any given time. To mitigate the risk of Tanzanian shilling devaluation, the Company regularly converts Tanzanian shilling receipts into US dollars and Euros to the extent available taking into consideration that the majority of operating expenditures are denominated in Tanzanian shillings. The availability of US dollars and Euros during the period has increased compared to prior periods. The majority of capital expenditures are denominated in US dollars. Capital stock and equity financing are denominated in Canadian dollars. All Loan repayments are also denominated in US dollars. There is a risk that US dollars may not be available from conversion in country for future capital requirements and loan interest payments. There are no forward exchange rate contracts in place. A 10% increase in the US dollar against the relevant foreign currency would result in an overall increase in working capital (defined as current assets less current liabilities) of $1.7 million from $21.9 million to $23.6 million and a decrease in the loss before tax from $17.2 million to $15.5 million. The sensitivity includes only outstanding foreign currency denominated monetary items and adjusts their translation at period end for a 10% change in the foreign currency rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel and represents management’s assessment of the reasonable possible change in foreign exchange rates. The following balances are denominated in foreign currency (stated in US dollars at period end exchange rates): Balances as at December 31, 2024 $’millions Tanzanian shillings Euros Canadian dollars British pounds Total Cash 3.0 0.1 1.4 – 4.5 Trade and other receivables 43.9 – – – 43.9 Trade and other liabilities (29.0) – (1.5) (0.7) (31.2) Net 17.9 0.1 (0.1) (0.7) 17.2 70 Orca Energy Group Inc. // Annual Report & Accounts 2024 B. Commodity Price Risk The Company negotiated industrial gas sales contracts with gas prices which, subject to certain floors and ceilings, are determined as a discount to the lowest cost alternative fuels in Dar es Salaam, namely Heavy Fuel Oil (“HFO”) and coal. The price of HFO is exposed to the volatility in the market price of crude oil. C. Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company has minimal exposure to interest rates as the Loan has a fixed interest rate, interest rates on short-term investments are fixed and interest received on cash balances is not significant. D. Concentration Risk All the Company’s sales are currently made in Tanzania. The sales are made to the Power sector and the Industrial sector. In relation to sales to the Power sector, the Company has a contract with TANESCO to supply gas to some of the TANESCO power plants and a contract with TPDC to supply gas through NNGI. The contracts with TANESCO and TPDC accounted for 54% of the Company’s gross field revenue during 2024 and $18.3 million of the short and long-term receivables at December 31, 2024. E. Credit Risk Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s receivables from TANESCO and TPDC. The carrying amount of accounts receivable and the long-term receivable represents the maximum credit exposure. As at December 31, 2024 and December 31, 2023, loss allowance exists against all of the long-term TANESCO receivable, gas plant operations receivables from Songas, and a receivable of $0.5 million from one industrial customer. The Company manages the credit exposure related to cash and cash equivalents by selecting counterparties based on credit ratings and monitoring all investments to ensure a stable return, avoiding complex investment vehicles with higher risk such as asset backed commercial paper. The Company’s cash resources are placed with reputable financial institutions with no history of default. During Q3 and Q4 2024, TPCPLC lifted 1,472 MMcf of Additional Gas volumes from August to December 2024. As a consequence of the position taken by TPDC, PAET was initially unable to invoice TPCPLC at prices anticipated to have been in effect under the Supplementary Gas Agreement (“SGA”). Subsequent to December 31, 2024, the SGA has been approved by TPDC with the effective date of August 1, 2024 and TPCPLC has paid the Company the $10.4 million due for the volumes lifted from August to December 2024 fully clearing the receivable outstanding as at December 31, 2024. During Q3 and Q4 2024, the Company invoiced Songas $9.6 million (including VAT and production taxes) for August, September and October 2024 liftings of Additional Gas volumes. On September 23, 2024, the Company was notified by Songas that it acknowledges it had lifted this volume, but due to TPDC’s refusal to approve a Gas Sales Agreement for this Additional Gas, they would elect to pay only 19.5% of such volumes. The Company recognized the payment of $1.9 million, being 19.5% of the August, September and October 2024 sales to Songas in revenue; these amounts were paid by Songas in Q4 2024. As of the date of this report, $7.7 million of August, September and October 2024 sales representing 80.5% of delivered volumes remain unrecognized. There is a risk that PAET will not receive compensation for the volumes, which were lifted after August 1, 2024 and which, notwithstanding the contractual termination of Protected Gas, TPDC asserts should be treated as Protected Gas. F. Liquidity Risk Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities. Cash forecasts identifying liquidity requirements of the Company are produced on a regular basis. These are reviewed to ensure sufficient funds exist to finance the Company’s current operational and investment cash flow requirements. At December 31, 2024 the Company has working capital, defined as total current assets less total current liabilities, of $21.9 million which is net of $113.8 million of financial liabilities with regards to trade and other liabilities of which $56.6 million is due within one to three months, $32.1 million is due within three to six months, and $25.1 million is due within six to twelve months (see Note 14). As at December 31, 2024 approximately 26% of the current liabilities relate to the long-term loan (“Loan”) from the International Finance Corporation (“IFC”) to PAET. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan, pursuant to a loan agreement dated October 29, 2015 between IFC, PAET and the Company (the "Loan Agreement"). To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. As at December 31, 2024 approximately 14% of the current liabilities relate to TPDC (see Note 14). The amounts due to TPDC represent its share of Profit Gas. In accordance with the terms of the PSA, TPDC is entitled to the payment of its share of Profit Gas on a quarterly basis proportional to the cash receipts during the quarter. A substantial proportion of the TPDC liability is associated with the long-term TANESCO arrears and payments to TPDC are made when cash is received for the arrears. COVID-19 reduced travel throughout the world. Tourism is a major source of revenue and foreign currency for Tanzania and the decrease in travel combined with global economic slowdown have seen an increasing decline in foreign exchange reserves in Tanzania. During 2023 and 2024, it has been more difficult for the Company to convert Tanzanian shillings directly to US dollars in country, however, as at the date of this report, this has not significantly impacted PAET’s ability to meet its US dollar liabilities or obligations. There is a risk that in the future the Company may not be able to convert Tanzanian shillings to US dollars or other hard currencies as and when required to attract capital. It is unknown how long this risk will continue. There is a risk that PAET will not receive compensation for the volumes, which were lifted after August 1, 2024, and which, notwithstanding the contractual termination of Protected Gas, TPDC asserts should be treated as Protected Gas. If this is the case, these volumes may not meet the definition of revenue under IFRS 15, so would not be reflected as revenue going forward until the potential dispute is resolved. There is a risk that in October 2026 the License will expire, if an extension is not obtained. If a License extension is not forthcoming, various litigation matters discussed in the MD&A may survive the expiry date, which may impact the liquidity post such date. 71 Orca Energy Group Inc. // Annual Report & Accounts 2024 G. Capital Risk Management The Company’s objectives when managing capital are to safeguard the Company’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to achieve an optimal capital structure to reduce the cost of capital. H. Country Risk The Company has unresolved disputes with TPDC related to Cost Gas revenue, TANESCO and Songas regarding unpaid invoices, and the Tanzanian Revenue Authority (“TRA”) in relation to tax disputes (see Note 21). The Company continues to rely upon its rights under the existing PSA and has initiated notices of disputes as required under the PSA and by local tax regulations to resolve outstanding issues. The Company’s principal operating asset is an interest held by a subsidiary, PAET, in the PSA. The PSA is set to expire in October 2026, and there are currently no certainties on the timing, nature and extent of any such extensions. Until such extension has been finalized, a high degree of uncertainty exists with respect to the extent of the Company’s operating activities subsequent to October 2026. 72 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 6. Segment Information The Company has one reportable industry segment which is international exploration, development and production of petroleum and natural gas. During 2024 and 2023 the Company’s producing assets were entirely located in Tanzania, with all of the Company’s gas revenue derived solely from customers in Tanzania. Included in 2024 revenues arising from Tanzania, are revenues of $41.2 million, $26.4 million and $13.8 million which arose from the Company’s three largest customers (2023: $47.1 million, $38.4 million and $10.9 million), who each contributed more than 10% to the Company’s 2024 and 2023 gross field revenue (see Note 7). The largest two customers in 2024 and 2023 are parastatal companies controlled by the Government of Tanzania. 7. Revenue Years ended December 31 $’000 2024 2023 Industrial sector 49,693 43,694 Power sector 74,926 97,378 Gross field revenue 124,619 141,072 TPDC share of revenue (25,843) (47,364) Company operating revenue 98,776 93,708 Current income tax adjustment 12,817 16,527 111,593 110,235 8. Personnel Expenses Years ended December 31 $’000 2024 2023 Employee and related costs included in: Production, distribution and transportation 3,112 3,137 General and administrative 8,775 8,644 11,887 11,781 Stock based compensation – 6 Long Term Retention Plan 1,200 1,500 13,087 13,287 Personnel expenses include Company employees who operate the Songas facilities on behalf of Songas; these expenses are recharged to Songas. 73 The Company recognized 100% of all gas deliveries to TANESCO as revenue during 2024 and 2023. During 2024 the Company invoiced TANESCO $51.1 million (2023: $32.9 million) for gas deliveries and received payments of $44.2 million (2023: $30.8 million) for 2024 gas deliveries. These amounts are inclusive of value added tax (“VAT”). Based on the consistent payments from TANESCO, the Company recognized all amounts invoiced for gas deliveries in 2024 and 2023 as revenue. Subsequent to December 31, 2024, the Company has collected all outstanding amounts for 2024 gas deliveries. During Q3 and Q4 2024, the Company invoiced Songas $9.6 million (including VAT and production taxes) for August, September and October 2024 liftings of Additional Gas volumes. On September 23, 2024, the Company was notified by Songas that it acknowledges it had lifted this volume, but due to TPDC’s refusal to approve a Gas Sales Agreement for this Additional Gas, they would elect to pay only 19.5% of such volumes. The Company recognized the payment of $1.9 million, being 19.5% of the August, September and October 2024 sales to Songas in revenue; these amounts were paid by Songas in Q4 2024. As of the date of this report, $7.7 million of August, September and October 2024 sales representing 80.5% of delivered volumes remain unrecognized. During Q3 and Q4 2024, TPCPLC lifted 1,472 MMcf of Additional Gas volumes from August to December 2024. As a consequence of the position taken by TPDC, PAET was initially unable to invoice TPCPLC at prices anticipated to have been in effect under the SGA. Subsequent to December 31, 2024, the SGA has been approved by TPDC with the effective date of August 1, 2024 and TPCPLC has paid the Company the $10.4 million due for the volumes lifted from August to December 2024 fully clearing the receivable outstanding as at December 31, 2024. In 2024, the Company recognized $41.2 million (2023: $47.1 million) for TANESCO, $7.3 million (2023: $11.9 million) for Songas and $13.8 million (2023: $10.9 million) for TPCPLC in gross field revenue. Orca Energy Group Inc. // Annual Report & Accounts 2024 9. Finance Income and Expense Finance Income Years ended December 31 $’000 2024 2023 Interest income 3,665 1,888 Finance Expense Years ended December 31 $’000 2024 2023 Base interest expense 3,808 4,850 Participation interest expense 914 2,970 Lease interest expense 48 14 Interest expense 4,770 7,834 Net foreign exchange loss 7,681 5,001 Indirect tax 1,300 1,273 Trade and other receivables write off – 830 13,751 14,938 Base interest expense and participation interest expense relate to the Loan from the IFC to PAET. Base interest on the Loan was payable quarterly in arrears at 10% per annum on a “pay-if-you-can-basis” using a formula to calculate the net cash available for such payments as at any given interest payment date. The participation interest expense is paid annually in arrears and equates to 6.4% of PAET’s net cash flows from operating activities net of net cash flows used in investing activities for the year. Such participation interest will continue to accrue until October 15, 2026 regardless of early repayment of the Loan. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan made by the IFC to PAET, pursuant to the Loan Agreement. The Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding (see Note 16). Net foreign exchange loss includes realized and unrealized revaluation gains and losses. The unrealized revaluation gain is mainly due to the reversal of previously recognized unrealized temporary changes in the fair value of cash balances denominated in Tanzanian shillings that are now considered permanent in nature and recognized as realized exchange losses. The indirect tax includes VAT on the invoices to TANESCO for interest on late payments. The indirect tax is for VAT associated with invoices to TANESCO for interest on late payments. The trade and other receivables write off in 2023 relates to VAT on interest invoices to Songas relating to unpaid invoices and an advance which was paid to a supplier and could not be recovered. Loss allowance Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Loss allowance 21,700 – 21,700 – Reversal of loss allowance – (4,901) – (6,915) 21,700 (4,901) 21,700 (6,915) The loss allowance in 2024 follows $21.7 million allowed with respect to ongoing litigation in the High Court of Tanzania and represents the amount required to increase the provision to cover the current gross liability before any cost recovery, following the criteria of IAS 37 (Provisions, Contingent Liabilities and Contingent Assets). The reversal of loss allowance in 2023 follows: (i) the recognition of $4.9 million resulting from agreement with Songas on a revision to the cost sharing in respect of the 2015-2016 workover of the SS-5 and SS-9 wells; and (ii) indirect taxation of $2.0 million relating to the 2020 and 2021 take or pay invoices to TANESCO that were paid in 2023. 74 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 10. Income Taxes The tax charge is as follows: Years ended December 31 $’000 2024 2023 Current income tax 13,737 16,133 Deferred income tax (15,508) (6,161) (1,771) 9,972 Tax of $0.8 million was paid during 2024 in relation to the settlement of the prior year’s tax liability (2023: $1.9 million). Installment tax payments totaling $8.5 million were made in respect of 2023 (2023: $15.0 million). These are presented as a reduction in tax payable on the Consolidated Statements of Financial Position. Tax Rate Reconciliation Years ended December 31 $’000 2024 2023 (Loss) / income before tax per Consolidated Statements of Comprehensive Income (17,159) 25,148 Less Additional Profits Tax (6,190) (8,162) (Loss) / income before statutory tax (23,349) 16,986 Provision for income tax calculated at the statutory rate of 30% (7,005) 5,096 Effect on income tax of: Administrative and non-deductible expenses 2,436 1,485 Foreign rate difference 555 1,006 Stock based compensation – 1 TANESCO interest not recognized as interest income 2,166 2,122 Change in unrecognized tax asset 390 (222) Changes in estimates (313) 484 (1,771) 9,972 As at December 31, 2024 the loss allowance for TANESCO had resulted in a $23.5 million unrecognized deferred tax asset (December 31, 2023: $21.3 million). If this debt is ultimately not recovered, the Company will also be entitled to a $14.1 million (2023: $12.8 million) refund of VAT. As at December 31, 2024, the Company has not recognized the benefit of unused trading loss carry forwards of $21.1 million (2023: $18.6 million), which do not expire, as it is not probable that future taxable profits will be available against which the benefit can be utilized. In respect of each type of temporary difference the amounts of deferred tax assets/(liabilities) recognized in the consolidated balance sheet were as follows: As at December 31 $’000 2024 2023 Differences between tax base and carrying value of property, plant and equipment (12,438) (21,853) Tax recoverable from TPDC (5,887) (6,808) Loss allowances 6,863 353 Additional Profits Tax 4,170 7,108 Deferred income included in taxable income 2,621 – Unrealized exchange gains and losses / other provisions 84 1,105 (4,587) (20,095) 11. Additional Profits Tax Under the terms of the PSA, APT is payable when the Company has recovered its costs plus a specified return out of Cost Gas revenue and Profit Gas revenue. As a result: (i) no APT is payable until the Company recovers its costs out of Additional Gas revenues plus an annual operating return under the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum APT rate is 55% of the Company’s Profit Gas when costs have been recovered with an annual return of 35% plus the percentage change in PPI. The timing and the effective rate of APT depends on the realized value of Profit Gas which in turn depends on the level of expenditure. The Company provides for APT by annually forecasting the total APT payable in the future as a proportion of the forecast Profit Gas over the term of the PSA. The forecast takes into account the timing of future development capital spending. As at December 31, 2024 the current portion of APT payable was estimated at $7.8 million (December 31, 2023: $16.0 million) with a long-term APT payable of $5.9 million (December 31, 2023: $7.5 million). The effective APT rate of 20.2% (2023: 14.5%) has been applied to the Company’s share of Profit Gas revenue of $30.7 million for the year ended December 31, 2024 (2023: $56.2 million). Accordingly, $6.2 million for the year ended December 31, 2024 (2023: $8.2 million) of APT has been recorded in the Consolidated Statements of Comprehensive Income. 75 Orca Energy Group Inc. // Annual Report & Accounts 2024 12. Current Trade and Other Receivables As at December 31 $’000 2024 2023 Trade receivables Songas – 2,389 TPCPLC 10,409 3,625 TPDC 5,592 3,841 TANESCO 12,731 5,851 Industrial customers 8,149 7,875 Loss allowance (452) (452) 36,429 23,129 Other receivables Songas gas plant operations 2,161 3,127 Songas well workover program – 2,630 Other 6,172 4,676 Loss allowance (725) (725) 7,608 9,708 44,037 32,837 Trade Receivables Aged Analysis As at December 31, 2024 $’000 Current >30 <60 >60 <90 >90 Total 35,854 – 88 487 36,429 As at December 31, 2023 $’000 Current >30 <60 >60 <90 >90 Total 22,191 66 – 872 23,129 Songas As at December 31, 2024 Songas owed the Company $2.2 million (December 31, 2023: $8.1 million), while the Company owed Songas $2.7 million (December 31, 2023: $3.0 million). The amounts due to the Company are for the operation of the gas plant of $2.2 million (December 31, 2023: $3.1 million) against which the Company has made a loss allowance of $0.7 million (December 31, 2023: $0.7 million). In addition, as of December 31, 2023 Songas owed the Company $2.4 million for sales of gas. The amounts due to Songas primarily relate to pipeline tariff charges of $2.1 million (December 31, 2023: $2.3 million). The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis. During Q3 and Q4 2024, the Company invoiced Songas $9.6 million (including VAT and production taxes) for August, September and October 2024 liftings of Additional Gas volumes. On September 23, 2024, the Company was notified by Songas that it acknowledges it had lifted this volume, but due to TPDC’s refusal to approve a Gas Sales Agreement for this Additional Gas, they would elect to pay only 19.5% of such volumes. The Company recognized the payment of $1.9 million, being 19.5% of the August, September and October 2024 sales to Songas in revenue; these amounts were paid by Songas in Q4 2024. As of the date of this report, $7.7 million of August, September and October 2024 sales representing 80.5% of delivered volumes remain unrecognized. TPCPLC During Q3 and Q4 2024, TPCPLC lifted 1,472 MMcf of Additional Gas volumes from August to December 2024. As a consequence of the position taken by TPDC, PAET was initially unable to invoice TPCPLC at prices anticipated to have been in effect under the SGA. Subsequent to December 31, 2024, the SGA has been approved by TPDC with the effective date of August 1, 2024 and TPCPLC has paid the Company the $10.4 million due for the volumes lifted from August to December 2024 fully clearing the receivable outstanding as at December 31, 2024. TPDC The current receivable from TPDC is for gas deliveries through the NNGI pursuant to the signing of the LTGSA. In accordance with the LTGSA, any unpaid, overdue amounts are offset against TPDC profit share. 76 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 13. Capital Assets $’000 Natural gas interests Office and other Right-of-use Total Costs As at December 31, 2023 297,027 3,106 1,987 302,120 Additions 27,233 315 57 27,605 Disposals (202) – – (202) Asset impairment (25,856) – – (25,856) As at December 31, 2024 298,202 3,421 2,044 303,667 Accumulated depletion and depreciation As at December 31, 2023 218,681 2,889 1,169 222,739 Additions 30,506 209 308 31,023 Disposals (152) – – (152) As at December 31, 2024 249,035 3,098 1,477 253,610 Net book values As at December 31, 2024 49,167 323 567 50,057 $’000 Natural gas interests Office and other Right-of-use Total Costs As at December 31, 2022 290,001 3,189 1,135 294,325 Additions 7,984 119 852 8,955 Disposals (958) (202) – (1,160) As at December 31, 2023 297,027 3,106 1,987 302,120 Accumulated depletion and depreciation As at December 31, 2022 177,541 2,971 917 181,429 Additions 41,857 120 252 42,229 Disposals (717) (202) – (919) As at December 31, 2023 218,681 2,889 1,169 222,739 Net book values As at December 31, 2023 78,346 217 818 79,381 In determining the depletion charge the Company takes into account an estimate of future development costs, the capital expenditure required to ensure the Company can produce the required gas volumes to meet its contractual obligations for the remaining life of the license. As at December 31, 2024, the estimated future development costs required to bring the total proved reserves to production were $1.4 million (December 31, 2023: $16.6 million). The decrease in estimated future development costs is a result of downward revision of the future cost estimates. During the year the Company recorded depreciation of $0.5 million (2023: $0.4 million) in general and administrative expenses. Asset Impairment Three Months ended Year ended December 31 December 31 $’000 2024 2023 2024 2023 Asset impairment 26,651 – 26,651 – 26,651 – 26,651 – During the year, the Company performed a workover on the SS-7 well. The work program sought to restore the mechanical integrity of the well to shutoff water production in order to restart production from the southern compartment of the Songo Songo gas field. Following water shut off and reperforation of the Neocomian sands, limited and unsustained gas flows were observed. Having completed all possible downhole work the Company has ceased well intervention operations. The program will not be pursued in the foreseeable future. Accordingly. the Company has tested the SS-7 well workover project for impairment on a stand-alone basis and recorded an impairment expense of $25.9 million, the full project cost. At December 31, 2024, the Company performed an impairment test of the remaining CGU and no further impairment was necessary. In addition during the year, the Company recorded a write off of a trade receivable of $0.8 million which relates to an advance which was paid to a supplier and could not be recovered. Orca Energy Group Inc. // Annual Report & Accounts 2024 13. Capital Assets continued Right-of-use assets $’000 As at December 31, 2023 818 Additions 57 Depreciation (308) As at December 31, 2024 567 As at December 31, 2022 218 Additions 852 Depreciation (252) As at December 31, 2023 818 Lease liabilities $’000 As at December 31, 2023 717 Additions 57 Lease interest expense 48 Lease payments (343) As at December 31, 2024 479 As at December 31, 2022 170 Additions 852 Lease interest expense 14 Lease payments (324) Lease foreign currency translation difference 5 As at December 31, 2023 717 Right-of-use assets are presented as part of capital assets on the Company’s balance sheet. Of the total lease liability of $0.5 million (December 31, 2023: $0.7 million), $0.3 million (December 31, 2023: $0.2 million) is current and is presented in trade and other liabilities. 78 Orca Energy Group Inc. // Annual Report & Accounts 2024 14. Trade and Other Liabilities As at December 31 $’000 2024 2023 Songas 2,741 2,981 Other trade payables 9,981 2,331 Trade payables 12,722 5,312 TPDC Profit Gas entitlement, net 16,359 17,199 Deferred income – take or pay contracts 943 1,144 Accrued liabilities 36,827 14,752 66,851 38,407 TPDC share of Profit Gas As at December 31 $’000 2024 2023 TPDC share of Profit Gas 29,076 26,075 Less “Adjustment Factor” (12,717) (8,876) TPDC share of Profit Gas entitlement 16,359 17,199 Under the PSA revenue sharing mechanism, the Company adjusts TPDC’s Profit Gas share by the “Adjustment Factor”. The Adjustment Factor is equal to the amount necessary to fully pay and discharge the PAET liability for taxes on income derived from petroleum operations. A significant percentage of the settlement of the $29.1 million liability to TPDC for its share of Profit Gas is dependent on receipt of payment from TANESCO for long-term arrears that have been fully allowed for. 79 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 15. Long-term Receivables As at December 31 $’000 2024 2023 105,210 89,809 (12,731) (5,851) (70,461) (61,940) Amounts invoiced to TANESCO Current trade receivables – TANESCO (see note 12) Unrecognized amounts1 Loss allowance (22,018) (22,018) Net TANESCO receivable – – Lease deposit 10 10 10 10 1 The amount includes invoices for interest on late payments from TANESCO. The Company recognized 100% of amounts invoiced for deliveries to TANESCO as revenue during 2024 and 2023. 16. Long-term Loan In 2015 PAET took out the Loan with the IFC, a member of the World Bank Group, for $60 million. The Loan was fully drawn down in 2016. The Loan was to be paid out through six semi-annual payments of $5.0 million starting October 15, 2022 and one final payment of $25.2 million due on October 15, 2025. The Loan was an unsecured subordinated obligation of PAET. Pursuant to the sale of the non-controlling interest in PAEM, the parent company of PAET, in 2018, the Company agreed with the IFC to reduce the outstanding amount of the Loan by the percentage interest sold of 7.933% ($4.8 million) before the fourth anniversary of the first drawdown. PAET made this payment on October 16, 2019. Dividends and distributions from PAET were restricted if at any time amounts of interest, principal or participating interest are due and outstanding. All amounts due under the Loan have been paid when due. Subsequent to December 31, 2024, the Company fully prepaid the Loan. To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. As of the date hereof, the annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. As at December 31 $’000 2024 2023 Loan principal 30,240 40,240 Financing costs (118) (279) Current portion of long-term loan (30,122) (10,000) – 29,961 80 Orca Energy Group Inc. // Annual Report & Accounts 2024 17. Capital Stock Authorized 50,000,000 Class A common shares (“Class A Shares”) No par value 100,000,000 Class B subordinate voting shares (“Class B Shares”) No par value 100,000,000 First preference shares No par value The Class A and Class B Shares rank pari passu in respect of dividends and repayment of capital in the event of winding-up. Class A Shares carry twenty (20) votes per share and Class B Shares carry one (1) vote per share. The Class A Shares are convertible at the option of the holder at any time into Class B Shares on a one-for-one basis. The Class B Shares are convertible into Class A Shares on a one-for-one basis in the event that a take-over bid is made to purchase Class A Shares which must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the holders of Class A Shares and which is not concurrently made to holders of Class B Shares. Changes in the capital stock On November 1, 2023 the Company announced a normal course issuer bid (“2023 NCIB”) to commence on November 6, 2023 to purchase Class B Shares through the facilities of the TSX Venture Exchange and alternative trading systems in Canada. As at December 31, 2024 the Company had repurchased for cancellation 70,200 Class B Shares at a weighted average price of CDN$4.38 pursuant to the 2023 NCIB. On November 15, 2024 the Company announced a normal course issuer bid (“2024 NCIB”) to commence on November 18, 2024 to purchase Class B Shares through the facilities of the TSX Venture Exchange and alternative trading systems in Canada. As at December 31, 2024 the Company had not repurchased any Class B Shares for cancellation pursuant to the 2024 NCIB. All issued capital stock is fully paid. Dividend Summary Declaration date Record date Payment date Amount per share (CDN$) February 14, 2025 March 31, 2025 April 14, 2025 0.10 November 12, 2024 December 31, 2024 January 14, 2025 0.10 August 21, 2024 September 30, 2024 October 14, 2024 0.10 May 15, 2024 June 28, 2024 July 12, 2024 0.10 February 1, 2024 March 29, 2024 April 12, 2024 0.10 18. (Loss) / earnings Per Share As at December 31 (000) 2024 2023 Outstanding shares Weighted average number of Class A and Class B Shares, basic 19,780 19,841 Weighted average number of Class A and Class B Shares, diluted 19,780 19,841 The calculation of basic (loss) / earnings per share is based on a net loss attributable to shareholders for the year of $21.6 million (2023: net income attributable to shareholders of $7.0 million) and a weighted average number of Class A and Class B Shares outstanding during the period of 19,780,178 (2023: 19,841,448). 81 Orca Energy Group Inc. // Annual Report & Accounts 2024 19. Related Party Transactions The Chair of the Company’s Board of Directors is Counsel of Burnet, Duckworth & Palmer LLP, a law firm that provides legal advice to the Company and its subsidiaries. During the year ended December 31, 2024 fees for services provided by this firm totaled $0.7 million (2023: $0.8 million). As at December 31, 2024 the Company had a total of $0.05 million (December 31, 2023: $0.6 million) recorded in trade and other liabilities in relation to related parties. 20. Contractual Obligations Protected Gas Under the terms of the Gas Agreement for the Songo Songo project, in the event that there is an insufficiency in Protected Gas as a consequence of the sale of Additional Gas, the Company is liable to pay the difference between the price of Protected Gas ($0.55/MMbtu escalated) and the price of an alternative feedstock in respect of whichever is the lesser of either (i) of the volume of Additional Gas sold which was 347 Bcf as at December 31, 2024 (December 31, 2023: 320 Bcf) or (ii) the insufficiency volume. The Company had been managing its reserves and did not have a shortfall during the reporting period up to and including the end of the Protected Gas delivery obligation, which ceased after July 31, 2024. Terms of the Gas Agreement were modified by the Amended and Restated Gas Agreement (“ARGA”) which was initialed by all parties but remains unsigned. In certain respects, the parties thereto are conducting themselves as though the ARGA is in effect. Management does not foresee a material risk with the conduct of the Company’s business with an unsigned ARGA at this time. On April 15, 2024, contrary to the terms of the Gas Agreement and PSA and in violation of PAEM and PAET’s legitimate expectations, the Permanent Secretary of the MoE wrote to TPDC, copying PAET and Songas, directing TPDC to “ensure that Protected Gas continue to be produced to the end of the Development Licence on 10th October 2026”. Consistent with that instruction, TPDC has taken the position that Protected Gas should continue despite the parties’ contractual agreement that Protected Gas would cease after July 31, 2024. It is our belief that PAET is entitled to payment at a commercial rate for all volumes of gas lifted by Songas and TPCPLC starting on August 1, 2024. Gas has continued to be lifted following August 1, 2024. Subsequent to December 31, 2024, PAET, TPDC and TPCPLC agreed the terms of the SGA to sell volumes as Additional Gas, which, prior to August 1, 2024, were supplied as Protected Gas. TPCPLC has fully paid the Company $10.4 million of the receivable outstanding as at December 31, 2024. There is a risk however that PAET will not receive payments from Songas or payments may form part of a contract dispute and this may adversely impact the Company’s ability to finance its capital requirements. On August 7, 2024, PAET and PAEM, issued the Notice of Dispute in respect of an investment treaty claim under the BIT against the GoT for breach of the BIT, alongside notifying a contractual dispute against the GoT and TPDC for breaches of: (i) the PSA, and (ii) the Gas Agreement between the GoT, TPDC, Songas and PAET, for damages in excess of $1.2 billion. Initial meetings with both the Advisory and Coordinating Committees were held during the week of October 14, 2024 without any resolution on the key issues in dispute. The matters have been further referred to the relevant entity’s chief executive officers and working groups in accordance with the dispute resolution process. Discussions have since continued with meetings most recently held in March 2025. Re-Rating Agreement In 2011 the Company, TPDC and Songas signed a Re-Rating Agreement which evidenced an increase to the gas processing capacity of the Songas Infrastructure to a maximum of 110 MMcfd (the pipeline and delivery pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-Rating Agreement, the Company paid additional compensation of $0.30/mcf for sales between 70 MMcfd and 90 MMcfd and $0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in addition to the tariff of $0.59/mcf payable to Songas as set by the energy regulator, EWURA. Although Songas notified the Company in 2014 that the Re-Rating Agreement was terminated, the parties have continued to produce, transport and sell gas volumes in line with the re-rated plant capacity. In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd would no longer be paid effective June 2016. The additional compensation was always intended to be temporary in nature until the expansion of the Songas Infrastructure, at which time Songas would apply to EWURA to obtain approval of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff charged to the Company in the event that a new tariff is approved. The parties to the Re-Rating Agreement are in the process of negotiating a replacement agreement which may address the additional compensation paid. In the interim, the processing capacity at the Songas Infrastructure remains unaltered and is fully available for utilization by the Company. This capacity is in addition to the capacity available within the NNGI. Portfolio Gas Supply Agreement (“PGSA”) On June 17, 2011, the PGSA was signed (term to June 2023) between TANESCO (as the buyer) and the Company and TPDC (collectively as the seller). TANESCO requested a change to the PGSA maximum daily quantity (“MDQ”) in accordance with clause 7.6(b) which PAET and TPDC approved effective January 29, 2018. In accordance with the PGSA, when calculating aggregate excess, extra and overtake gas through the supply period, the MDQ was reduced and the seller is now obligated, subject to infrastructure capacity, to sell a maximum of approximately 16 MMcfd (previously 26 MMcfd) for use in any of TANESCO’s current power plants, except those operated by Songas at Ubungo. Previously under the PGSA any sales in excess of 36 MMcfd were subject to a 150% increase in the basic wellhead gas price. On December 22, 2018 a side letter amendment to the PGSA was agreed with TPDC to allow PGSA volumes up to a maximum monthly average volume of 35 MMcfd to temporarily flow through the NNGI. The temporary arrangement was terminated in September 2019 once the refrigeration unit became fully operational and all PGSA volumes were again processed through the Songas Infrastructure. In 2023, the PGSA, which was due to expire on June 30, 2023, was extended to a new expiry date of July 31, 2024. On July 30, 2024, the PGSA was extended to October 10, 2026. Long-term Gas Sales Agreement (“LTGSA”) On May 14, 2019 the Company and TPDC signed the LTGSA for an initial delivery of 20 MMcfd through the NNGI, at a price of $3.10/MMbtu as at January 1, 2019, (escalating 2% per annum) exclusive of any processing and transportation tariff associated with the NNGI. The LTGSA was amended on September 24, 2019 to increase the volumes supplied through the NNGI up to a MDQ of 30 MMcfd. In 2020 parties established a 12-month renewable agreement for the supply of volumes above 30 MMcfd on an ad-hoc basis, allowing TPDC to meet fluctuating demand and compensate for shortfalls in production from their Madimba plant without being penalized due to a higher, fixed contractual limit and the subsequent take-or-pay penalties should the demand reduce again. The agreement has allowed the Company to supply volumes in excess of 50 MMcfd on occasion, increasing average sales volumes and revenues. The LTGSA expires on October 10, 2026. 82 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 21. Contingencies Upstream and Downstream Activities The Petroleum Act, 2015 (the “Petroleum Act”) provides TPDC with exclusive rights over the distribution of gas in Tanzania. The Petroleum Act has grandfathering provisions upholding the rights of the Company to develop and market natural gas produced under the PSA as it was signed prior to the Petroleum Act coming into effect in 2015. On October 7, 2016 the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under Sections 165 and 258 (I) of the Petroleum Act. Article 260 (3) of the Petroleum Act preserves the Company’s pre-existing right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party natural gas customers. To date there has been no impact on the Company as a result of the Natural Gas Pricing Regulation, however, any future impact cannot be determined at this time. Cost Recovery TPDC conducted an audit of historical costs (the “Cost Pool”) and in 2011 objected approximately $34.0 million of costs that had been recovered from the Cost Pool from 2002 through to 2009. In 2014 a portion of the objected costs were agreed to be cost recoverable from TPDC with $25.4 million remaining as being objected. Under the dispute mechanism outlined in the PSA, parties are to agree the appointment of an independent specialist to assist the parties in reaching agreement on costs that are still subject to queries . In 2014, prior to appointing an independent specialist, TPDC suspended the process. From 2010 to 2015 TPDC rejected a further $16.8 million of costs. In 2016 the Tanzanian Petroleum Upstream Regulatory Authority (“PURA”) assumed the role of auditing the PSA Cost Pool from TPDC and for 2016 to 2020 have rejected all costs pertaining to downstream development amounting to $15.0 million and a further $9.5 million of other costs. In 2022 the Company and PURA negotiated a settlement on certain rejections with respect to 2016 to 2018 audits. As a result of this, $2.7 million was credited to the Cost Pool in Q2 2022. In 2023 the Company and PURA negotiated a settlement on certain rejections with respect to 2019 to 2020 audits. As a result of this, $0.7 million was credited to the Cost Pool in Q2 2023. In Q4 2023, the Company credited to the Cost Pool an additional $0.03 million with respect to 2021 audit. In Q4 2024, the Company further credited to the Cost Pool an additional $0.26 million with respect to 2021 audit. To date there remains a total of $62.5 million (2023 adjusted - $61.6 million) of costs that have been queried or rejected by TPDC or PURA through the Cost Pool audit process. The 2023 amounts were previously disclosed as $66.6 million in the December 31, 2023 Consolidated Financial Statements. During 2019, discussions on the disputed amounts briefly resumed with TPDC. At the time of writing this report no independent specialist has been appointed and neither TPDC nor PURA have issued a formal dispute regarding cost recovery. The Company’s view is that all costs have been correctly included in the Cost Pool, however should any of the costs be rejected as not being cost recoverable, the Company would be required to retroactively adjust its share of revenue for the period under dispute. 83 Orca Energy Group Inc. // Annual Report & Accounts 2024 21. Contingencies continued Taxation The following table provides a summary of the Company’s tax contingencies that are outstanding with the Tanzanian tax authorities: As at December 31 Amounts in $’millions 2024 2023 Area Period Reason for dispute Principal Interest and penalties Total Total Income tax 2008-09, 2011-20 Deductibility of capital expenditures and expenses (2012, 2015 and 2016), additional income tax (2008, 2011 and 2012), foreign exchange rate application (2013 to 2015, 2018 to 2020), underestimation of tax due (2014, 2016 and 2020) and methodology of grossing up income taxes paid (2015 to 2017). 21.8 15.9 37.7(1) 34.1 Tax on repatriated income 2012-21 Applicability of withholding tax on repatriated income (2012 to 2021) 21.4 5.7 27.1(2) 24.4 VAT 2012-23 VAT already paid (2012 to 2014), VAT on imported services (2015 and 2016); interest on VAT decreasing adjustments (2017), input VAT on services (2017 to 2020) and VAT on income tax and production taxes (2019 to 2023). 13.1 3.5 16.6(3) 1.5 56.3 25.1 81.4 60.0 During 2022, following the expiry of the statutory deadline for the TRA to respond to the Company’s objections, the Company filed notices of intention to appeal to the Tanzania Revenue Appeals Board (“TRAB”) against the corporate income tax assessments for the years of 2012 to 2016, tax on repatriated income for the years of 2012 to 2014, and VAT for the years of 2015 to 2016. In May 2023, the TRA issued final corporate income tax assessments for the years of 2012 to 2016 agreeing to drop certain claims with respect to previously assessed corporate income tax for the years of income of 2012 and 2016. These claims are no longer represented in the table above. As of December 31, 2024, years of income of 2021 to 2024 remain open for audit. Corporate income tax In 2024, the Company withdrew its application for the Court of Appeal of Tanzania (“CAT”) to review its judgment on the corporate income tax for the year of 2009 ($2.3 million). The matter is now marked withdrawn. Parties will now negotiate on the implementation of CAT’s judgment of 2018 in favor of TRA. At an earlier judgment, TRAB, while ruled in favour of the TRA, also allowed the Company to utilize the depreciation allowance, which was the issue in dispute, in subsequent years. The Company had already made provision in the accounts for the amount in dispute. In Q2 2022, the Tax Revenue Appeals Tribunal (“TRAT”) pronounced its judgment on the corporate income tax appeal for the year 2010 ($2.3 million) in favor of the TRA. The Company filed a notice of intention to appeal at the CAT. In Q3 2022, the Company filed a memorandum of appeal. The hearing took place on February 25, 2025 and was adjourned for a later date. The Company had already made provision in the accounts for the amount in dispute. In Q3 2023, the TRAT pronounced its judgment on the corporate income tax appeal for the year 2011 ($1.6 million) in favor of the TRA. The Company filed a notice of intention to appeal at the CAT. In Q4 2023, the Company filed a memorandum of appeal and is now awaiting a hearing date. In Q4 2023, the Company recorded a provision of approximately $0.3 million being the Company's share of the income assessed. On January 31, 2025 and February 7, 2025 the Company’s appeals against the corporate income tax assessments for the years of 2012 and 2013 ($12.2 million) came for a hearing at TRAB. The hearing is ongoing and is now scheduled to continue in Q2 2025. In Q4 2022, the TRA issued six assessments for income tax and for ensuing interest on deemed delayed payments ($0.5 million) for the years of 2018 to 2020. The Company objected to the assessments on the grounds of incorrect disallowance of expenses and use of exchange rates. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q4 2023, the Company filed statements of appeal at the TRAB. In Q1 2024, the appeals came for a hearing at TRAB and the parties are now awaiting TRAB’s decision. Tax on repatriated income In Q4 2023, during the TRAB hearing of the appeals against the notice of assessment for tax on repatriated income for the years of 2012 to 2013 ($11.6 million), the TRA was allowed to file a preliminary objection. In Q1 2024, the parties filed their written submissions. In Q1 2025, TRAB heard the appeals and the parties are now awaiting TRAB’s decision. The TRAB hearing of the appeal against the notice of assessment for tax on repatriated income for the year of 2014 ($3.8 million) is scheduled for May 8, 2025. In Q4 2022, the TRA issued seven assessments for tax on repatriated income ($11.7 million) for the years of 2015 to 2021. The Company objected to the assessments on the grounds of the assessments lacking merit; additionally, the assessments for the years of 2015 and 2016 were time-barred. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q4 2023, the Company filed statements of appeal at the TRAB. In Q1 2024, the parties filed their respective final written submissions and are awaiting TRAB’s decision. 84 Orca Energy Group Inc. // Annual Report & Accounts 2024 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTINUED 21. Contingencies continued VAT On May 22, 2023, the TRAB pronounced its judgment on the VAT appeal for the years of 2015 and 2016 ($0.2 million) in favour of the Company. A written judgment is still pending. The TRA did not file a notice of intention to appeal at the TRAT by the statutory filing deadline. The Company continues to monitor actions taken by the TRA. In Q4 2022, the TRA issued an assessment for VAT ($0.1 million) for the years of 2019 and 2020. The Company objected to the assessment on the grounds that the TRA incorrectly disallowed input VAT on certain services. In Q1 2023, the Company received TRA’s proposals to settle the objections. In Q2 2023, the Company responded to the proposals. In Q3 2023, following TRA’s failure to issue a final determination on the objections within the statutory time limit, the Company filed notices of intention to appeal and in Q1 2024, the Company filed statements of appeal at the TRAB. In Q1 2024, the appeals came for a hearing at the TRAB. The parties filed their written submissions and are now awaiting TRAB’s decision. On November 29, 2024 the TRA issued assessments for VAT ($14.9 million) for the years of 2019 to 2023. The Company objected to the assessments on the ground that the TRA incorrectly imposed VAT on a contractual adjustment made to the TPDC’s Profit Gas share and to the regulatory levy charged to customers. The Company is awaiting TRA’s determination of the objections. Management, with advice from its legal counsel, has reviewed the Company’s position on the objections and appeals related to the disputed amounts and has concluded that no further provision is required. However, if the TRA assesses the Company’s tax returns for open taxation years on a similar basis, the Company may be required to make future deposits to object such assessments. The process of appealing assessments issued by the TRA starts by initially filing an appeal with the TRA. If this is not successful, claims can be taken to higher authorities starting with the TRAB, followed by an appeal to the TRAT and finally to the CAT. Below is a summary of the status of the various assessments: (4) (a) 2008 ($0.6 million): The Company objected to the TRA assessment that did not recognize a tax loss carried forward and is awaiting a response; (b) 2009 ($0.8 million): The Company objected to an amended assessment from the TRA for being time-barred and arbitrary and is awaiting a TRA response; (c) 2010 ($2.3 million): The TRAT ruled in favour of the TRA; CAT hearing took place on February 25, 2025 and was adjourned for a later date. The Company had already made provision in the accounts for the amount in dispute; (d) 2011 ($1.6 million): The Company is awaiting a CAT hearing date following the TRAT ruling in favour of the TRA; (e) 2012 ($10.2 million): The Company appealed to the TRAB objecting to the TRA assessment with respect to understated revenue and deductibility of capital expenditures and expenses. Hearing is ongoing; (f) 2013 ($2.0 million): The Company appealed to the TRAB objecting to the TRA assessment as being time-barred and without merit. Hearing is ongoing; (g) 2014 ($5.5 million): The Company appealed to the TRAB objecting to the TRA assessment on the ground that the TRA assessment incorrectly disallowed certain expenses and applied erroneous foreign exchange rates. Hearing is scheduled for May 8, 2025; (h) 2015-16 ($9.0 million): The Company appealed to the TRAB as to TRA’s assessments on the ground that the TRA assessments failed to recognize provisional tax payments, incorrectly disallowed capital expenditures and certain expenses and applied erroneous foreign exchange rates; (i) 2017 ($7.4 million): The TRA issued an assessment for corporation tax which questioned the Company’s methodology of grossing up already paid corporation tax ($6.5 million) and raised the issue of imposing interest on deemed delayed payment ($0.1 million). The Company filed an objection and is awaiting the TRA’s response; (j) 2018 ($0.02 million): The Company appealed to the TRAB objecting to the TRA’s assessment on the grounds that the TRA incorrectly disallowed certain expenses and applied erroneous foreign exchange rates. The Company is awaiting TRAB’s judgment; (k) 2018-20 ($0.6 million): The Company appealed to the TRAB objecting to the TRA assessment on the ground that the TRA incorrectly disallowed certain expenses and failed to recognise payments already made. The Company is awaiting TRAB’s judgment; (5) (a) 2012 ($3.3 million): The Company objected to the TRA assessment as being without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; (b) 2013 ($8.3 million): The Company objected to the TRA assessment as being time-barred and without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; (c) 2014 ($3.8 million): The Company objected to the TRA assessment as being without merit and, following expiry of the statutory deadline for the TRA to respond, filed an appeal at the TRAB and is awaiting TRAB’s decision; (f) 2015-21 ($11.7 million): The Company appealed to the TRAB objecting to the TRA assessments for the year of income of 2015 ($1.9 million), 2016 ($1.9 million), 2017 ($1.6 million), 2018 ($1.1 million), 2019 ($1.6 million), 2020 ($1.1 million) and 2021 ($1.4 million) for being without merit and is awaiting TRAB’s judgment; (6) (a) 2012-16 ($0.2 million): The TRAB ruled in favour of the Company, parties are awaiting the written judgment. The TRA has not appealed the decision to the TRAT; (b) 2017-18 ($1.4 million): The Company filed an objection to a TRA assessment and is awaiting a response. The Company objected to incorrect imposition of interest on VAT decreasing adjustments in respect of delayed TANESCO payment ($1.2 million) and disallowing input VAT claimed in certain services ($0.1 million); (c) 2019-20 ($0.1 million): The Company appealed to the TRAB objecting to a TRA assessment on the grounds of incorrectly disallowing input VAT claimed and is awaiting TRAB’s judgment; (d) 2019-23 ($14.9 million): The Company has filed an objection to the TRA assessments and is awaiting a response. The Company objected to the imposition of VAT on a component of the profit sharing mechanism with TPDC and under the PSA and on the EWURA levy included in invoices to certain customers. In 2016, the TRA introduced significant changes in relation to the income tax treatment of the extractive sector with separate new chapters in Part V of the Income Tax Act 2004 (“ITA, 2004”) for mining and for petroleum to be effective commencing in 2018. Further changes were subsequently made by the Written Laws (Miscellaneous Amendments) Act, 2017 (“WLMAA, 2017”) and in particular section 36(a)(ii) of the WLMAA, 2017. The WLMAA, 2017 amended sections 65M and 65N of the ITA, 2004 to exclude cost oil/cost gas from inclusion in both income and expenditure. The Company continues to review the tax effects of the changes as there are a number of uncertainties and ambiguities as to the interpretation and application of certain provisions of the WLMAA, 2017. In the absence of guidance on these matters, the Company has used what it believes are reasonable interpretations and assumptions in applying the WLMAA, 2017 for purposes of determining its tax liabilities and the results of operations, which may change as it receives additional clarification and implementation guidance. The Company does not expect a significant impact from the changes as it is able to recover taxes payable from the TPDC Profit Gas revenue entitlement under the terms of the PSA. As at December 31, 2024, a total of $5.1m (2023: $5.1m) has been provided against the tax disputes and is included in the tax payable balance within current liabilities. 85 Orca Energy Group Inc. // Annual Report & Accounts 2024 22. Directors and Officers Emoluments Stock based compensation $’000 Year Base Bonus expense Total Directors 2024 500 – – 500 Directors 2023 500 – – 500 Officers 2024 1,525 615 - 2,140 Officers 2023 1,532 468 - 2,000 The table above provides information on compensation relating to the Company’s officers and directors. Four officers (year ended December 31, 2023: four) and three non-executive directors (year ended December 31, 2023: three) comprised the key management personnel during the year ended December 31, 2024. 23. Change in Non-Cash Operating Working Capital As at December 31 $’000 2024 2023 (Increase) / decrease in trade and other receivables (12,767) 945 Decrease / (increase) in prepayments 51 (86) Increase / (decrease) in trade and other payables 21,274 (4,144) Decrease in APT (15,983) (13,147) Increase / (decrease) in tax payable 4,672 (755) Decrease in long-term receivable – 2,205 (2,753) (14,982) 86 Orca Energy Group Inc. // Annual Report & Accounts 2024 24. Non-Controlling Interest The Company sold 7.933% (7,933 Class A common shares) of PAEM to a wholly owned subsidiary of Swala Oil & Gas (Tanzania) plc (“Swala TZ”), Swala (PAEM) Limited’s (“Swala UK”) in 2018 for $15.4 million cash and $4.0 million of Swala TZ’s Preference Shares pursuant to a share purchase agreement. The Preference Shares entitled the Company to a 10% per annum distribution payable 15 days after each quarter end commencing from the closing date, January 16, 2018. Payment of the quarterly distributions was at the discretion of Swala TZ based on funds available, however, the liability accrued if any amount was unpaid when due. For any distributable amount remaining unpaid at December 31, 2021, the Company may demand settlement and Swala TZ was obligated to comply by transferring and returning the Class A common shares of PAEM sold to Swala TZ. The aggregate value of these shares will equal the amount of the outstanding distributions. On April 3, 2023, Swala TZ announced that its creditors resolved that Swala TZ be placed into liquidation at a creditors’ meeting held on March 31, 2023. On March 31, 2023, Apex Corporate Trustees (UK) Limited appointed representatives of Grant Thornton UK LLP as administrators of Swala UK. On July 21, 2023, the Company repurchased the 7.933% shares in PAEM held by Swala UK for $7.5 million and the non-controlling interest was therefore eliminated in 2023. 25. Subsequent Events On February 14, 2025 the Company declared a dividend of CDN$0.10 per share on each of its Class A Shares and Class B Shares for a total of $1.4 million to holders of record as of March 31, 2025 to be paid on April 14, 2025. In February 2025, the Company received a judgment (the "Judgment") from the Tanzanian High Court (Commercial Division) (the "Court") for a claim brought by a contractor against PAET. The claim was brought by the contractor for losses arising from PAET's termination of a contract relating to the Company's 3D seismic acquisition program. The contract was signed in 2022 and works were due to be completed by the end of 2022. However, work only commenced in 2023 and was never completed. Pursuant to the Judgment, the Court ordered specific and general damages in the aggregate of $23.1 million, plus legal costs and interest at a rate of 7% per annum be paid by PAET to the contractor. PAET was required to post security for the full amount of the judgment until the appeal is resolved. The Company has recognised the resulting liability in 2024 based on the judgement applied. The Company has initiated the appeal process, and if successful in that process, a reversal would be recognized in earnings at that time. Subsequent to December 31, 2024, the Company fully prepaid the $60 million Loan made by the IFC to PAET, pursuant to the Loan Agreement. To effect the prepayment, the Company paid to the IFC $30.6 million, representing the aggregate outstanding principal of the Loan together with all accrued interest thereon and all other amounts owing in connection with the Loan as of February 21, 2025. The annual variable participating interest granted by PAET to the IFC under the terms of the Loan Agreement remains outstanding. On April 15, 2025 PAET signed a settlement agreement with TPDC and TANESCO (“Settlement Agreement”), for TANESCO to pay PAET and TPDC $52.0 million for unpaid amounts owing by TANESCO for deliveries of natural gas from the Songo Songo gas field. The parties acknowledged in the Settlement Agreement that these unpaid amounts totalled $104.2 million as of January 9, 2025, comprised of $33.7 million of the principal amount owing and approximately $70.5 million of default interest. The Settlement Agreement requires TANESCO to pay the Tanzanian Shilling equivalent of $52.0 million, comprised of the $33.7 million principal amount and $18.3 million representing a portion of the default interest owed by TANESCO. It was agreed that the balance of the default interest owing by TANESCO would be waived if TANESCO pays the settlement amount when required and in full. TANESCO must pay the settlement amount to PAET in weekly instalments commencing in April 2025 and ending in October 2025. Payments on account of the settlement amount will be allocated between PAET and TPDC in accordance with the PSA. Pursuant to the PSA, and assuming payment in full of the settlement amount, the Company expects to retain approximately $29.4 million of the settlement amount with TPDC retaining the balance. If TANESCO breaches its payment obligations under the Settlement Agreement, the Settlement Agreement terminates and PAET and TPDC will be entitled to enforce their rights to receive payment of the net amount of the TANESCO arrears owing plus default interest. Notwithstanding the signing of this Settlement Agreement, there will be no change in Company’s recognition of receivables or loss allowances, or unrecognised amounts not meeting revenue recognition criteria until such time that PAET receives a significant proportion of the payments due under the Settlement Agreement. 87 Orca Energy Group Inc. // Annual Report & Accounts 2024 CORPORATE INFORMATION Board of Directors Jay Lyons Executive Director and Chief Executive Officer Vancouver, Canada Lisa Mitchell Executive Director and Chief Financial Officer London, UK David W. Ross Chairman and Non-Executive Director Calgary, Canada Dr Frannie Léautier Non-Executive Director Washington DC, United States Linda Beal Non-Executive Director London, UK Advisor to the Board and PAET Lloyd Herrick Director, PAET Calgary, Canada Officers Jay Lyons Chief Executive Officer Vancouver, Canada Lisa Mitchell Chief Financial Officer London, UK Andrew Hanna Managing Director, PAET Surrey, UK Operating Office PanAfrican Energy Tanzania Limited Oyster Plaza Building, 5th Floor, Haile Selassie Road P.O. Box 80139, Dar es Salaam, Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 Registered Office Orca Energy Group Inc. Vistra Corporate Service Centre Wickhams Cay II, Road Town Tortola British Virgin Islands, VG110 Investor Relations Jay Lyons Chief Executive Officer ir@orcaenergygroup.com Lisa Mitchell Chief Financial Officer ir@orcaenergygroup.com International Subsidiaries PanAfrican Energy Tanzania Limited Oyster Plaza Building, 5th Floor, Haile Selassie Road P.O. Box 80139, Dar es Salaam, Tanzania Tel: + 255 22 2138737 Fax: + 255 22 2138938 PAE PanAfrican Energy Corporation 3rd Floor, Rogers House, 5 President John Kennedy Street Port Louis, Mauritius Tel: + 230 207 8888 Fax: + 230 207 8833 Engineering Consultants McDaniel & Associates Consultants Ltd. Calgary, Canada Auditors KPMG LLP Calgary, Canada Website orcaenergygroup.com Lawyers Burnet, Duckworth & Palmer LLP Calgary, Canada Transfer Agent TSX Trust Company Calgary, Canada 88 Orca Energy Group Inc. // Annual Report & Accounts 2024 85 Orca Energy Group Inc. Wickhams Cay II Road Town Tortola British Virgin Islands, VG110 www.orcaenergygroup.com 89

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