Good morning. My name is Natalia, and I will be your operator today. Welcome to Ecopetrol's earnings conference call, in which we will discuss the main financial and operating results in 2025. Before we begin, it is important to mention that the comments in this call by Ecopetrol's senior management include projections of the company's future performance. These projections do not constitute any commitment as to future results nor do they take into account risks or uncertainties that could materialize. As a result, Ecopetrol assumes no responsibility in the event that future results are different from the projections shared on this conference call. The call will be led by Mr. Ricardo Roa, CEO of Ecopetrol; Juan Carlos Hurtado, Executive Vice President of Hydrocarbons; Camilo Barco, CFO; and Bayron Triana, Executive Vice President of Transition Energies. Thank you for your attention. Mr. Roa, you may begin your conference.

Good morning. Thank you for joining us today for Ecopetrol Group's Fourth Quarter and Full Year 2025 Results Call. Last year, we achieved our goals, maintained financial discipline, stable operations, maximizing value management, drivers that reflect the strength of our strategy and the group's ability to operate in a challenging environment. We consolidated a 44% 3-year success rate in exploration the industry average and exceeded our 2025 target by 60% drilling 16 wells. This team achieved the second highest net profit in history. In production and refining, we met our targets within the announced range and achieved a reserves replacement ratio of 121%, the highest in the last 4 years. In 2025, we marketed in advance 100% of the Sirius gas and moved forward with new supply alternatives. On the other hand, we declared the well Lorito to be commercially viable. Also, we surpassed our renewable energy capacity goal, reaching 951 megawatts, initially set by 2030 and strategic milestone for diversifying the company's energy metrics. But in ISA, we executed investments 31% higher in 2024 with projects of a total amount of $664 million. I would like to highlight how our efficiency program delivered historical results in 2025 accumulating more than COP 16 trillion over the past 3 years, strengthening our financial position and supporting business sustainability. 2025 was a year of reliable execution. We maintained the group's long-term sustainability and met the goals announced to the market. Average production reached 745,000 barrels per day. Transportation exceeded 1.1 million barrels per day and refining throughput reached 417,000 barrels per day. Both operational performance and the efficiency program mitigated the impact of an adverse environment, considering a reduction of nearly 15% in crude prices. Despite this, we maintained an EBITDA margin in line with expectations, demonstrating discipline and resilience. On the commercial front, we achieved the best crude differential of the past 4 years. We closed 2025 at $4.6 per barrel, an improvement of $2 compared to 2024, driven by market diversification, basket optimization and effective coordination among our trading companies. Finally, to our shareholders. In 2025, we transferred COP 35 trillion to the nation in dividends, taxes, and royalties. This result ratifies Ecopetrol's role as a fundamental pillar for national economic development. The Board of Directors will propose to the general assembly on March 27 a dividend of COP 110 per share equivalent to 50% of net income under the dividend distribution policy of Ecopetrol. This proposal reaffirms our commitment to responsible, sustainable and value-oriented dividend distribution. Let's move to the next slide. At the end of 2025, Ecopetrol reached 1.944 billion barrels of oil equivalent improving 1P reserves, supporting the long-term sustainability of our operations. This result was mainly driven by organic growth, which added 314 million barrels through enhanced recovery, the largest reserves incorporation in the history as well as operational optimization that contributed with 19 million barrels helping to offset external variables such as Brent prices, exchange rates and inflation. In addition, according to Law 2056 of 2020 and Resolution 164 of 2015, reserves associated with crude royalty securitization were incorporated. This practice is recognized by the SEC and has been applied to gas royalties since 2014 for Ecopetrol Group. The total crude incorporation amounted to 314 million, 1.6x the year's production, allowing the company to reach historic highs in one peak crude reserves volumes, reaffirming the resilience of the field, both nationally and internationally. In gas, natural decline led to a reduction of 4.7 million barrels of oil equivalent partially offset by results at Pauto and Pauto fields, where pressure reduction techniques and hydraulic improvements were implemented to extend wells' life. We expect this trend to be reversed in the medium term as we progressively enable volumes discovered in Sirius and KG. Internationally, we continue to advance in the Orca Brazil Gas to the Market project after the commerciality declaration in 2025. Once the development plan gets the approval by the National Agency of Petroleum, Natural Gas, and Biofuels of Brazil, resources will gradually be progressed as reserves. Let us move to the next slide. In 2025, we also advanced firmly in ESG indicators by strengthening our environmental, social and governance commitments. On the environmental side, we reduced 561,000 tons of CO2 equivalent 165% of the annual target. We also received the Gold Standard recognition for methane management from the United Nations, validating our technical and transparent approach based on environmental protection. Ecopetrol consolidated its leadership in Colombia's aviation energy transition by supplying co-processed jet fuel with renewable feedstocks for the operation of more than 700 LatAm flights. Regarding water management, we reused 181 million cubic meters, equivalent to 82% of water used in operations, a 10% increase compared to 2024, positioning us as a global benchmark in the sector. In energy transition at the Cartagena Refinery, we began installing the largest PEM electrolyzer in Latin America, capable of producing 800 tons of green hydrogen per year and avoiding up to 7,700 tons of CO2 equivalent annually. In 2025, we consolidated our leadership in Works for Taxes in Colombia. Since 2018, we have accumulated 154 projects, worth COP 1.4 trillion equivalent to 35% of the national total. Only in 2025, we completed 21 projects worth COP 109 billion, benefiting more than 49,000 inhabitants in 31 municipalities across 12 departments. On corporate governance, we highlight the approval of the statutory reform that incorporates an employee representative on the Board of Directors, strengthening diversity participation and best governance practices. With this, I hand over to Juan Carlos, who will present the details of the Hydrocarbon business performance.

Thank you, Ricardo. On the exploration front, we continue to strengthen our portfolio. By the end of 2025, we drilled 16 wells, exceeding our target of 10. Of these 16, 7 were successful, 5 are under evaluation and 4 failed, achieving an average success rate of 44% over the last 3 years, placing us at competitive levels within the industry. In 2025, we promoted the maturation of discoveries towards the development phase with a potential of over 455 million barrels of crude equivalent to 24% of the current reserve of the Ecopetrol Group, highlighting one first commercial declaration of 4 exploration areas of Orca Brazil, Lorito, Toritos and Saltador. Second, the extension of the commercial area of the Terecay field, reaffirming the potential of Los Llanos Centrales. These volumes will gradually be incorporated into 1P reserve as their development progress. Environmental license is currently underway for the Lorito project and the development plan for the Orca asset is awaiting approval from the Brazilian National Ports Administration. In the Sirius project, the delineation stage of the discovery was completed, confirming the potential of the 6 trillion cubic feet. Furthermore, the ANH approved the extension of the 10 exploration and production contracts and agreements with additional terms between 1 and 4 years and authorized the transfer of 50% of the participation and operation to Parex Resources Colombia in the Farallones E&P agreement. By 2026, in association with Parex, we expect the drilling of 2 exploratory wells in the Pedemonte and Farallones extension agreement. Next slide, please. On the production front, we reached a total accumulated production of 745,000 barrels of oil per day, in line with the established target at levels comparable to those of 2024. This result was largely driven by national crude production, which reached 517,000 barrels, the highest level in the last 5 years. Thanks to, first, the enhanced recovery strategies to increase production in major fields and mitigate natural decline. Second, growth in production from the Caño Sur fields, and third, the acquisition of a 45% stake in the CPO09 block. We highlight that this production level was achieved with a 10% optimization at the initial planned investment, and we achieved efficiencies of more than $139 million in drilling and completion activities. The 2026 organic investment plans have a simple breakeven of $40 per barrel, positioning this as a competitive portfolio given current market conditions. Of this portfolio, 88% of the investment will be concentrated in growth projects. Among the milestones to be achieved in 2026, we aim to increase the number of development wells to be drilled in the country compared to 2025 and extend the development plan in Midland with Oxy until July 2027. Jointly defined with the price framework, the interest of both and aligned with the reduction in activity. Next slide, please. By the end of 2025, the Transportation segment posted one of its best historical performance in EBITDA and net income, affirming its flexibility and operational efficiency amid a challenging environment. Regarding transport volumes, the segment through the strategic investments and operational adjustments managed to expand evacuation options to capture volumes outside the network and respond actively to the needs of both the business growth and the market. In the context, the following milestones stand out, which enabled us to transport volumes above 1,100,000 barrels through the network. First, expansion of evacuation capacity in oil pipelines by more than 122,000 barrels, multiproject pipelines by more than 10,000 barrels and additional storage capacity by 323,000 barrels, thanks to the commissioning of the new tanks in Pozos Colorados. Second, commissioning of the crude oil import scheme from Coveñas to our Barrancabermeja refinery to mitigate and respond to the third-party impact on the infrastructure monitoring schemes, operational control and the interinstitutional coordination were strengthened in the Caño Limón - Coveñas system. The timeline activation of alternative evacuation routes together with flexible operating schemes and the use of the technology allowed us to preserve system continuity, avoid deferred production and maintain refinery supply. From a financial standpoint, prioritization of cost optimization neutralizing external effects such as the exchange rate and maximizing the use of infrastructure among other measures enabled the segment to achieve an EBITDA of COP 11 trillion and net income close to COP 5 trillion, one of the highest results in the history of the segment. Continuing with the refining segment results, solid operational execution and commercial decisions allow us to capture better international price differentials, strengthening profitability reservations of the business for 2025. We highlight the historical record of 113,000 barrels per day of integrated throughput in the fourth quarter of 2025, reflecting operational stability and high unit reliability after major maintenance in the first half of the year. The results contributed to the annual total of 470,000 barrels. The gross refining margin increased by 32% in 2025 compared to 2024, increasing from $9.9 to $13.1 per barrel, thanks to production focus on higher value and higher quality fuels, crude basket optimization, prioritizing the processing of crudes with greater economic contribution and acting opportunity to capture international price differentials. EBITDA reached COP 2.7 trillion, 20% higher compared to 2024, driven by prioritizing operational and energy efficiency, which kept refining costs under control and strengthened competitiveness and resilience in the face of energy and price conditions. In practice, each barrel contributed more supported by the system's capacity to take advantage of international price differentials, control and unit costs and energy use efficiencies. Regarding electrical reliability in Cartagena, efforts continued throughout 2025 to manage and decrease risk with a projection of reaching a tolerant risk level in 2026. In 2025, progress reached 81%. 3 out of the 13 out of the 16 milestones were completed and connection to the national interconnecting system was secured. 70 megawatts of backup, reducing exposure to grid events and supporting established operation. Next slide, please. During 2025, the efficiency program was consolidated as a key driver for value generation in the hydrocarbons line. We implemented decisive actions to maintain competitive unit costs, which have allowed us to offset exchange rate and inflationary impacts. At the end of 2025, the total unit cost of the Hydrocarbons line was $46 per barrel, a significant decrease of $1.7 or 3.4% compared to 2024, mainly driven by the synergies implemented in crude oil purchasing and strict cost-executing discipline. The lifting cost stood at $12.2 per barrel, $0.3 less than in 2024, marking 2025 as an important turning point in the indicator trend. Efficiencies played a fundamental role by contributing $0.96 per barrel in optimization. The refining cash cost and transport barrel costs remained stable during 2025, closing at $5.75 per barrel and $3.41 per barrel, respectively. This reflects the effective mitigation of inflation and exchange rate pressures as a result of the established operational discipline and efficiency materials throughout the year. Despite the impact of the exchange rate on costs expressed in dollars, the trend in local currency confirmed operation control, financial discipline and our commitment to ensuring a downward trajectory in our key cost indicators. Now I will give the floor to Bayron, who will discuss the main milestone of the energy transition line.

Thank you, Juan Carlos. 2025 was a year of disciplined execution in the energy transition business line. We made progress in strengthening energy security, scaling our renewable portfolio and capturing efficiencies with operational and financial impact. In relation to natural gas, the Ecopetrol Group remains committed to generating value and contributing to the growth of the country's supply with Ecopetrol being the only producer to market long-term volumes during 2025 for the period 2026 to '29. As a result, in December, we closed the sale of gas from the Sirius field together with Petrobras, selling the entire volume up to 249 GBTUD, a key step forward for its entry in 2030. Similarly, for 2026, the Ecopetrol Group has signed gas sales contracts for an average of 326 GBTUD to mainly serve the residential and commercial segments, reaching an estimated coverage of 76% of its demand, 6 percentage points more than in 2025. In terms of gas supply optionality, complementary to offshore development in 2025, we will market 60 GBTUD of reclassified gas through Buenaventura with deliveries scheduled for 2026. Additionally, in February, we began marketing 2 products with an offer between 126 and 370 GBTUD, which will be delivered through Sociedad Portuaria Puerto Bahía, starting in December 2026. Let's move to the next slide, please. In terms of electricity, by the end of 2025, we reached nearly 951 megawatts of capacity incorporated into the renewable energy portfolio, exceeding the target of 900 megawatts. This growth contributes to reducing the unit cost of our electricity supply. Within this portfolio, operating capacity grew by 94% from 186 megawatts at the end of 2024 to 381 megawatts at the end of 2025. This growth is explained in part by the acquisition of Statkraft's asset portfolio, which included the Portón del Sol solar farm, the first asset operating in Colombia under the remote self-generation scheme as well as the entry into operation of the La Cira and La Iguana projects. The combined operation of the group's solar farms and the Cantayús small hydroelectric plant avoided the emission of approximately 47,000 tons of CO2 equivalent and generated savings of around COP 55 billion in 2025. In addition, in December 2025, the 205-megawatt Windpeshi wind farm reached its FID. This project will be the first wind project built and operated 100% by Ecopetrol as well as one of the largest in the country. I would like to highlight that during 2025, these efforts enabled us to reduce the electricity supply tariff for Ecopetrol Group by approximately 4%, contributing among other things, to mitigating pressures on lifting costs. Ecopetrol Group's electricity demand is equivalent to 10.25% of the energy in the national interconnected system. This demand was covered 92% through self-generation, both conventional and renewable and through contracts in the wholesale energy market, MEM as it is known in Colombia. When contracting in the MEM, the group seeks to mitigate variations in the cost of electricity supply through planning supported by risk policies. To this end, it plans energy contracting with horizons of between 1 and 3 years, considering the expansion of the system, the evolution of demand and climate effects. Next slide, please. Now I would like to highlight our efforts in energy efficiency, which is a structural level of competitiveness for Ecopetrol Group. 2025 closed with 4.79 petajoules of energy optimization, 1.6x the annual target, generating significant emissions reductions and savings. This result led us to achieve 99% of the goal of 25 petajoules of cumulative energy optimization between 2018 and 2030 ahead of schedule. The improvements were achieved through 80 initiatives comprising operational control of production processes, investments in technological upgrades of high consumption equipment and energy management systems in the Transportation segment. Finally, in terms of our contribution to energy justice in the regions, in 2025, the gas social project achieved its historical peak, completing more than 114,000 cumulative connections in 21 departments across the country. And in energy communities, we reached 3.8 megawatts accumulating in operation and construction, helping more than 58,000 people with centralized renewable solutions that strengthen energy autonomy and expand access to affordable energy. I now give the floor to Camilo Barco to detail the financial performance for the period.

Thank you, Bayron. 2025 results confirm that Ecopetrol Group delivered performance in line with the annual investment plan reported to the market. The company operated with financial strength supported by an improved OpEx reduction target and CapEx flexibility, which boosted efficiencies across all segments and business lines, even in an environment marked by lower crude prices compared to 2024, higher tax burden and inflationary pressure. In 2025, we achieved an EBITDA of COP 46.7 trillion with a stable EBITDA margin aligned with the annual target of 39%, driven by the gradual recovery of the refining segment, the stability of the Transportation segment and the significant contribution of the profitability and efficiency program. The exploration and production segment contributed approximately 51% of the EBITDA, while the Transportation and Transmission and Road segments jointly contributed 43% and refining accounted for the remaining 6%. It is worth highlighting the continued recovery of the downstream segment, which delivered a 20% increase in EBITDA compared to 2024, supported by favorable market conditions for product differentiation. Likewise, portfolio diversification through the contribution of the transportation business and ISA has been key to the group's performance in periods of high volatility. During 2025, the profitability and efficiency programs delivered a record target of approximately COP 6.6 trillion, exceeding the adjusted annual target of COP 5 trillion by 1.3x and reaching nearly COP 23 trillion over the past 5 years. These results reflect our commitment to financial discipline, value creation and sustained contribution to the group's performance. In 2025, this efficiency plan enabled optimizations with an effect on EBITDA of approximately COP 3.6 trillion. In CapEx, we achieved COP 2 trillion in efficiencies through the successful execution of the investment plan, driven by upstream optimizations, particularly in surface facilities, drilling and completion activities. In OpEx, we achieved COP 1.8 trillion in efficiencies, thanks to improvements in energy, maintenance and digitalization. These efforts contained costs in an inflationary environment and improved key indicators such as lifting costs, which decreased by $0.9 per barrel, maintained the Barrancabermeja refinery conversion index near 91% and reduced energy consumption by 4.8 petajoules equivalent to COP 130 billion. These results not only support the 2025 performance, but also consolidate a more competitive basis to face the challenges of 2026. Additionally, our financial flexibility, operational strength and cash management contributed to a total shareholder return of 24% for local investors when combining dividends and share price variation and 39% for our shareholders in the United States. Likewise, our focus on capturing efficiencies enabled us to reach a net income breakeven close to $50 per barrel, reaffirming the competitiveness and resilience of our diversified portfolio. Regarding investments, we closed the year with $6.3 billion in organic investment execution within the range outlined in the investment plan. We highlight the following investments: Hydrocarbons, $3.9 billion, 63% of the total with focus on Meta, Piedemonte, Permian and Brazil. Energy transition and gas, $750 million, 12% of the total for advancing infrastructure to ensure medium-term supply for the country and complementing our energy matrix through renewable energy. And transmission and road, around 25% of the total investments were allocated primarily to the power transmission project. Brazil accounted for the largest share of investment followed by Colombia, Chile and Peru. In total, ISA advanced on 26 transmission projects, 183 reinforcements and upgrades in Brazil and 3 road concession projects which together will add approximately 4,988 kilometers of transmission lines and 296 kilometers of roads once they enter into operation. Let's move on the next slide. Net income for the year totaled COP 9 trillion, a level close to the target established in the financial plan despite a lower average of Brent price of USD 5 per barrel versus the initial estimate of USD 73 per barrel. The outcome is mainly explained by the following factors. First, nonrecurring effects recorded in 2024, such as the valuation of CPO-09 and the reversal of impairment, which generated a positive impact of COP 1.6 trillion. Those were not perceived during 2025. It is important to highlight that these nonrecurring factors did not represent cash outflow nor affected our cash flow results. Second, market factors, including the 15% annual decline in Brent prices, which went from $80 in 2024 down to $68 per barrel in 2025. Inflationary effects on cost and expenses and the revaluation of the Colombian peso against the U.S. dollar had a combined impact of 7.2 trillion. Third, external events such as blockades at production fields, a tax on infrastructure, and new taxes derived from the state of internal commotion decree and the nondeductible VAT on fuel imports reduced our net income by COP 1 trillion. These effects were partially offset by the improved performance of crude and product differential, which contributed COP 2.6 trillion as well as OpEx optimizations and our commercial strategy, which contributed an additional COP 1.3 trillion. External factors altogether amounted to COP 5.6 trillion and explained nearly 95% of the decline in net income between 2024 and 2025. Operational and commercial activity compensated for approximately 22% of the variation. Let's move on to the next slide, please. In terms of liquidity, we closed December with a consolidated cash position of COP 12.7 trillion, maintaining a solid stance supported by operating cash generation and working capital optimization. Free cash flow for the year reached COP 11 trillion, driven by operating cash generation, boosted by the early collection of COP 7.7 trillion from FEPC and cost and expense reduction measures and also the disciplined execution of CapEx in line with the estimates established in the plan. In working capital management, we strengthened liquidity by reducing the FEPC balance to its lowest levels within the last 5 years and by offsetting COP 6.9 trillion in tax credit. To manage foreign exchange risk, we executed hedges using financial instruments that protected between 6% and 16% of monthly dollar-denominated revenue. Likewise, to mitigate Brent price volatility, we carried out hedging operations during the second half of 2025 to cover between 8% and 20% of export volume. For 2026, working capital management will focus on the collection or offsetting of the 2025 tax credit balance, which closed at COP 11.4 trillion as well as on the collection of the FEPC receivables around COP 3 trillion. We have also initiated execution of the hedging plan to mitigate market risk associated with price and exchange rate volatility in 2026. Regarding the ongoing process with DIAN concerning import VAT on fuels for the period 2022 to 2024, the administrative stage has concluded for 3 cases, one in Ecopetrol and the other 2 in Reficar, amounting to approximately COP 9.6 trillion, including estimated penalties and interest. The company maintains its position not to record the provision based on the opinion of external legal advisers and in accordance with the accounting standard. Now let's move on to the next slide. 2025 was a key year in consolidating our financing strategy and ended with an adequate debt structure, a controlled maturity profile and a gross debt-to-EBITDA ratio of 2.3x, below the maximum level of 2.5x established in the company's strategic framework. Excluding ISA, this ratio stood at 1.6x, reflecting a healthy leverage level comparable to the oil and gas industry peers. During the year, the following achievements stand out: the renegotiation of bank debt, resulting in rate reduction of up to 80 basis points for U.S. dollar-denominated loans and 85 basis points for Colombian peso-denominated loan, the securing of a new committed line of up to COP 700 billion available under any market scenario and the structuring of financing mechanism to support inorganic growth opportunities with the energy transition strategy. It is important to note that the group's liquidity remained fully secured throughout the year without the need to increase long-term debt to finance Ecopetrol's organic investment plan even in an environment of lower-than-expected revenues relative to the investment plan. During the year, the group's incremental debt reached approximately $1.8 billion equivalent. Around 70% corresponded to ISA, mainly due to the conversion of its pesos-denominated obligations into U.S. dollars, while the remaining 30% corresponded to Ecopetrol specifically allocated to inorganic business opportunities. In 2026, we plan to continue strengthening the company's capital structure and do not expect definitive incremental debt to finance Ecopetrol's organic capital. Our focus is on optimizing the financial cost and debt structure while reinforcing liquidity and flexibility in working capital management. Should we identify inorganic growth opportunities, this may require additional debt always under the principle of maintaining controlled leverage level. We will continue monitoring market conditions and will be prepared to respond and adapt to different scenarios. Finally, let's move on to the next slide to detail this year's investment plan. The investment plan projected for 2026 ranges between $5.4 billion and $6.7 billion. These align with our historical execution levels and allocated to strengthening the traditional business while advancing strategic priorities in the energy transition. The plan is based on an average Brent price expected of $60 per barrel and an exchange rate of COP 4,050 per dollar within a price range that allows us to adapt to different scenarios, maintaining strict capital discipline and ensuring competitive returns with a target EBITDA margin of 40%. With approximately 70% of total investments, the Hydrocarbons business will continue to be the core driver, considering a production target between 730,000 and 740,000 barrels of oil equivalent per day, refinery throughputs between 410,000 and 420,000 barrels per day and more than 1,100,000 barrels transported per day. This performance is supported by enhanced oil recovery technologies that optimize resources, increase crude production in Colombia and offset the natural decline of gas. Likewise, we expect to drill between 380 to 430 development wells and up to 10 exploratory wells prioritizing the most profitable opportunities within our portfolio. In transportation and refining, investments will strengthen the integrity and reliability of the group's critical infrastructure. The remaining 30% of investments will deepen diversification into low emission businesses, including transmission and road, the integration of renewable energy and sustainability projects that enhance portfolio resilience. As part of the 2026 plan, we expect to capture approximately COP 5.7 trillion in efficiencies and deliver COP 28 trillion in transfers to the nation. Additionally, we aim at maintaining a net income breakeven close to $47 per barrel. In renewable energy, we expect to incorporate an additional 750 megawatts of projects in operation, construction and execution. Our goals reflect financial discipline, a focus on profitability and a measurable impact in our energy transition strategy. During 2026, we will continue executing with discipline, prioritizing investments that strengthen our portfolio and ensuring that each decision contributes to a more competitive, resilient and results-driven group. Now I will turn it over to the President, who will present the conclusion.

Thank you, Camilo. In 2026, we will maintain a clear strategic focus, a strict capital discipline, strengthening traditional business, and ensuring the group's long-term sustainability. Natural gas is a strategic lever. We are advancing offshore projects and maintaining continuous exploration activity as a pillar to progress resources into reserves. At the same time, we will proactively manage supply sources to ensure reliability and flexibility. We continue progressing in the energy transition with the start of civil works at the Windpeshi project, community responsible compensation, and the launch of green hydrogen production at the Cartagena Refinery in coming months. We manage working capital, securing liquidity, and reducing cash flow pressures in a volatile environment. We delivered the plan presented for 2025 and expect to comply with the one defined for 2026. With this, we open the question-and-answer session. Thank you very much.

I have a couple of questions. One is about the Permian, and I'd like to know if you could give us more clarity on why there was a sequential fall of the production. And if this result is because of less intensity in the drilling or what happened? And considering what you have been doing in the Delaware. Camilo, could you tell us what's the total production at Permian and Delaware? And overall, how many wells do you think that you will be drilling this year to reach those 11,000 barrels per day? And the second question has to do with dividends. Looking at the figures of 2025 of the company, you could see that the cash flow of the company was hurt. And Camilo, could you give us more clarity on the dividend, which was approved by the Board of Directors? Is it subject or not to the collection of the fiscal and the fiscal and the ISAPEC?

Regarding your first question, you have to keep in mind that in 2024, we had about 94,000 barrels per day and for 2025, 122,000. So this year, today, we can say that we are above 91,000 barrels in the first months of the year. And this is basically agreed in the development plans of the agreement that we have in term – and it depends on the activity as everybody knows and of the prices because it's the type of field that we work on really depends on the prices right then. So it's related to that. For this year, we estimate that we will have 38 to 40 wells. But while the price of the barrel moves, we can start looking at our investment plan.

I'm sorry. Can I ask you something else about this? Those 78,000 barrels include Delaware or what? Because it said only Midland.

It includes everything. All of the basin or the fields that we have. The topic of the reduction of activity is reflected throughout the premium about – from '24 to '25, we see a 12% reduction in the number of drills in 2024, 309 throughout the basin to 273, and we moved from 4 to 2.

On your question about dividend, there are several aspects. First and very important for everybody that's joining us today. The distribution of dividends is given by the authority of the shareholders' meeting. So it's important to keep in mind that this is the recommendation preapproved by the Board of Directors to be given to the shareholders' meeting. It's a recommendation of 5.1% of the activity available for shareholders, which is COP 110 per share. And if it's related to the ISAPEC, it's important also to mention that the cash flow of Ecopetrol has an important impact on certain accounts that are crossed with those of the nation in favor and against, not only ISAPEC, but also the balance of taxes in favor are things that have an impact on the cash flow. And we hope that as we've seen in prior years to have a discussion in which we agree with the Ministry of Treasury. We can reach agreements on the timetable of payments of ETEC, which determine the timetable of payments of dividends indeed.

I have 2 questions. No, 3. One, along with what Daniel asked, I'd like to understand, could you give us guidance on the tax on equity that Ecopetrol will be paying, understanding that the proposition of dividends is only one payment in April? And could you give us guidance to see – I believe it's close to COP 1 billion. And I'd like to also understand how you will manage the liquidity and the resources to make these payments understanding, of course, the level of cash flow you have today. And also to understand on a short-term basis with the leverage indicators. That's my first question. Second question relates to the reserves. This report surprises us because of the change in the agreements with the National Agency of Hydrocarbons. So I'd like to understand why you made a change in the contracts, especially in that aspect? And how can this really benefit Ecopetrol because it's an accounting change that makes the added value to look higher? But from another viewpoint, do you really see a benefit? And if there is one, what percentage of the contracts are currently tied to royalties in sample and in money? And my third and last question relates to the breakeven profit. The gap between the breakeven and the EBITDA is wider. And if we look at the end of 2025, there is a difference that's quite big, about $18 per barrel. So I'd like to understand if that difference in the total what proportion is explained by the higher taxes that we've observed that Ecopetrol is paying and if it relates to other reasons?

On your question related to the equity tax, the calculation that you mentioned is correct. What we estimated to pay by Ecopetrol is between COP 1 billion and COP 1.3 million calculated as the rate of COP 1.6 million over the liquid equity. This payment will be made in April. How does it relate to the liquidity? It's important to say that we have tax balances in favor that ended at a high level in 2025, close to COP 11.5 billion, which give us good space to compensate part of that tax. Otherwise, the cash flow and the liquidity of the group are in healthy conditions as we saw COP 12.7 billion consolidated total cash, and that gives us the capability to maneuver and make all the payments of dividends and the debt on a timely basis. Also, we have to keep in mind here. When it comes to the tax equity and other taxes, there are discussions constantly made with the Ministry of Treasury that allow us to have agreements on the availability of the group's cash flow and the requirements of treasury and also allow us to align the timelines of payments of these.

We can continue with the question on reserves. My name is Ricardo Roa and I'm the CEO. I'm going to answer your question on the explanation you need on the changes of agreements with ANH. But I'd like to clarify, there were no changes in the contracts between Ecopetrol and the National Agency of Hydrocarbons. Secondly, this is a legal situation that we've been experiencing for some years. But what did happen is that a decision was made as a result of the change of title on the royalties that instead of being made in things, they were made in money, paid in money. And we incorporated these reserves into the resources of the company on the balance. We're talking about 9 fields that are subject to this application, the scheme. This is validated not only by SEC but other methodologies that audited these reserves. We are talking about 100 fields in which we are working on, but we are looking at 9. And we're going to continue consolidating in our balance the disposition of reserves that we have. These are valid in the methodology and create more stability in the expectations of production that the company has in time. We also have to add in terms of the report or the role played by the incorporation of reserves; we could say that this is the highest in the history of the company and the participation with the appropriation of reserves in the fields in Colombia was big. We're talking about 20%. Logically, when we look at this incorporation, we could say in short that we have consumed in production 248,000 barrels. We've incorporated 200,000 barrels, and this result shows the 121% reposition of reserves.

Ricardo, I'm sorry, thank you for the answer, but also that potential of 100 would then allow to add how many reserves as well. If that's made – please correct how I'm saying this because we're talking about contractual agreements according to what you wrote in the report.

To add more fields is an analysis underway? Yes. But really, the benefit – one of the biggest benefits is to ensure the commercial basket because it's our oil, and we can ensure in 2 ways: one, because we're in charge of the refineries and in the basket. So it really depends on the analysis we make year after year. And as the President said, it also depends on the analysis we make every year depending on the conditions.

Okay, Katherine. Let's talk about the breakeven of profit. It's important to mention that indeed, in 2025, we ended with a breakeven close to $50 per barrel. For 2026, aligned with the goals that we have set out, we estimate that the breakeven will be closer to $46 per barrel. And within that – those $46, there's a tax component of $9 to $10 per barrel.

I have 2 questions and one follow-up here. The first question is related to lifting costs. We have seen a strong Colombian peso recently. So if the FX remains around current levels, what would be a reasonable assumption for lifting costs in 2026? I'm trying to get a sense here if there is room to further reduce it in dollar basis? And the second question is related to the commercialization front. The company reached the best crude differential in 4 years. So how do you see this going forward, especially considering the current developments in the Middle East? And then the follow-up is related to Permian. If you could remind us when exactly does the Delaware contract expire in 2027? Is it also during the midyear or it's earlier or later than that?

I'd like to refer to the effect of the exchange rate on the lifting cost. Indeed, as you mentioned, the exchange has a significant impact on the lifting cost because this metric is expressed in dollars per barrel. So it is evident that in revaluation periods, the exchange rate has a pressure when there is a higher lifting cost. When this trend changes, which we are starting to see, just keeping this trend of devaluation we're seeing, surely, we will see a significant impact that will allow us to foresee and meet our goal to have a lifting cost below $12 per barrel.

Regarding your question on the agreement with Oxy in Delaware, it's in effect until December 31, 2026. Thank you for your question.

Thank you for your question. We have had a successful commercial strategy that has allowed us to report better differentials between the last quarter of 2024 and last quarter of 2025. When it comes to what's happening in the Middle East, part of the answer depends on how long the conflict will last. There are several countries involved, not only Iran, now we have Saudi Arabia and countries close by. There are 15 million barrels that are – that do not – cannot pass through the Hormuz Strait. We see that this will strengthen the company, meaning it will position us to have a lower differential than the demand will be higher for Colombian oil, not only for oil, but refined products as well. Two days ago, what happened, one of the refineries in Arabia, Aramco, which processes 550 barrels per day was attacked. And this, of course, has to do with gasoline and diesel in the Middle East. So when it comes to oil, we see an enhancement, although now it all depends on the durability of this crisis. Arabia reported its inventory for today of 75 million barrels. It will last a week. China already said it closes its exports. So although right now, we do not see it, we do believe that this will help the company.

I have two questions. First, regarding the reserves, we have high hopes for reserves being incorporated in Brazil. However, I would appreciate more details on whether these reserves have been incorporated or not. Additionally, what is the potential for these reserves to be incorporated, and what do we need to make this happen? Could you provide more clarity on this? My second question is about DIAN, the tax authority in Colombia. There is a significant risk since DIAN has the authority to impose fines. In terms of risks, have you been in discussions with rating firms? What feedback have they given you on this matter? Can you also share any insights on the covenants or what borrowers are saying regarding these upcoming issues with DIAN?

Thank you for your questions. Let me share with you that, indeed, that was one of the expectations to incorporate the reserves that we had with the Gato do Mato asset in Brazil. But because of the proceeding of the national agency of oil, which is equivalent to that of hydrocarbons in Colombia, we could not incorporate about 70 million barrels in our balance of reserves of the year before. But it is the initial foundation for this year. I would say in a couple of weeks, we can incorporate those reserves in the significant reserves in our balance.

In response to your question regarding the DIAN, we have made significant progress that we would like to update you on. Concerning the differing interpretations with this authority, we have made several strides. Currently, we can confirm that we have finished the administrative phase and are now moving along the jurisdictional path. We have filed various official payment cases, positioning us particularly well in the administrative contentious courts where the legal processes are expected to unfold according to the stipulated timelines. We emphasize that, given the tax-related nature of this controversy, the law clearly indicates that once such actions are initiated, including precautionary measures like provisional suspension, the coactive charge must be part of the judicial discussion. This is an important element under review. We are confident that the jurisdictional authorities will adequately safeguard the company’s interests in this matter. As for the timelines, we are adhering to the expected schedule. Similar cases typically last between three to six years, indicating that these processes can be lengthy. Regarding our interactions with rating agencies, we have engaged with them thoroughly, providing detailed disclosures. So far, there have been no major concerns raised by these agencies regarding this issue. Specifically addressing your question about covenants, there are none in our financing mechanisms, and we do not perceive an imminent risk. To reiterate, by 2026, we anticipate no liquidity risk or adverse effects from this situation. It is unlikely that this matter will reach a resolution in the short term, so it does not affect Ecopetrol. There is no impact on our accounting provisions, either. Our external legal advisors have assessed the risk of losing this dispute as very low, with a high likelihood of success, and any resulting impact on our balance sheet is expected to be minimal, if not negligible.

I'd like to ask about the gap between the real production of oil and the goal that was established for the year. And you mentioned several factors like the climate and blockades. Could you please elaborate more on those settings? And if you overcame some of these reasons for lower production and which were the fields affected? And the maintenance aspect last year, you said that this reduced the supply of natural gas in some refineries of Ecopetrol. If there is a similar scenario in 2026, do you have a contingency plan different from that could help you with the natural gas problem? Or are we still exposed to a similar scenario?

When it comes to the gap that you were asking about, I can say that when it comes to the settings this year, especially in the last 1.5 months, we had events that did hit our production levels. And because of the rainy season, we still have factors related to weather, not only the stability because of thunderstorms, but we also had the slide of an electric tower, and that stopped us from operating a station from working with the field, and this also affected and restricted partially the production of those fields. This has been restored now, of course, but that did have an impact. So when it comes to Rubiales, Caño Sur, Castilla, Chichimene and Casix, those are the fields.

When it comes to the natural gas question, we always carry out the overhaul, the maintenance. And what differs from last year is that the import project from Buenaventura is already in operation. So it gives more capability and resilience to the transport of the natural gas system in Colombia. So now we see the coordination of all the agents, so that in October, we can surpass this event.

I have two questions. The first is about Venezuela. What opportunities do you see there? What types of opportunities do you anticipate with the investments you have approved or those planned for the future, specifically regarding the possibility of selling electricity to Venezuela? My second question follows up on your previous explanation regarding the reserves and the ANH. You paid royalties in cash for some fields, correct? To me, this suggests that the production from those reserves, which currently represent about 5% of the total, will likely result in decreased profit per barrel for those specific barrels since it feels like you're covering the lifting cost twice—once through the royalty and again through the lifting cost of those barrels. Could you please clarify if my understanding is correct?

Allow me to talk about the opportunities we've identified and the chances to make transactions of energy with Venezuela. First, Venezuela needs electricity to reactivate its economy and the exploitation of hydrocarbons in higher volumes than those that we've seen recently. And we need gas for the past 10 years, we've needed. So we can exchange resources of products or light crude oil, which we see a lot in Venezuela. And after identifying these opportunities, we have talked with OPAC last week to give – to make an assessment and to make transactions of this nature with Venezuela. When it comes to the amount of energy that we could sell to Venezuela, or yes, electricity or to improve the concept of self-generation to sell energy to Venezuela. Remember, the transactions are not – of this type are not physical, they're financial. We have to go through the wholesale market, and these contracts are financial. And today, Ecopetrol cannot do this because when it purchased ISA, it was forced to do so. But ISA can do it. It has no restrictions to commercialize energy with Venezuela. The core of the business of ISA is to develop these interconnections for years, and it's done so with Venezuela before. So there's an opportunity there. So today, the regulation allows us to have projects and to record that energy for our consumption. That's a premise that we can do today. So the energy that Venezuela needs and Colombia having good sources based on hydroelectricity, I would say that we can enable those connections without any problem to Venezuela provided the restrictions are raised. And from there, we can carry out the transactions, energy transactions with that country.

So you mean Ecopetrol generates it according to your new strategic plan? Yes. But it would be for the system and the system with any surplus, part of that surplus would be sold to Venezuela, right?

Yes. Any generator in the country can place the energy in the system. And with the transactions held according to the boundaries and the agreements with boundaries made, we've been doing transactions for many years. We have generation in the system. We have what's called the boundary or frontier systems. And according to what's agreed with those frontier systems, any generator, any self-generator can place a surplus in that system, and the energy is taken from other buyers.

On your question related to the treatment, the accounting treatment and financial treatment given to the royalties. The most important part here is to repeat that the monetization of the royalties is that today, the volumes are no longer of the ANH but become volumes of barrels owned by Ecopetrol. This isn't a big cost for Ecopetrol, but there is a reconversion or reclassification of the cost. Before, what we did was to provide the barrel to the ANH and the ANH would give it back to us to commercialize it. So then we would register a sales cost, a higher sales cost over those volumes of royalties. However, today, since it's owned by Ecopetrol, the sales cost to purchase those barrels is transferred to the operating cost, as you stated. And as so, this increases the total cost of the lifting cost, yes. But we have to keep in mind, when you produce more barrels, which are incorporated in the production of Ecopetrol, the unit cost per barrel drops. So what we can say is that the effect is neutral – and it's more a reclassification of the sales cost and the operating cost with the effect, yes, that when you divide the total cost – lifting cost by a higher number of barrels, you can record a lower lifting cost per barrel.

Yes, Camilo. So when you look at these fields, when it comes to royalties, those barrels and those fields are not being commercialized by ANH, but with the mechanism that you've explained through Ecopetrol, right?

Until before this monetization of royalties, that's how we did it, yes. ANH would give it to us to be commercialized by Ecopetrol with the risk that any other commercializer could do it. But today, since it's owned by Ecopetrol, we eliminated that risk. We ensured the crude slate and 100%, and we are commercializing those barrels.

I'd like to make 2 questions. One, what's happening in Iran today and the impact it has on the higher crude oil prices and on the margins, do you see any changes on your strategy for this effect because it will hurt surely the profitability levels? And second question, during this quarter, we see in the midstream volumes transported compared to the last quarter of last year, but we see a decrease in revenue. Since these are tariffs regulated, could you give us more details of this negative variation?

When it comes to the Iranian conflict, there are impacts on the 15 million barrels, of course, that cannot pass the Hormuz Strait. And that, of course, will increase the price of oil. When it comes to refined products, as of today, the report says is that in the Middle East and Iran and Arabia, you can see a shortage of diesel because when it comes to loading, so for these enhancements in the past 48 hours. Also in naphtha, we see a cut in exports. Remember, there are countries like Qatar, Dubai, Iran, Saudi Arabia, Iraq and others that exported last year, 1.2 million barrels in naphtha. And that naphtha went to countries in the East. And most likely, that naphtha now will have to go from the U.S. and rebalance all the market. The gasoline market right now does not export a lot of gasoline and jet. We see also a cut in exports. So to conclude, we can foresee that if this war is extended, there was a spike in prices. But we have to keep in mind the following. The freights are at astronomical prices, 150%, 160% higher. So we can have a better price that will be mitigated by transport cost of those oils or products, and we have to see the impact on this. But if the situation continues like this, surely, it can be a good time for the downstream in many parts of the world. Regarding your question, as you can see in the report, the increase or higher volume transported was of oil. And you have to remember that the transport rates are in dollars. Therefore, because of the exchange rate, there was a reduction in revenue. The total reduction is COP 512 billion, of which a good percentage is because of the lower exchange rate. In addition, there is COP 131 million owed because when you compare the semester of '24 to '25, there was a chip boy for the transport, which in '25 is not there. Still, I'd like to highlight that of the COP 512 million through efficiencies, we reduced the impact to COP 179 million. So in the report, you can see there is an improvement of the EBITDA margin to 61%.

This is Bayron Triana. Regarding the questions on the impacts of importing gas in Colombia, I'd like to highlight that import is made by a company that's not Ecopetrol. The duration – we have to see the impacts that will take place in this company. But we can say that in the spot, when it comes to purchases of Ecopetrol for the infrastructure of the Pacific and the Caribbean, the contracts are all long term to mitigate the effects of what's taking place now. When it comes to the development of the Coveñas plant, this plant has all the permits now, the environmental permits. We are working now with the carrier. The initial phase of 110 million cubic feet was canceled, and we have a phase of 400 million cubic feet, and we expect that by the end of 2028, it will be in operation.

I am Julián Lemos, the Corporate VP of Strategy and New Businesses. Today, we have an agreement in force with Occidental. As I mentioned in another question, one of the contracts is in force until December 31, 2027, and as Juan Carlos said before, the level of activity and therefore of investments made the analysis of what's happening macroeconomically in the market. And to that way, we can agree with our partner how we can develop that basin. Since these processes usually are covered by confidentiality agreements, we cannot state anything on this. But again, as I've said before, Ecopetrol constantly evaluates inorganic growth opportunities to incorporate reserves, and these will be announced to the market.

With regard to the operations to handle debt or to financing in Ecopetrol, we'd like to take this opportunity to indicate several aspects. First, Ecopetrol, we monitor constantly the market, the banking financial markets and that of capitals. And we evaluate carefully the different windows and performances. Right now, we have several purposes in terms of handling debt. And the goal is to decrease the cost of that financing. And secondly, to reduce or mitigate the refinancing risks. So consequently, we evaluate all the possibilities. And it's important to clarify that right now, we do not have any refinancing risks associated. Our next major maturities are closer to the end of the year of 2029. And our average mean life is over 8 years. So with this said, we will be carefully evaluating all the possibilities and the performance of the market. Initially, we do not see any windows. But as they open, we are going to be prepared to look at them closer.

Alfredo, thank you for your question. This is Julián Lemos. This is a competitive process. As I said before, covered by a confidentiality agreement. So we cannot tell you the likelihood. But we can say that when Ecopetrol analyzes and will conclude that these operations are proper and gets the approvals, this will be shared with the market.

The consortium will invest about $1.2 billion in the exploration phase and $2.9 million more for production development. This major CapEx investment will have different financing schemes. Of course, these are being evaluated according to the best practices to finance these types of projects. Especially we are emphasizing the possibility to develop structures of balance for this particular project. With regard to the question of what happens with the commercial part of gas by 2030, this has been financed with flexibility for the seller provided the project is in operation. So when the project is in operation, the contracts are firm and become mandatory for us beforehand; there is no obligation to deliver the gas. Still, Ecopetrol has projects until Sirius is in operation to import gas back that level of gas needed.

Thank you all for attending this earnings call. We appreciate your questions, which have allowed us to clarify the aspects that you were wondering about regarding the results of the last quarter of 2025. We'd like to say finally that there is absolutely no aspect or parameter that has not been protected duly by the hundreds and thousands of employees of Ecopetrol. They have devoted their intellect and their smartness. So for all of our shareholders and creditors, we have sound robust results that allow us to continue showing you that we have a great company in Colombia that does create value for shareholders and for the country. Thank you all.

Thank you all. This concludes our earnings call for the fourth quarter of 2025. Thank you for attending. You can disconnect now.