[PART I—FINANCIAL INFORMATION](index=3&type=section&id=PART%20I%E2%80%94FINANCIAL%20INFORMATION) This section presents the Trust's unaudited financial statements, management's discussion and analysis, market risk disclosures, and internal controls [Item 1. Financial Statements](index=3&type=section&id=Item%201.%20Financial%20Statements) This section presents the unaudited financial statements of BP Prudhoe Bay Royalty Trust, prepared on a modified cash basis, including the Statement of Assets, Liabilities and Trust Corpus, Statements of Cash Earnings and Distributions, and Statements of Changes in Trust Corpus, along with explanatory notes detailing the Trust's formation, termination, liquidity, accounting basis, royalty interest, income taxes, Alaska oil and gas production tax, and subsequent events [Statement of Assets, Liabilities and Trust Corpus](index=3&type=section&id=Statement%20of%20Assets%2C%20Liabilities%20and%20Trust%20Corpus) This statement details the Trust's financial position, including cash, total assets, accrued expenses, total liabilities, and trust corpus at specific dates Trust's Financial Position | Item | June 30, 2025 (in thousands) | December 31, 2024 (in thousands) | | :---------------------------------------------------------------- | :----------------------------- | :------------------------------- | | Cash and cash equivalents | $3,117 | $4,159 | | Total Assets | $3,117 | $4,159 | | Accrued expenses | $325 | $532 | | Total Liabilities | $325 | $532 | | Trust Corpus (21,400,000 units issued and outstanding) | $2,792 | $3,627 | | Total Liabilities and Trust Corpus | $3,117 | $4,159 | [Statements of Cash Earnings and Distributions](index=4&type=section&id=Statements%20of%20Cash%20Earnings%20and%20Distributions) This statement outlines the Trust's cash earnings and distributions over specified periods, including royalty revenues, interest income, and administrative expenses Cash Earnings and Distributions | Item | Three Months Ended June 30, 2025 (in thousands) | Three Months Ended June 30, 2024 (in thousands) | Six Months Ended June 30, 2025 (in thousands) | Six Months Ended June 30, 2024 (in thousands) | | :-------------------------- | :-------------------------------------------- | :-------------------------------------------- | :------------------------------------------ | :------------------------------------------ | | Royalty revenues | $— | $— | $— | $— | | Interest income | $36 | $62 | $78 | $129 | | Less: Trust administrative expenses | $(588) | $(556) | $(1,120) | $(894) | | Cash earnings (loss) | $(552) | $(494) | $(1,042) | $(765) | | Cash distributions | $— | $— | $— | $— | | Cash distributions per unit | $— | $— | $— | $— | | Units outstanding | 21,400,000 | 21,400,000 | 21,400,000 | 21,400,000 | [Statements of Changes in Trust Corpus](index=5&type=section&id=Statements%20of%20Changes%20in%20Trust%20Corpus) This statement tracks changes in the Trust Corpus, reflecting the impact of cash earnings, accrued expenses, and distributions over time Changes in Trust Corpus | Item | Three Months Ended June 30, 2025 (in thousands) | Three Months Ended June 30, 2024 (in thousands) | Six Months Ended June 30, 2025 (in thousands) | Six Months Ended June 30, 2024 (in thousands) | | :-------------------------- | :-------------------------------------------- | :-------------------------------------------- | :------------------------------------------ | :------------------------------------------ | | Trust Corpus at beginning of period | $3,081 | $4,475 | $3,627 | $4,964 | | Cash earnings (loss) | $(552) | $(494) | $(1,042) | $(765) | | Decrease in accrued expenses | $263 | $221 | $207 | $3 | | Cash distributions | $— | $— | $— | $— | | Trust Corpus at end of period | $2,792 | $4,202 | $2,792 | $4,202 | [(1) Formation of the Trust, Organization and Termination](index=6&type=section&id=%281%29%20Formation%20of%20the%20Trust%2C%20Organization%20and%20Termination) This section details the Trust's establishment, its purpose of owning an overriding royalty interest, and the conditions leading to its termination - The Trust was formed on February 28, 1989, to own and administer an overriding royalty interest (Royalty Interest) of **16.4246%** on the lesser of **90,000 barrels** or the average actual daily net production from HNS's working interests in the Prudhoe Bay field[17](index=17&type=chunk)[18](index=18&type=chunk) - The Trust terminated at **11:59 PM on December 31, 2024**, due to net revenues being less than **$1,000,000** for two successive years (2023 and 2024)[23](index=23&type=chunk)[24](index=24&type=chunk) [(2) Liquidity](index=6&type=section&id=%282%29%20Liquidity) This section discusses the Trust's cash reserve management, its purpose for covering expenses, and the reevaluation of its target level during wind-down - A cash reserve was established in July 1999 for liquidity, and HNS indemnified the Trust for **$537,835** in unpaid expenses in December 2020[25](index=25&type=chunk)[27](index=27&type=chunk) - The Trustee increased the cash reserve to approximately **$6,000,000** in 2021 to cover administrative and termination expenses, with the target level under reevaluation during wind-down[28](index=28&type=chunk)[69](index=69&type=chunk)[71](index=71&type=chunk) - The current cash reserve is deemed sufficient to cover Trust fees and expenses for the next **12 months**[30](index=30&type=chunk) [(3) Basis of Accounting](index=7&type=section&id=%283%29%20Basis%20of%20Accounting) This section explains that the financial statements are prepared on a modified cash basis, recording revenues when received and expenses on an accrual basis - Financial statements are prepared on a **modified cash basis**, considered most meaningful for quarterly distributions to Unit holders[33](index=33&type=chunk) - Revenues are recorded when received, distributions when paid, and Trust expenses are recorded on an **accrual basis**[37](index=37&type=chunk) [(4) Royalty Interest](index=8&type=section&id=%284%29%20Royalty%20Interest) This section outlines the initial carrying value of the Royalty Interest and its subsequent reduction to zero due to amortization and impairment - The Royalty Interest had an initial carrying value of **$535,000,000** in February 1989, reduced to **zero** by December 31, 2010, due to amortization and impairment[38](index=38&type=chunk) [(5) Income Taxes](index=8&type=section&id=%285%29%20Income%20Taxes) This section clarifies the Trust's federal tax filing as a grantor trust, where Unit holders are treated as owners of Trust income and corpus - The Trust files its federal tax return as a **grantor trust**, treating Unit holders as owners of Trust income and corpus for tax purposes[39](index=39&type=chunk) [(6) Alaska Oil and Gas Production Tax](index=8&type=section&id=%286%29%20Alaska%20Oil%20and%20Gas%20Production%20Tax) This section details the 2013 amendments to Alaska's oil and gas production tax statutes, including the increased base rate and per-barrel tax credits - Alaska's oil and gas production tax statutes were amended in 2013, increasing the base rate to **35%** and adding a stair-step per-barrel tax credit, effective January 1, 2014[41](index=41&type=chunk) - The 2014 Letter Agreement specifies the calculation of Production Taxes for the Trust's Royalty Production, including stair-step per-barrel tax credits and minimum tax limitations[42](index=42&type=chunk)[43](index=43&type=chunk) [(7) Subsequent Events](index=9&type=section&id=%287%29%20Subsequent%20Events) This section reports on recent events including the absence of royalty payments, the delisting of Units, and the ongoing sale process for Trust assets - No royalty payment was received in July 2025 for the quarter ended June 30, 2025[45](index=45&type=chunk) - The Units were delisted from the NYSE effective **June 30, 2025**, due to failing the **$1.00** average closing price requirement, and began trading on the OTC Pink market on **July 1, 2025**[46](index=46&type=chunk)[47](index=47&type=chunk) - Following termination, HNS declined its option to purchase Trust assets, initiating a sale process with bids due in July and August 2025, currently under review[48](index=48&type=chunk)[54](index=54&type=chunk)[55](index=55&type=chunk) [Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations](index=10&type=section&id=Item%202.%20Trustee%27s%20Discussion%20and%20Analysis%20of%20Financial%20Condition%20and%20Results%20of%20Operations) This section provides an overview of the Trust's financial condition and operational results, detailing its termination, the ongoing asset sale process, recent developments, forward-looking statements, liquidity management, and a comparative analysis of its financial performance for the three and six months ended June 30, 2025, versus 2024 - Crude oil prices significantly affect the Trust's revenues, influenced by global supply/demand, market conditions, and geopolitical events[74](index=74&type=chunk) - The Per Barrel Royalty is calculated as WTI Price less Adjusted Chargeable Costs and Production Taxes; HNS's net production has been below **90,000 barrels per day** since 2020 and is expected to remain so[76](index=76&type=chunk)[77](index=77&type=chunk) - WTI crude oil spot prices were, on average, below the 'break-even' level for both the first and second quarters of 2025, preventing the Trust from receiving a Per Barrel Royalty[79](index=79&type=chunk)[80](index=80&type=chunk) - An overpayment of **$13,279** from the fourth quarter of 2022 remains outstanding and will be deducted from any future distributions[83](index=83&type=chunk) Per Barrel Royalty Calculation Factors (Quarter Average) | Royalty Payment in Month | Quarter Ended | Average WTI Price | Chargeable Costs | Cost Adjustment Factor | Adjusted Chargeable Costs | Average Production Taxes | Average Per Barrel Royalty | Average Net Production (mb/d) | | :----------------------- | :------------ | :---------------- | :--------------- | :--------------------- | :------------------------ | :----------------------- | :------------------------- | :---------------------------- | | April 2025 | 03/31/25 | $71.50 | $40.25 | 2.4569 | $98.89 | $2.46 | $(29.85) | 65.6 | | Jan. 2025 | 12/31/24 | $70.32 | $37.50 | 2.4293 | $91.10 | $2.42 | $(23.19) | 64.6 | | April 2024 | 03/31/24 | $77.01 | $37.50 | 2.3895 | $89.61 | $2.69 | $(15.28) | 66.8 | | Jan. 2024 | 12/31/23 | $78.47 | $34.75 | 2.3643 | $82.16 | $2.75 | $(6.44) | 67.9 | [Introduction](index=10&type=section&id=Introduction) This section introduces the Trust's termination due to insufficient net revenues and the subsequent initiation of an asset sale process after HNS declined its purchase option - The Trust terminated on **December 31, 2024**, as net revenues from the Royalty Interest were less than **$1.0 million** for two successive years (2023 and 2024)[52](index=52&type=chunk) - HNS declined its option to purchase Trust assets on **June 2, 2025**, leading the Trustee to initiate a sale process for the assets, with bids currently under review[54](index=54&type=chunk)[55](index=55&type=chunk) [Recent Developments](index=11&type=section&id=Recent%20Developments) This section highlights the impact of low WTI prices on royalty calculations and the payment of accrued administrative expenses from the cash reserve - The average WTI price for the quarter ended June 30, 2025, was below the 'break-even' price, resulting in a negative Per Barrel Royalty calculation, though payments cannot be less than zero[57](index=57&type=chunk)[59](index=59&type=chunk) - Accrued expenses totaling **$588,418** through June 30, 2025, were paid from the cash reserve[58](index=58&type=chunk) [Forward-Looking Statements](index=11&type=section&id=Forward-Looking%20Statements) This section cautions that forward-looking statements are subject to various risks, including fluctuations in oil prices, production levels, and the outcome of the Trust's winding up - Forward-looking statements are subject to risks including future changes in oil prices, production levels, production charges, Trust expenses, cash reserve levels, and the timing/outcome of the Trust's winding up and asset sale[60](index=60&type=chunk) [Liquidity and Capital Resources](index=12&type=section&id=Liquidity%20and%20Capital%20Resources) This section describes the Trust's limited capital resources, its cash reserve for expenses, and the ongoing reevaluation of the reserve target during wind-down - The Trust is a passive entity with no capital resources other than royalty revenues, though the Trustee can borrow, establish reserves, or dispose of property under limited circumstances[65](index=65&type=chunk) - The cash reserve, increased to **$6.0 million** in 2021, is intended to cover administrative and termination expenses, with its target level being reevaluated during the Trust's wind-down[69](index=69&type=chunk)[70](index=70&type=chunk)[71](index=71&type=chunk) [Results of Operations](index=13&type=section&id=Results%20of%20Operations) This section analyzes the Trust's operational performance, comparing financial results and key royalty calculation factors for the three and six months ended June 30, 2025, against the prior year [Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2024](index=14&type=section&id=Three%20Months%20Ended%20June%2030%2C%202025%20Compared%20to%20Three%20Months%20Ended%20June%2030%2C%202024) This section compares the Trust's financial performance and key royalty calculation factors for the three months ended June 30, 2025, against the same period in 2024 Changes in Royalty Calculation Factors (Q1 2025 vs Q1 2024) | Item | Three Months Ended 3/31/2025 | Amount (Increase/Decrease) | Percent (Increase/Decrease) | Three Months Ended 3/31/2024 | | :-------------------------- | :--------------------------- | :------------------------- | :-------------------------- | :--------------------------- | | Average WTI Price | $71.50 | $(5.51) | (7.2)% | $77.01 | | Adjusted Chargeable Costs | $98.89 | $9.28 | 10.4% | $89.61 | | Average Production Taxes | $2.46 | $(0.23) | (8.6)% | $2.69 | | Average Per Barrel Royalty (paid) | $(29.85) | $(14.57) | (95.4)% | $(15.28) | | Average net production (mb/d) | 65.6 | (1.2) | (1.8)% | 66.8 | - The Average Per Barrel Royalty remained negative and decreased by **$14.57**, primarily due to a **7.2%** decrease in Average WTI Price and a **10.4%** increase in Adjusted Chargeable Costs[87](index=87&type=chunk) Changes in Trust's Revenues and Expenses (Q2 2025 vs Q2 2024) | Item | Three Months Ended 6/30/2025 (in thousands) | Amount (Increase/Decrease) | Percent (Increase/Decrease) | Three Months Ended 6/30/2024 (in thousands) | | :---------------------- | :---------------------------------------- | :------------------------- | :-------------------------- | :---------------------------------------- | | Royalty revenues | $— | $— | — | $— | | Cash earnings (loss) | $(552) | $(58) | (11.7)% | $(494) | | Cash distributions | $— | $— | — | $— | | Administrative expenses | $588 | $32 | 5.8% | $556 | - Cash losses increased by **11.7%** due to Administrative Expenses being paid solely from the cash reserve, which itself increased by **5.8%** due to higher service provider fees[89](index=89&type=chunk) [Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024](index=15&type=section&id=Six%20Months%20Ended%20June%2030%2C%202025%20Compared%20to%20Six%20Months%20Ended%20June%2030%2C%202024) This section compares the Trust's financial performance and key royalty calculation factors for the six months ended June 30, 2025, against the same period in 2024 Changes in Royalty Calculation Factors (H1 2025 vs H1 2024) | Item | Six Months Ended 3/31/2025 | Amount (Increase/Decrease) | Percent (Increase/Decrease) | Six Months Ended 3/31/2024 | | :-------------------------- | :------------------------- | :------------------------- | :-------------------------- | :------------------------- | | Average WTI Price | $70.90 | $(6.85) | (8.8)% | $77.75 | | Adjusted Chargeable Costs | $94.95 | $9.11 | 10.6% | $85.84 | | Average Production Taxes | $2.44 | $(0.28) | (10.3)% | $2.72 | | Average Per Barrel Royalty (paid) | $(26.49) | $(15.68) | (145.1)% | $(10.81) | | Average net production (mb/d) | 65.1 | (2.3) | (3.4)% | 67.4 | - The Average Per Barrel Royalty remained negative and decreased by **$15.68**, primarily due to an **8.8%** decrease in Average WTI Price and a **10.6%** increase in Adjusted Chargeable Costs[91](index=91&type=chunk) Changes in Trust's Revenues and Expenses (H1 2025 vs H1 2024) | Item | Six Months Ended 6/30/2025 (in thousands) | Amount (Increase/Decrease) | Percent (Increase/Decrease) | Six Months Ended 6/30/2024 (in thousands) | | :---------------------- | :-------------------------------------- | :------------------------- | :-------------------------- | :-------------------------------------- | | Royalty revenues | $— | $— | — | $— | | Cash earnings (loss) | $(1,042) | $277 | 36.2% | $(765) | | Cash distributions | $— | $— | — | $— | | Administrative expenses | $1,120 | $226 | 25.3% | $894 | - Cash losses increased by **36.2%** due to Administrative Expenses being paid solely from the cash reserve, with Administrative Expenses increasing by **25.3%** due to higher service provider fees[93](index=93&type=chunk) [Item 3. Quantitative and Qualitative Disclosures About Market Risk](index=16&type=section&id=Item%203.%20Quantitative%20and%20Qualitative%20Disclosures%20About%20Market%20Risk) The Trust, as a passive entity with limited investment options, faces no material interest rate risk, foreign currency risk, or exposure to derivative financial instruments - The Trust is a passive entity with no material interest rate risk due to the short-term nature and limitations on its investments[94](index=94&type=chunk) - The Trust does not engage in foreign currency transactions or invest in derivative financial instruments, thus avoiding related market risks[94](index=94&type=chunk) [Item 4. Controls and Procedures](index=16&type=section&id=Item%204.%20Controls%20and%20Procedures) This section details the Trustee's evaluation of the Trust's internal control over financial reporting, concluding its effectiveness as of June 30, 2025, and reporting no material changes during the last fiscal quarter [Evaluation of Disclosure Controls and Procedures](index=16&type=section&id=Evaluation%20of%20Disclosure%20Controls%20and%20Procedures) This section confirms the Trustee's responsibility for internal control over financial reporting and its conclusion that controls were effective as of June 30, 2025 - The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting[95](index=95&type=chunk) - Based on an evaluation using COSO criteria, the Trust's internal control over financial reporting was effective as of **June 30, 2025**[97](index=97&type=chunk) [Changes in Internal Control Over Financial Reporting](index=17&type=section&id=Changes%20in%20Internal%20Control%20Over%20Financial%20Reporting) This section reports that no material changes occurred in the Trust's internal control over financial reporting during the last fiscal quarter - There have been no material changes in the Trust's internal control over financial reporting during the last fiscal quarter[98](index=98&type=chunk) [PART II—OTHER INFORMATION](index=17&type=section&id=PART%20II%E2%80%94OTHER%20INFORMATION) This section covers various other information, including legal proceedings, risk factors, equity security sales, defaults, mine safety, and exhibits [Item 1. Legal Proceedings](index=17&type=section&id=Item%201.%20Legal%20Proceedings) The Trust reports no legal proceedings - None[100](index=100&type=chunk) [Item 1A. Risk Factors](index=17&type=section&id=Item%201A.%20Risk%20Factors) The Trust states there have been no material changes to the risk factors previously disclosed in its annual report on Form 10-K for the year ended December 31, 2024 - There have been no material changes from the risk factors disclosed in the Trust's annual report on Form 10-K for the year December 31, 2024[101](index=101&type=chunk) [Item 2. Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchases of Equity Securities](index=17&type=section&id=Item%202.%20Unregistered%20Sales%20of%20Equity%20Securities%2C%20Use%20of%20Proceeds%2C%20and%20Issuer%20Purchases%20of%20Equity%20Securities) The Trust reports no unregistered sales of equity securities, use of proceeds, or issuer purchases of equity securities - None[102](index=102&type=chunk) [Item 3. Defaults Upon Senior Securities](index=17&type=section&id=Item%203.%20Defaults%20Upon%20Senior%20Securities) The Trust reports no defaults upon senior securities - None[103](index=103&type=chunk) [Item 4. Mine Safety Disclosures](index=17&type=section&id=Item%204.%20Mine%20Safety%20Disclosures) This item is not applicable to the Trust - Not applicable[104](index=104&type=chunk) [Item 5. Other Information](index=17&type=section&id=Item%205.%20Other%20Information) The Trust reports no other information - None[105](index=105&type=chunk) [Item 6. Exhibits](index=17&type=section&id=Item%206.%20Exhibits) This section lists the exhibits filed with the report, including certifications and an explanatory note regarding the Interactive Data File - Exhibits include Rule 13a-14(a) Certification and Section 1350 Certification[107](index=107&type=chunk) - An Interactive Data File is not submitted because the Trust does not prepare financial statements in accordance with GAAP[107](index=107&type=chunk)

Financial Data and Key Metrics Changes - Beach Energy reported a total production increase of 9% to 19.7 million barrels of oil equivalent, with sales volumes rising 16% to 24.7 million barrels of oil equivalent [18][19] - Sales revenue increased by 13% to AUD 2 billion, driven by higher production and five Waitzier LNG swap cargoes, while underlying EBITDA rose 20% year on year to AUD 1.1 billion [19][30] - Underlying NPAT increased by 32% to AUD 451 million, with a significant improvement in underlying EBITDA margin by 300 basis points to 57% [19][31] - The company declared a record final dividend of AUD 0.06 per share, bringing the total full-year dividend to AUD 0.09 per share, representing a 31% payout ratio [19][20] Business Line Data and Key Metrics Changes - The Otway Basin saw a 64% increase in production to 6.8 million barrels of oil equivalent, while the Bass Basin experienced a 91% increase in production to 1.4 million barrels [18] - The Cooper Basin faced challenges due to severe flooding, impacting production but overall performance in other areas compensated for this [18][19] Market Data and Key Metrics Changes - Beach Energy's operated assets and non-operated interests now supply 19% of the entire East Coast domestic gas market, positioning the company as a significant supplier [4][6] - The East Coast gas production increased by 23% in FY 2025, with Beach supplying 90% of the East Coast gas demand [13][19] Company Strategy and Development Direction - The company aims to become Australia's leading domestic energy company, focusing on core East Coast and West Coast hubs while maintaining a strong balance sheet for growth opportunities [6][20] - Beach Energy has implemented a disciplined gas marketing strategy, rebalancing its customer portfolio and retaining approximately 30% of its East Coast gas supply for the spot market [16][19] Management's Comments on Operating Environment and Future Outlook - Management highlighted the declining gas supply available to the domestic market, with firm long-term gas demand, leading to widening structural supply deficits [12] - The company is optimistic about its growth potential, with plans for further exploration and development activities in FY 2026 [21][40] Other Important Information - Beach Energy achieved its best safety performance in 14 years, with no significant hydrocarbon spills and a focus on improving safety culture [25][27] - The completion of the Moomba CCS project is a significant milestone in the company's emissions reduction pathway, abating over 1 million tonnes of CO2 [28] Q&A Session Summary Question: Can you talk us through the dividend and concerns about M&A or net debt rising? - Management explained the decision to set the dividend payout slightly below the targeted range to ensure financial flexibility for potential growth opportunities [49][50] Question: Is there further cost reduction potential in 2026 and 2027? - Management confirmed ongoing efforts to reduce costs, particularly in the Cooper Basin, and expressed confidence in achieving the $11 per barrel target [52][54] Question: Can you provide details on the $11 per BOE cost target? - Management clarified that the target remains at $11 per barrel, set to outperform peers, with current operations achieving a unit operating cost of $10.68 [57][58] Question: What is the balance sheet capacity for growth? - Management indicated a willingness to stretch the balance sheet for value-accretive acquisitions while maintaining a target gearing level below 15% [59][60] Question: Can you outline the framework for assessing new growth opportunities? - Management reiterated a focus on domestic opportunities with a target return rate above 12%, emphasizing a cautious approach to acquisitions [69][72] Question: Are there any constraints in accessing larger domestic growth opportunities? - Management expressed confidence in finding a broader suite of opportunities, focusing on maximizing shareholder value and domestic supply [73][74] Question: Will there be any new acreage releases of interest? - Management mentioned ongoing interest in acreage releases in South Australia and Queensland, particularly in CSG [81] Question: What is the potential pricing delta upside from recontracting at the Cooper Basin? - Management indicated that recent recontracting would likely yield significant pricing improvements, with benefits expected to flow through in upcoming quarterly results [84]

Financial Data and Key Metrics Changes - Total production increased by 9% to 19.7 million barrels of oil equivalent, with sales volumes rising 16% to 24.7 million barrels of oil equivalent [15][16] - Sales revenue grew by 13% to $2 billion, driven by higher production and an increase in average realized gas price to $10.7 for domestic volumes [16][28] - Underlying EBITDA increased by 20% year on year to $1.1 billion, while underlying NPAT rose by 32% to $451 million [17][28] - The underlying EBITDA margin improved by 300 basis points to 57%, reflecting structural cost savings and improved commercial outcomes [17][28] - Pre-growth free cash flow increased fourfold to $657 million, with a payout ratio of 31% [17][18] Business Line Data and Key Metrics Changes - East Coast gas production increased by 23% in FY 2025, with Beach supplying 90% of the East Coast gas demand [11][12] - The Otway Basin saw a 64% increase in production to 6.8 million barrels of oil equivalent, while the Bass Basin experienced a 91% increase to 1.4 million barrels [15] - The Cooper Basin faced challenges due to severe flooding, impacting production [15][29] Market Data and Key Metrics Changes - Beach's operated assets and non-operated interests now supply 19% of the entire East Coast domestic gas market, positioning the company as a significant supplier [3][5] - The gas supply available to the domestic market is declining, while long-term gas demand remains firm, leading to widening structural supply deficits [10] Company Strategy and Development Direction - The company aims to become Australia's leading domestic energy company, focusing on core East Coast and West Coast hubs [5][18] - A disciplined gas marketing strategy has been implemented, allowing for a balanced approach between contracted volumes and spot market exposure [12][14] - The strategic pillars include high margins and sustainable growth, with a focus on operational efficiencies and accountability [7][8] Management's Comments on Operating Environment and Future Outlook - Management expressed confidence in the company's ability to deliver growth, emphasizing the importance of maintaining a strong balance sheet and operational effectiveness [18][41] - The company is actively pursuing opportunities for disciplined, value-accretive growth, particularly in the East and West Coast markets [18][66] - Management acknowledged the challenges faced in the Cooper Basin but remains optimistic about future production and operational improvements [29][35] Other Important Information - A non-cash impairment of $474 million was recorded for the Cooper Basin and Perth Basin carrying values, primarily due to lower near-term commodity price outlooks [28][29] - The Moomba CCS project was completed, contributing to the company's emissions reduction goals [24][25] Q&A Session Summary Question: Can you talk us through the dividend and concerns about potential lower dividends due to M&A or rising net debt? - Management explained that the decision to set the payout slightly below the targeted range was to ensure flexibility for future opportunities and maintain a strong balance sheet [45][46] Question: Is there further cost reduction potential in FY 2026 and 2027? - Management confirmed ongoing efforts to reduce costs, particularly in the Cooper Basin, and emphasized a focus on maintaining margins [48][49] Question: Can you provide details on the $11 per BOE cost target and its current status? - Management stated that the $11 target remains in place and is set to outperform peers, with operated assets achieving a unit operating cost of $10.68 [53][54] Question: What is the Board's confidence in the $06 per share final dividend despite Waitzier not being commissioned? - Management indicated that the Board's decision reflects confidence in the commissioning timeline for Waitzier and the company's overall performance [60][63] Question: Can you outline the framework for assessing new growth opportunities? - Management reiterated that the investment criteria include a hurdle rate of over 12% for gas projects and a focus on domestic opportunities [66][67] Question: Are there any new acreage releases of interest? - Management mentioned ongoing interest in acreage releases in South Australia and Queensland, particularly for CSG [77] Question: What is the potential pricing delta upside from the recontracting at the Cooper Basin? - Management indicated that recent recontracting has been at prevailing domestic gas prices, which are expected to positively impact future results [80]

Financial Performance - Sales revenue reached $20 billion, a 13% increase[25] - Underlying EBITDA was $1136 billion, up by 20%[25] - Pre-growth free cash flow increased by over 4 times to $657 million[25] - A record fully franked final dividend of 6 cents per share was declared, a 200% increase[25] Production and Reserves - FY25 production was 197 MMboe, a 9% increase[25] - 2P reserves decreased from 205 MMboe to 173 MMboe[26] - Beharra Springs Deep revision required a -107 MMboe adjustment to undeveloped 2P reserves[28] Operational Highlights - Supplied 19% of East Coast gas demand[21, 22] - $130 million in cost and capital reductions were delivered, with an 18% reduction in unit field operating costs and a 20% reduction in sustaining capital expenditure[21] - ~40 TJ/day of Cooper Basin JV gas volumes were re-contracted for FY26[21, 24] - $352 million revenue was generated from five LNG cargoes[21, 78] FY26 Outlook - Production guidance is set at 197 – 220 MMboe[60] - Capital expenditure is projected to be $675 – 775 million[60]

Financial Performance - Cash earnings for the three months ended March 31, 2025, were a loss of $490,000 compared to a loss of $271,000 for the same period in 2024, indicating a worsening of 80.8%[12] - The Trust's administrative expenses increased to $532,000 in the first quarter of 2025 from $338,000 in the same quarter of 2024, marking a rise of 57.5%[12] - There were no royalty revenues distributed in either the first quarter of 2025 or the first quarter of 2024, resulting in a cash loss of $490, an increase of 80.8% from the previous year[83] - The average Per Barrel Royalty for the fourth quarter of 2024 was negative $23.19, primarily due to increased Adjusted Chargeable Costs and decreased Average WTI Price[80] Asset and Liability Changes - As of March 31, 2025, total assets decreased to $3,669,000 from $4,159,000 as of December 31, 2024, representing a decline of approximately 11.8%[10] - The Trust corpus at the end of the period was $3,081,000, down from $4,475,000 at the end of the same period in 2024, reflecting a decrease of 31.1%[15] - The Trust's total liabilities increased to $588,000 as of March 31, 2025, compared to $532,000 as of December 31, 2024, an increase of 10.5%[10] Revenue and Royalty Issues - No royalty revenues were recorded for the quarters ended in 2023, 2024, and the first quarter of 2025, leading to a total of zero revenues for these periods[30] - The Trust did not receive any revenues attributable to any of the four quarters of 2023 and 2024, leading to its termination on December 31, 2024[48] - The Trust has not received any revenues from the Royalty Interest since the first quarter of 2021 until July 2021, when it received approximately $3.2 million[60] Termination and Future Outlook - The Trust's termination process commenced on December 31, 2024, due to the absence of revenues for two consecutive years[25] - The Trust's termination process will incur costs related to professional evaluations, legal fees, and other necessary expenses[63] - HNS's average net production of oil and condensate allocated to the Trust was less than 90,000 barrels per day from 2020 through the first quarter of 2025, and is expected to remain below this threshold in future years[69] Oil Price and Production Insights - For the quarter ended March 31, 2025, the average WTI price was $71.50, while average adjusted chargeable costs were $98.89, resulting in an average per barrel royalty of $(29.85)[52] - The average WTI crude oil spot price for the fourth quarter of 2024 was $70.32, a decrease of 10.4% compared to $78.47 in the fourth quarter of 2023[80] - The average net production from the 1989 Working Interest declined by 4.9% from 67.9 mb/d in the fourth quarter of 2023 to 64.6 mb/d in the fourth quarter of 2024[80] - The U.S. Energy Information Administration forecasts WTI prices to average $60.85 per barrel in Q2 2025 and $58.00 per barrel in Q3 2025[73] Cash Reserves and Distributions - The Trust has not made any cash distributions since the first quarter of 2023, maintaining a cash reserve to cover administrative expenses[12] - The Trust's cash reserve was evaluated to be approximately $6,000,000 in 2021, but has since been drawn down due to lack of revenue[29] - The Trust's cash reserve was increased to approximately $6.0 million to cover administrative expenses and potential termination costs[64] - The Trustee paid all accrued expenses of the Trust through March 31, 2025, totaling $531,612 from the cash reserve[51] Internal Controls and Risk Management - The Trust's internal control over financial reporting was deemed effective as of March 31, 2025, based on the COSO criteria[87] - The Trust has no foreign operations and holds no long-term debt instruments, minimizing exposure to interest rate and foreign currency risks[84] - The Trustee has the authority to borrow or establish a cash reserve under limited circumstances as per the Trust Agreement[57] Market Influences - The Trust's revenues and results of operations are significantly affected by fluctuations in oil prices, which are influenced by global supply and demand and geopolitical events[66]

Financial Performance - Royalty revenues for the year ended December 31, 2024, were $0, a significant decrease from $6,640,000 in 2023 and $82,283,000 in 2022, indicating a substantial drop in revenue generation [256]. - Cash earnings for 2024 resulted in a loss of $1,143,000, compared to cash earnings of $5,600,000 in 2023 and $80,888,000 in 2022, reflecting a negative trend in profitability [256]. - Cash distributions for 2024 were $0, down from $6,365,000 in 2023 and $80,823,000 in 2022, indicating a complete halt in distributions to unit holders [256]. - The Trust's future cash inflows for 2024 are projected to be $0, indicating a significant decline in expected revenue [296]. - The Trust's net increase (decrease) during the year for 2023 was $(56,751,000), indicating a challenging financial environment [296]. Asset and Reserve Changes - As of December 31, 2024, total assets of BP Prudhoe Bay Royalty Trust were $4,159,000, a decrease from $5,302,000 in 2023, representing a decline of approximately 21.5% [253]. - The trust corpus decreased to $3,627,000 at the end of 2024 from $4,964,000 in 2023, marking a decline of approximately 27% [258]. - As of December 31, 2024, the net proved reserves of oil and condensate attributable to the Trust are estimated to be 0 million barrels, down from 8.232 million barrels in 2022 [295]. - Proved developed reserves as of December 31, 2022, were 7.862 million barrels, with no proved developed reserves reported for 2023 and 2024 [298]. Revenue and Production Insights - The standardized measure of discounted future net cash flow relating to proved reserves for 2022 was $56,751,000, with future cash inflows of $61,169,000 and a 10% annual discount of $4,418,000 [296]. - The total production for the year ending December 31, 2022, was 4,169,000 barrels, contributing to the overall reserve estimates [298]. - The average net production of crude oil and condensate from proved reserves allocated to the Trust was less than 90,000 barrels per day during certain quarters [286]. - The negative revision in year-end 2023 reserves was due to a decrease in the WTI price from $93.67 per barrel in 2022 to $78.22 per barrel [300]. Operational and Administrative Aspects - Accrued expenses increased to $532,000 in 2024 from $338,000 in 2023, indicating rising operational costs [253]. - The Trust's administrative expenses for the fiscal year 2023 were $1,327,000, with the highest expense recorded in Q2 at $587,000 [290]. - The trust maintained effective internal control over financial reporting as of December 31, 2024, according to the independent auditor's opinion [244]. Trust Structure and Limitations - The trust's passive nature limits its ability to engage in borrowing transactions, with the trustee only able to borrow as necessary to pay liabilities [231]. - The trust's royalty interest is based on a per barrel royalty of 16.4246% on the lesser of 90,000 barrels or the average actual daily net production, which is subject to production risks [261]. Historical Context and Trends - The Trust did not receive any royalty payments for the four quarters of 2020 and the first quarter of 2021 due to lower oil prices and increased chargeable costs [269]. - The Trust's cash reserve was increased to approximately $6,000,000 in 2021 to ensure liquidity [271]. - In the first quarter of 2023, the Trust received a royalty payment of $6.640 million, which included an overpayment adjustment of $27,000 [286]. - The Trust's total cash earnings for the fiscal year 2023 were $6,363,000, with cash distributions amounting to $6,365,000 [290]. - Royalty revenues for the fiscal year 2022 totaled $82,282,000, with the highest quarterly revenue of $30,341,000 in Q3 [290]. - The average WTI price for 2022 was $93.67 per barrel, which contributed to a positive revision in reserves from 2021 to 2022 [300]. - The net changes in prices and production costs resulted in a decrease of $63,330,000 in 2023, reflecting the impact of lower oil prices [296].

Termination of BP Prudhoe Bay Royalty Trust - BP Prudhoe Bay Royalty Trust did not receive a royalty payment for the quarter ended December 31, 2024, and will not make a quarterly cash distribution to unitholders[5] - The Trust terminated at 11:59 PM on December 31, 2024, due to no revenue received for any of the four quarters of 2023 or 2024[5] - The Trust terminated as per the Trust Agreement when net revenues from the Royalty Interest were less than $1.0 million per year for two successive years[12] NYSE Delisting and Compliance Issues - The Trust received a delisting notice from NYSE as the average closing price of its units was less than $1.00 over 30 consecutive trading days[6] - The Trust must regain compliance with NYSE listing standards within six months by achieving a closing unit price of at least $1.00 and an average closing unit price of at least $1.00 over 30 trading days[7] - The Trust has no control over the trading price of its units and cannot take actions like a reverse split without unitholder approval[8] Potential Impact of Delisting - If delisted, the Trust's units may be transferred to the over-the-counter market, potentially affecting market price, trading volume, liquidity, and resale price[10]

Financial Performance - For the quarter ended September 30, 2024, the average WTI price was $75.20, while the average adjusted chargeable costs were $90.90, resulting in an average per barrel royalty of $(18.31)[24]. - The Trust did not receive any royalty payments for the entirety of 2023 and the first three quarters of 2024 due to declining WTI prices and increased chargeable costs[24]. - The average net production for the quarter was 59.6 mb/d, indicating ongoing production levels despite the financial challenges faced by the Trust[24]. - Trust royalty revenues for the third quarter of 2024 were zero, consistent with Q3 2023, due to non-payment of the Per Barrel Royalty[54]. - Royalty revenues for the nine months ended September 30, 2024, decreased to $0, a decline of $6,640 thousand or 100.0% compared to $6,640 thousand in the same period of 2023[59]. - Cash earnings (loss) for the same period were $(1,037) thousand, a decrease of $6,869 thousand or 117.8% from $5,832 thousand in the prior year[59]. - Cash distributions also fell to $0, down $6,365 thousand or 100.0% compared to $6,365 thousand in the previous year[59]. - Administrative expenses for Q3 2024 increased by 109.6% to $329, primarily due to timing of invoices and increased service provider fees[54]. - Administrative expenses increased to $1,223 thousand, reflecting a rise of $199 thousand or 19.4% from $1,024 thousand in the same period of 2023[59]. Trust Operations and Management - The Trust will terminate if net revenues from the Royalty Interest are less than $1.0 million per year for two consecutive years, with a potential termination date of December 31, 2024, if revenues do not exceed this threshold[24]. - The Trustee intends to keep the cash reserve program in place through the winding up of the Trust, with any excess cash reserved to be distributed to unit holders after covering administrative expenses[37]. - The Trustee has the authority to adjust the cash reserve based on the Trust's financial circumstances, which may include increasing or decreasing the reserve without prior notice to unit holders[31]. - The Trust Corpus decreased at the end of the nine months ended September 30, 2024, due to the payment of expenses from cash reserves, slightly offset by an increase in interest income[59]. - The Trust is at risk of delisting from the NYSE if it cannot meet the minimum price requirement of $1.00 per Unit over a consecutive 30 trading day period[68]. - If net revenues from the Royalty Interest do not exceed $1.0 million for the quarter ended December 31, 2024, the Trust will terminate on December 31, 2024[70]. - The termination and winding-up of the Trust may negatively affect Unit prices and increase price volatility[70]. Market Conditions and Risks - The Trust's revenues and operations are significantly affected by fluctuations in oil prices, which are influenced by global supply and demand, geopolitical events, and market conditions[38]. - Forward-looking statements regarding the Trust's performance are subject to various risks, including changes in oil prices and geopolitical developments, which could materially affect future results[25]. - The average WTI crude oil spot price for Q2 2024 was below the "break-even" level necessary for the Trust to receive a Per Barrel Royalty, fluctuating between a high of $86.91 and a low of $73.25[43]. - The average WTI crude oil spot price for Q3 2024 also remained below the "break-even" level, with a high of $83.88 and a low of $65.75[44]. - The U.S. Energy Information Administration forecasts WTI prices to average $71.97 per barrel in Q4 2024 and $73.67 per barrel in Q1 2025, but there is no assurance these prices will be achieved[45]. Production Trends - The average net production of oil and condensate allocated to the Trust from proved reserves was less than 90,000 barrels per day from 2019 through 2024, with expectations to remain below this threshold in future years due to declining production rates[41]. - The average net production from the 1989 Working Interest declined by 6.7% in Q2 2024 compared to Q2 2023, attributed to the declining production rate from the Prudhoe Bay field[52]. - The average net production for the nine-month period ending June 30, 2024, was 65.3 mb/d, a decrease of 5.1% compared to the same period in 2023[57]. Financial Reporting and Controls - The internal control over financial reporting was evaluated as effective as of September 30, 2024, based on COSO criteria[64]. - The average WTI Price for the second quarter of 2024 increased by 9.3% compared to Q2 2023, while Adjusted Chargeable Costs increased by 11.4%[52]. - The average Per Barrel Royalty paid in Q2 2024 was $(12.89), a decrease of $(2.70) or (26.5%) compared to Q2 2023[52].

Royalty Payments - BP Prudhoe Bay Royalty Trust did not receive a royalty payment for Q3 2024[2] - Consequently, there will be no quarterly cash distribution to unitholders for the quarter ended September 30, 2024[2]

Financial Performance - Cash earnings for the three months ended June 30, 2024, were reported at a loss of $494,000, compared to a loss of $445,000 for the same period in 2023[4] - Cash earnings for the six months ended June 30, 2024, reported a loss of $765, a decrease of 112.9% compared to a gain of $5,918 in the same period in 2023[51] - Royalty revenues for the six months ended June 30, 2024, were $0, a 100% decrease from $6,640 in the same period in 2023[51] - Cash distributions for the six months ended June 30, 2024, were $0, while cash distributions per unit for the six months ended June 30, 2023, were $0.2974[4] - The Trust's cash earnings and distributions for the interim periods are not necessarily indicative of the results expected for the full year[11] Assets and Liabilities - As of June 30, 2024, total assets amounted to $4,537,000, a decrease from $5,302,000 as of December 31, 2023, reflecting a decline of approximately 14.4%[3] - The Trust corpus decreased to $4,202,000 from $4,964,000 at the end of 2023, representing a reduction of about 15.4%[6] - The Trust's total liabilities as of June 30, 2024, were $335,000, slightly down from $338,000 at the end of 2023[3] - The Trust's total accrued expenses through June 30, 2024, amounted to $334,765, which were paid from the cash reserve[19] Production and Revenue - As of June 30, 2024, the average daily net production was 61.5 thousand barrels per day, with an average WTI price of $80.62 per barrel[19] - The average adjusted chargeable costs were $90.69 per barrel, resulting in a negative average per barrel royalty of $(12.89)[19] - The Trust did not receive any royalty payments for the first and second quarters of 2024 due to declining WTI prices and increased production costs[19] - HNS's net production of oil and condensate allocated to the Trust has been less than 90,000 barrels per day annually from 2019 through 2024, with expectations of continued decline[35] - The average net production from the 1989 Working Interest declined by 4.1% in the six months ended March 31, 2024, due to the naturally declining production rate from the Prudhoe Bay field[48] Cash Reserve and Liquidity - The cash reserve was increased to approximately $6,000,000 in 2021 to ensure liquidity during periods without revenue[9] - The Trustee intends to continue evaluating the cash reserve adequacy and may adjust it based on prevailing circumstances[9] - The Trust's cash reserve was established to provide liquidity during periods of insufficient revenue from the royalty interest[23] - The cash reserve is intended to cover Administrative Expenses for a two-year period if net revenues from the Royalty Interest fall below $1.0 million per year[28] Market Conditions and Price Fluctuations - The Trust's revenues are significantly affected by fluctuations in oil prices, which are influenced by global supply and demand and geopolitical events[31] - The average WTI crude oil spot price fluctuated between a high of $83.47 and a low of $70.38 per barrel in the first quarter of 2024, remaining below the "break-even" level necessary for the Trust to receive a Per Barrel Royalty[37] - The U.S. Energy Information Administration forecasts WTI prices to average $79.95 per barrel in Q3 2024 and $81.47 per barrel in Q4 2024, but there is no assurance these prices will be met[38] - The average WTI Price for Q1 2024 increased by 1.1% to $77.01 compared to Q1 2023's $76.17[43] - Average WTI Price for the six-month period in 2024 decreased by 2.1% to $77.75 compared to $79.38 in 2023[48] Administrative and Other Expenses - Administrative expenses for the six months ended June 30, 2024, increased by 3.1% to $894 compared to $867 in the same period in 2023[51] - The Trust's financial statements are prepared on a modified cash basis, reflecting the most meaningful representation of cash receipts and distributions[11] Trust Operations and Governance - The Trust's internal control over financial reporting was evaluated as effective as of June 30, 2024[54] - The Trust's termination may occur if net revenues from the royalty interest fall below $1 million per year for two consecutive years[19] - The Trustee increased the cash reserve from $1.27 million by $500,000 in July 2021 and further increased it to $6.0 million in October 2021, fully funded from Royalty Payments[27] - The Trust's royalty interest had a carrying value of $535 million at inception, with accumulated amortization and impairment write-downs reducing its value to zero by December 31, 2010[12]