Robinson Energy Receives Grant Offer for PRL 68, the Triceratops Gas and Condensate Discovery, Papua New Guinea Three wells have flowed gas at up to 28 MMcf/d from the Triceratops structure. Calgary, October 6, 2026: Robinson Energy Limited (“Robinson” or the “Company”) (TSXV: ROB | FSE: VK5) is pleased to announce that it has received an offer from the Minister for Petroleum of Papua New Guinea, the Hon. Jimmy Maladina, for the grant of Petroleum Retention Licence 68 (“PRL 68”) covering the Triceratops gas and condensate discovery in the Gulf Province of Papua New Guinea (the “Grant Offer”). The Grant Offer was made under Section 39 of the Oil and Gas Act 1998, following a report from the Petroleum Advisory Board. It is dated October 2, 2026 and was served on the Company by the National Petroleum Authority of Papua New Guinea (the “NPA”) on October 5, 2026. PRL 68 covers the area formerly held as PRL 39, which lapsed on July 6, 2026. The licence comprises nine graticular blocks and, once granted, will give Robinson a 100% interest for an initial term of five years. The licence contemplates a Company work program with expenditures of US$52 million over the term, including a minimum of one appraisal well in the fourth year. PRLs are designed to allow the holder time to investigate the commerciality of a discovery. To the extent the Company makes a decision to proceed to commercial development, the Company would need to obtain a petroleum development licence, a “PDL”. Highlights • A tested discovery. Three wells on the Triceratops structure have flowed gas to surface: Bwata-1 (BP, 1959) at up to 28 MMcf/d, Triceratops-2 (InterOil, 2012) at 27 MMcf/d, and Triceratops-3 (InterOil, 2015) at 17.1 MMcf/d with 200 bbl/d of condensate. • Independent historical resource estimate. GLJ Petroleum Consultants Ltd. (“GLJ”) estimated gross unrisked best estimate (2C) contingent resources of approximately 352 Bcfe for Triceratops, in an evaluation effective December 31, 2015 and reported in 2016. This is a historical estimate and is not being treated by the Company as a current estimate. • Located on the Papua LNG trend. Triceratops lies approximately 45 km west northwest of the Elk Antelope field, the resource base for the Papua LNG project. • Potential path to production. A Triceratops tieback into existing Papua LNG infrastructure offers a potential path to production ahead of the Company’s full Western Province pipeline and LNG development. • Commercialization concept. Gas tied back to Elk Antelope for tolled liquefaction at Caution Bay, with condensate delivered by pipeline to the Kumul Marine Terminal. Robinson intends to pursue third-party access for up to 50 MMcf/d of gas. No access agreement has been reached with the operator of the Papua LNG project. • A five-year licence at 100%. The Minister for Petroleum has offered PRL 68 to Robinson at a 100% interest for five years, with a US$52 million work program of geological and geophysical studies, infill 2D seismic, at least one appraisal well and commercial studies. Subject to the terms of the licence, the term may be extended for an additional term, or alternatively, the Company may apply for a PDL.  Field History and Production Test Rates The Triceratops structure is a carbonate gas and condensate accumulation in the onshore Papuan Basin. Gas was first tested at Bwata-1, drilled by BP in 1959. InterOil Corporation (“InterOil”) returned to the structure in 2005 and drilled two appraisal wells after it. On June 14, 2012, the Department of Petroleum and Energy declared Triceratops a petroleum discovery following the Triceratops-2 test. Bwata-1 Operator: BP Year: 1959 Test result: Gas flows up to 28 MMcf/d Triceratops-1 Operator: InterOil Year: 2005 Test result: Gas shows Triceratops-2 Operator: InterOil Year: 2012 Test result: 27 MMcf/d on DST 9; upper zone DST of 17.6 MMcf/d at a condensate yield of 13.6 to 16.3 bbl/MMcf Triceratops-3 Operator: InterOil Year: 2015 Test result: 17.1 MMcf/d gas and 200.3 bbl/d condensate, tubing constrained, 72/64 inch choke Pressure data from Triceratops-2 indicated that its upper reservoir is in communication with Bwata-1, approximately 3.5 km along trend. Triceratops-3 reached a total depth of 2,090 m measured depth and delivered stabilized rates over several five-hour flow periods. InterOil held the licence until its acquisition by ExxonMobil in 2017, and the licence subsequently lapsed without development. The test rates above are historical, were reported by the prior operators, and are short-term drill stem and flow test results. They are not necessarily indicative of long-term performance or ultimate recovery. Historical Resource Estimate GLJ, an independent qualified reserves evaluator engaged by InterOil, estimated gross unrisked best estimate (2C) contingent resources for the Triceratops discovery of approximately 58.7 MMboe (352 Bcfe), effective December 31, 2015, as reported by InterOil in 2016, the “GLJ Estimate”. 1C (low) Natural Gas: 151 Bcf Natural Gas Liquids: 3.3 MMbbl Total Oil Equivalent: 28.5 MMboe 2C (best) Natural Gas: 312 Bcf Natural Gas Liquids: 6.6 MMbbl Total Oil Equivalent: 58.7 MMboe 3C (high) Natural Gas: 561 Bcf Natural Gas Liquids: 11.9 MMbbl Total Oil Equivalent: 105.5 MMboe The GLJ Estimate is a “historical estimate” and should not be treated as current. It was prepared for a prior operator, before the lapse of PRL 39, and relies on data the Company has not yet independently verified. The Company considers it relevant because it was prepared by a recognized independent evaluator using the three Triceratops area wells and the seismic then available, and it characterizes the property’s exploration and evaluation history. In addition, significant changes in commodity prices, operating costs, development assumptions, regulatory requirements, technology and other economic and technical factors may have occurred since the GLJ Estimate was prepared. As a result, the assumptions underlying the estimate may no longer be applicable and there can be no assurance that the estimate remains reliable. Readers are cautioned not to place undue reliance on the historical estimate. A qualified reserves evaluator has not done sufficient work to classify the GLJ Estimate as current reserves or resources, and the Company is not treating it as a current estimate. To upgrade it, the Company expects to recover and reprocess the well logs, test data and seismic, and commission a new independent evaluation under NI 51-101 and the COGE Handbook. Contingent resources are not reserves, and there is no certainty that any portion of the resources will be commercially viable to produce. At the time of the GLJ Estimate, the project maturity subclass of the estimate was “development unclarified.” Projects are assigned a maturity subclass of “development unclarified” if they are still under evaluation or require significant further appraisal to clarify the potential for development, and where the contingencies have not been fully defined. “1C”: the “low” estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. With the probabilistic methods used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. “2C”: the “best” estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. With the probabilistic methods used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. “3C”: the “high” estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. With the probabilistic methods used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. Barrels of oil equivalent (boe) and Bcfe figures convert natural gas and condensate at a ratio of six thousand cubic feet of gas to one barrel. This ratio is based on an energy equivalency conversion method at the burner tip and does not represent a value equivalency at the wellhead. Commercialization Plan Robinson’s plan is to bring Triceratops into production as a tieback to the Papua LNG system. The plan has four stages. 1. Data recovery and evaluation. Recover the original well logs, test data and seismic from public and private sources, reprocess the seismic, and commission an independent NI 51-101 resource evaluation. This work forms the prospectivity review committed for the first two years of the licence. 2. Access and offtake. Pursue third-party access for up to 50 MMcf/d of gas into the Papua LNG pipeline and LNG facility, including gas processing, transport to Caution Bay and tolled liquefaction, and arrange condensate delivery by pipeline to the Kumul Marine Terminal for sale at market prices. 3. Appraisal and development drilling. Acquire infill 2D seismic and drill Triceratops-4 and Triceratops-5 to confirm deliverability and serve as producers, subject to the results of the evaluation. The licence commits the Company to at least one appraisal well. 4. Facilities and first production. Construct a production facility and a gathering pipeline to the Elk Antelope system, with a target rate of up to 50 MMcf/d of gas and associated condensate. Triceratops complements the Company’s full development plan, the aggregated Western Province pipeline and LNG export system. Timing and each stage remain subject to financing, completion of the licence grant, regulatory approvals, access terms with the Papua LNG participants, and the results of the planned technical work. Third-party access. Robinson has not entered into any agreement with the operator of the Papua LNG project, or with any of its participants, for third-party access to the project’s pipeline or LNG facility. There is no assurance that access will be granted on acceptable terms, in the volumes sought, or at all. Without such access, the tieback concept described in this release could not proceed as planned. Management Comment “Triceratops is a discovery that has already flowed gas from three wells, and it sits on the same trend as the fields feeding Papua LNG,” said Cam Bailey, Executive Chairman of Robinson. “It gives us a potential path to production that can be pursued independently of our larger Western Province development. Our first priority is to rebuild the technical record and put a current independent evaluation behind the asset. At the same time, we will open discussions on access to the Papua LNG system. We thank the Minister for Petroleum, the Hon. Jimmy Maladina, the Petroleum Advisory Board, the National Petroleum Authority and the Government of Papua New Guinea for their confidence in Robinson.” About Robinson Energy Limited Robinson is an upstream natural gas company focused on the appraisal and development of its 100% held Petroleum Retention Licence 62 (“PRL 62”), located in the Western Province of Papua New Guinea. The Company’s strategy is to advance the exploration and development of PRL 62’s resource potential to deliver reliable, lower-carbon energy to domestic Papua New Guinea and export markets across Asia, drawing on Canadian technical and capital-markets expertise and the established energy-services footprint in the region. For Further Information, Please Contact J. Cameron Bailey Executive Chairman jcbailey@robinsonenergy.ca +1 403 680 0434 Neil Bothwell Chief Financial Officer neil@robinsonenergy.ca +1 403 874 2769 Neither the Exchange nor its Regulation Services Provider, as that term is defined in the policies of the Exchange, accepts responsibility for the adequacy or accuracy of this release. Cautionary Statement Regarding Forward-Looking Information This news release includes certain “forward-looking statements” under applicable Canadian securities legislation, collectively referred to as “forward-looking information.” Forward-looking information is generally identifiable by words such as “anticipates,” “believes,” “expects,” “intends,” “plans,” “proposes,” “targets,” “will,” “may,” “could,” “should” and similar expressions suggesting future outcomes or events. Forward-looking information contained in this news release includes, but is not limited to, statements concerning: the Company’s intention to satisfy the conditions of the Grant Offer, including the request for grant, the lodging of security and the payment of the first annual fee, and the anticipated formal grant of PRL 68; the terms of PRL 68, including the Company’s anticipated 100% interest, the five-year term, the required work program and minimum expenditure commitment of US$52 million, and the funding of that program; the recovery and reprocessing of historical well logs, test data and seismic information; the commissioning and timing of a new independent evaluation under National Instrument 51-101 and the COGE Handbook; the Company’s plans to pursue third-party access to the Papua LNG pipeline, gas-processing and LNG facilities and the Kumul Marine Terminal; the potential tieback of Triceratops to the Papua LNG system; the potential transportation, processing, liquefaction and sale of natural gas and condensate produced from Triceratops; the negotiation and execution of access, transportation, processing, liquefaction, offtake or other commercial arrangements; the potential drilling of the Triceratops-4 and Triceratops-5 wells and their potential use as production wells; the construction of production facilities, gathering pipelines and related infrastructure; potential production of up to 50 MMcf/d of natural gas and associated condensate; the timing of first gas, including the target of first gas in early 2030; the ability to bring Triceratops into production before the development of the Company’s proposed Western Province pipeline and LNG export system; and the Company’s broader plans to aggregate Western Province gas resources and supply North Asian LNG markets. The forward-looking information in this news release is based on assumptions that management considers reasonable as of the date hereof, including assumptions concerning: the Company’s timely acceptance of, and satisfaction of the conditions attached to, the Grant Offer; the formal grant, validity and continuation in good standing of PRL 68 on the anticipated terms; the Company’s ability to obtain access to complete and usable historical technical information; the quality, completeness and utility of the historical well, test and seismic data; the results of reprocessing, technical interpretation, appraisal activities and an updated independent resource evaluation; the presence, quantity, quality, deliverability and commercial potential of hydrocarbons at Triceratops; the availability of equipment, personnel, services and infrastructure; the technical and commercial feasibility of connecting Triceratops to the Papua LNG system; the availability of capacity in the applicable pipeline, processing, LNG and condensate transportation infrastructure; the willingness of the owners and operators of that infrastructure to negotiate and grant access on commercially acceptable terms; the receipt of required government, regulatory, environmental, landowner and third-party approvals; the availability of financing on acceptable terms; future commodity prices, operating costs, capital costs and fiscal terms; and the absence of material adverse changes in applicable laws, regulatory requirements, market conditions, infrastructure availability or project economics. Forward-looking information is subject to known and unknown risks, uncertainties and other factors that could cause actual results or events to differ materially from those expressed or implied by such information. These risks and uncertainties include, but are not limited to: the Grant Offer not being accepted in the required period or PRL 68 not being formally granted on the terms anticipated or at all; the imposition of additional conditions or work commitments; challenges concerning the validity, continuation or renewal of PRL 68; the inability to obtain or adequately reconstruct the historical technical record; historical data proving incomplete, inaccurate or unsuitable for current evaluation purposes; the results of seismic reprocessing, appraisal work or an updated independent evaluation differing materially from historical information or management’s expectations; uncertainty concerning the existence, classification, volume, deliverability, development potential and commercial viability of any resources; unsuccessful or delayed appraisal drilling; geological, reservoir, drilling, completion, construction and operating risks; cost increases, supply-chain constraints and delays; the inability to obtain required financing; changes in commodity prices, operating costs, capital costs, exchange rates or fiscal terms; the inability to obtain necessary governmental, regulatory, environmental, landowner or other approvals; changes in the laws, policies or political, economic or operating environment of Papua New Guinea; the unavailability of capacity in the Papua LNG system or other required infrastructure; the inability to negotiate third-party access, transportation, processing, liquefaction, condensate handling, offtake or other commercial arrangements on acceptable terms or at all; dependence on third-party infrastructure owners and operators; delays affecting the Papua LNG project or related infrastructure; and other risks inherent in the exploration, appraisal, development and production of oil and natural gas. In particular, the Company has not entered into any agreement with the operator or participants of the Papua LNG project for access to the project’s pipeline, processing or LNG facilities, and there can be no assurance that such access will be available in the capacity sought, on acceptable terms or at all. If the required third-party access and commercial arrangements are not obtained, the tieback and commercialization concept described in this news release may not proceed as currently contemplated. Although the Company believes that the assumptions and expectations reflected in the forward-looking information are reasonable as of the date of this news release, there can be no assurance that they will prove to be correct. Actual results and future events could differ materially from those anticipated. Readers are therefore cautioned not to place undue reliance on forward-looking information. The forward-looking information contained in this news release is made as of the date hereof, and the Company undertakes no obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by applicable securities laws.

A new report says Alberta’s energy sector is still in a good position to grow, even though global oil markets remain unpredictable. “We obviously saw elevated oil prices throughout much of this year with the Strait of Hormuz. Right now prices are a little bit lower,” said Deloitte energy partner, Andrew Botterill. “Countries going to need to rebuild on their strategic reserves that they really decimated here in the last few months.” Botterill points to an average WTI price for the remainder of the year around $80 U.S. a barrel. The Deloitte report says global energy prices remained elevated through the second quarter of 2026 as markets continued to grapple with supply disruptions, shifting demand and geopolitical uncertainty. Despite those challenges, Canada and the United States both reached record crude oil export levels, with Alberta’s oil sands playing a major role in production growth. The report notes that producers are choosing projects that cost less and can be developed more quickly, like conventional heavy oil drilling and in-situ operations. This helps companies stay profitable, even when prices drop. Looking ahead, Deloitte forecasts continued production growth, supported by planned pipeline expansions and optimizations that could add about 800,000 barrels per day of export capacity by 2030. “What we’re going to see is this renewed investment in recognition of what the global supply chain is going to kind of shift a little bit,” said Botterill. “Think we’re just going to see a little bit of a shift in the next five years of maybe not everything is going to come from the Middle East.” He points to Asian and European market becoming more reliant on Canada energy. The report says most oil sands development remains concentrated in the Athabasca region, while activity in the Cold Lake and Peace River regions has increasingly shifted toward conventional heavy oil production. It predicts oil prices will fall over the next few years, with WTI crude settling in the $65-$75 U.S per barrel mark. Richard Masson, former CEO of the Alberta Petroleum Marketing Commission calls that a middle of the road scenario. “Very adequate to make a lot of free cash flow from their existing projects,” said Masson. “From Alberta’s point of view, it doesn’t necessarily balance the budget, but it probably goes a long way.” The report came after Alberta Premier Danielle Smith announced separate pipeline proposals with Prime Minister Mark Carney and Ontario Premier Doug Ford, arguing that additional energy infrastructure will be needed to support future production growth. Masson says that forecast will also be able to support future projects “Oil sands projects don’t need $100 to be successful,” he said. “$65-75 the money would allow them to continue to grow, and fill up the Trans Mountain, Enbridge, South Bow and eventually the million barrels a day pipeline if these things can be brought in.” LNG production Robinson Energy, headquartered out of Calgary, was established in May 2022 and develops existing natural gas resources in Papua New Guina. “What’s happening with the Iranian war is that the (disruption) to the Strait of Hormuz has really disrupted the supply of LNG into, the largest marketplace in the world,” said Robinson Energy’s CEO Cam Bailey. Bailey points to a fifth of the world’s gas supply being held up in the Strait of Hormuz during the war. Robinson Energy has accumulated 140 gas wells in Papua New Guinea and will look to capture part of the Asian market. “Whoever captures that marketplace today, will have that secured for a long time coming,” said Bailey. Bailey added the political issues to get gas to market in Canada “have been so difficult.” “Papua New Guinea, those constraints don’t exist,” said Bailey. “That’s part of the reason why we’ve chosen to take Canadian technology and methodologies and apply to a jurisdiction where we’re not hamstrung with those problems.” Botterill anticipates growing demand for LNG over the next five to 10 years.