Ecopetrol SA (EC) 0 Q0 法說會逐字稿

Good morning. My name is Hilda, and I'll be your operator today. Welcome to Ecopetrol's Group Second Investor Day. Today, we will discuss the financial and operational results for the second quarter of 2020 and the 2020 and 2022 business plan update.

(Operator Instructions) Before we begin, it is important to mention that the comments in this call by Ecopetrol 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 in this conference call.

The call will be led by Mr. Felipe Bayon, CEO of Ecopetrol; Alberto Consuegra, COO; and Jaime Caballero, CFO.

Thank you for your attention. Mr. Bayon, you may begin your conference.

Good morning, everyone, and thank you for joining us during these second Ecopetrol's investor days in 2020, where we will discuss operating and financial results for the second quarter of the year and the 2020-2022 business plan update. On behalf of Ecopetrol, we hope you and your families are keeping safe during this very difficult time. We reiterate our gratitude for your participation in this conference call and your permanent support in other events hosted by the company, especially under the current circumstances.

First of all, I would like to highlight that the life and well-being of our employees remain as our main priority to cope with the current challenges caused by this pandemic. Currently, about 80% of our employees continue to work remotely, thanks to our digital transformation. In order to ensure the well-being of our employees and their families, we have decided to maintain the remote working scheme for the rest of 2020 for those employees whose tasks allow it.

For 2021, we will continue to assess a progressive and safe return of these employees to the workplace. Since March, as part of our contingency plans, we adjusted our operations by reducing our drilling and projects work fronts in Colombia from some 300 during the first quarter of the year to 50 work fronts in April. By the end of June, thanks to the progressive increasing activity levels, some 200 work fronts were active. Activity will continue to increase as we confirm favorably and safe conditions to operate.

As part of our commitment with the communities where we operate, we have already announced COP 88 billion in social investments through our social investment program named Apoyo País with COVID-19 emergency. This program is mainly focused on the delivery of food kits, biosafety elements, medical equipment; strengthening the health system in the country; support to technological initiatives; and solidarity with those families that most need it in 21 departments where we operate. This has been possible thanks to strategic alliances with different entities.

Please, let's move on to the next slide to discuss market conditions. In line with the guidance we provided on our previous earnings conference call, the second quarter has been, at this time, the most challenging period of the current crisis with a reduction of 38% in Brent prices as compared to 2019 year-end. In April, prices reached their lowest level, decreasing 71%. Local demand of our main products such as gasoline, diesel and jet fuel had a steep drop mainly during April and May.

Since the month of June, we have seen a gradual recovery related to the easing of lockdown restrictions. The crude oil basket reported a significant decline during the first semester, reaching $29.8 per barrel compared to $59.8 per barrel in the same period of 2019. Despite the unprecedented contraction in demand, our commercial strategy successfully positioned our crudes in the market, and we were able to protect all the production that was profitable.

Let's move on to the next slide for a summary of our second quarter results. Despite the gradual improvement in oil prices and local demand for products since mid-May, our operating and financial results were strongly impacted, in line with the negative performance of the global economy and the industry. During the second quarter, Ecopetrol Group's production was 677,000 barrels of oil equivalent per day, in the high end of the range announced in the first quarter. This lower production, combined with the negative impact of oil prices, resulted in a 54% decrease in revenues, in comparison to the same quarter of 2019. Despite the exceptional environmental conditions, the Ecopetrol Group reached an EBITDA of COP 2 trillion and a net income of COP 25 billion during this quarter.

I now give the floor to Alberto Consuegra, who will provide further details of our operational results for the semester.

Thanks, Felipe.

On exploration, we completed the drilling of 7 wells during the first half of the year, highlighting the successful completion of the Gato do Mato-4 well. Hocol announced the discovery of gas in the Merecumbé-1 well in the Colombian department of Atlantic in July. Additionally, I would like to mention the official approval granted on June 12 by the Brazilian ministry of mines and the national petroleum agency to Ecopetrol's 30% interest in the Gato do Mato discovery.

On production, despite volatility in the price of crude and the impact of the pandemic and public order events, we reached 706,000 barrels of oil equivalent per day during the first half of the year. Drilling campaigns were impacted so that we completed 148 wells during the first half of the year, in contrast to the 311 drilled and completed in the first semester 2019. The key milestones were the closing of the acquisition by Hocol of 43% of the offshore gas assets in La Guajira, the entry into production of 18 wells in May in the Permian Basin as well as the upturn of 11,000 barrels of oil equivalent per day in June that were closed due to sustainability criteria in our Colombian fields. Our current production remains profitable at less than $30 per barrel.

Gas remains as a strategic pillar in our energy transition strategy as well as in our production portfolio. During the quarter, we provided financial reliefs to end users in the amount of COP 168 billion. Additionally, we rapidly reacted to lower demand and the country's energy requirements in order to supply the thermal power sector. With regards to the midstream segment, the transport of crude and refined products decreased, reflecting the effect of lower local production. Midstream companies offered commercial reliefs such as discounts and financing of the transport tariffs up to 6 months. And in certain cases, [in volume] requirements on the ship-or-pay contracts were made more flexible.

In the downstream segment, results were affected by the contraction of both domestic and international demand for their main products. Our refineries have been adapting their operational schemes, implementing measures such as adjustments in throughputs and maintenance rescheduling in order to guarantee the integrity and reliability of our operations. Our refineries reached a joint throughput of 255,000 barrels per day during the first quarter and 300,000 barrels per day during the first half of the year, with a growing trend since April's operating minimums. Gross refining margin reached $6.2 per barrel during the quarter. However, we have seen a gradual recovery in demand and margins since mid-May.

On petrochemicals side, Esenttia continues to deliver excellent financial and operational performance. In addition, due to the partnership with companies both from the group and the national plastics industry, it has led initiatives to provide protective equipment during the pandemic. These results were feasible, thanks to a proactive commercial strategy that enabled production above the minimum operating [vital] of our refineries through agreements with new clients and anticipated sales of crude and product surpluses within international markets.

Let's continue to the next slide to discuss our progress in terms of efficiencies. We have reacted appropriately to reduce costs and expenses to confront this new environment through the capture of significant savings and activity deferrals. The results of these measures were reflected during the second quarter, with May and June the months with the highest efficiencies. Lifting cost was $7.1 per barrel during the first half of the year with efforts focused on tariff renegotiation, infrastructure optimization, energy matrix and exchange rate impacts.

The cost per transported barrel was $3 during the first half of the year, slightly lower when compared to the same period of 2019 mainly due to the optimization of contracts, prioritization of activities and exchange rate effect. The average purchase tariff of nonregulated energy portfolio was 29% below market price as a result of the incorporation of bilateral contracts and self-generation optimization during the first half of the year.

I now give the floor to Jaime Caballero, who will share the group's main financial results.

Thanks, Alberto.

EBITDA margin stood at 31% mainly due to the price juncture and the effects of declining demand. EBITDA per barrel was $15.3; and was adversely affected by a decrease in sale volumes, partially offset by lower prices and purchase volumes. Despite a challenging market and operating conditions, production only decreased 3%, as compared to the first half of 2019. The cash breakeven dropped to $19.9 per barrel, taking into account financing raised during the semester, which increased gross debt-to-EBITDA ratio to 2.4x. CapEx remained steady, as compared to the first half of 2019. 68% of investments were allocated to growth projects within the E&P segment.

During the first half of 2020, net income decreased versus 2019 mainly due to, firstly, a negative impact of COP 5.95 trillion from the effect of lower prices; and secondly, a negative variation of COP 3 trillion primarily driven by inventory fluctuations and higher operational expenses that were partially offset by lower costs as a result of austerity measures implemented and the rephasing of activities due to diminished operational levels. Financial expenses increased COP 490 billion due to the increase in debt levels and peso devaluation. Tax provisions in 2020 were COP 3.1 trillion less than in 2019 prior to nonrecurring events. Income before impairments and nonrecurring events reached COP 80 billion.

Nonrecurring events for the first half of 2020 represented a positive effect of COP 1 trillion. It is important to highlight the income from business combination arising from the acquisition of offshore assets in La Guajira, partially offset by the voluntary retirement plan that was initially accepted by 122 employees and the contributions to support the communities during the pandemic. Net income for the first half of 2020, after the impairment of long-term assets recognized during the first quarter, amounted to COP 158 billion.

I will hand over now to Felipe Bayon who will present the business plan update.

Thank you, Jaime.

We managed to promptly reassess the business plan that was initially announced to the market in February seeking to respond to the new market conditions and the impacts of the COVID-19 global pandemic. We have strengthened our strict capital discipline, cash protection and cost efficiency pillars with new criteria for portfolio opportunities valuation focused on profitable projects, OpEx optimization initiatives throughout the company and disciplined debt management. We maintained our strategic commitments to protect our production and reserves, such as all the exploratory activities, increased production with the existing fields, development of the Comprehensive Research Pilot Projects for Unconventional Reservoirs in Colombia and the international investments that are strategic to the group. We reaffirm our commitment to make progress to the energy transition, growing our share in terms of gas, increasing renewable energy in our energy matrix, supported by fundamental enablers such as social and environmental investments as well as technology.

Let's now move on to the next slide to deepen on each of the segments.

The upstream remains as a key pillar of the Ecopetrol Group. In exploration, we plan to drill more than 30 wells within high-materiality basins mainly in Colombia. Likewise, we will continue the assessment and development of the offshore gas discoveries in the Colombian Caribbean, with investments that we estimate in some $180 million between 2020 and 2022. In production, we will leverage the production increase in existing fields through enhanced recovery projects. We will also continue focus on building a portfolio that allow us to preserve our reserves, prioritizing our position in strategic assets. 78% of the investments will be allocated to Colombia; and the remaining 22% to the positioning and development of our international operations, mainly in Brazil and the U.S.

Let's move on to the next slide. It is a priority to continue leveraging the future growth of reserves within the Ecopetrol Group. To do so, we have maintained our investments in order to build a strategic portfolio with significant contributions towards ensuring production and reserves. Among our main projects, I want to highlight the development of the Piedemonte gas trend, drilling activities in Rubiales and in the Caño Sur fields in Colombia and the development of the Gato do Mato discovery in Brazil and the Permian in the U.S.

Our enhanced recovery programs remains an essential source to increase reserves and production, supporting a large part of our growth and value generation strategy. I would like to mention water injection projects in the middle Magdalena Valley and the fields in the Orinoquia.

Let's now move on to the next slide. In gas, we maintain our investment commitment on some $780 million with a potential upside of $870 million. That will enable us to grow through new demand, participate in new segments and be part of the full energy chain integration. Leveraged on the competitiveness of our prices, we seek to maximize our efficiency and diversify and accelerate the time to market of gas and LPG. We'll focus our efforts on the development of offshore gas discoveries in the Caribbean, the development of the Piedemonte gas trend and other onshore gas sources mainly in the middle Magdalena Valley and the Sinú-San Jacinto basin.

Let's move on to the next slide. We will continue to mature our short-cycle assets. Regarding the development of the comprehensive research pilot projects, proyectos piloto de investigación integral in Spanish, the Ministry of Mines and Energy published the corresponding technical regulation on July 7. And in the coming months, we expect the government to issue the environmental, civil and contractual regulations that will complete the regulatory framework and allow us to move forward with all the planning activities. We'll invest around $127 million and continue on the definition of the preliminary agreement we announced with Exxon recently in order to work jointly on those pilots in the middle Magdalena Valley.

Regarding our activities in the Permian Basin in Texas and as a result of the recovery of prices, along with our partner Oxy, we have decided to increase operations during the second half of 2020 and start drilling an additional 22 wells. These 22 new wells will add up to the 22 wells already producing which were completed earlier in the year. The new 22 wells will start production in the first quarter of 2021. We estimate that average net production for Ecopetrol will reach 5,500 barrels of oil equivalent per day by the end of 2020, higher than the 4,000 to 5,000 barrels of oil per day announced in the first quarter of the year.

Let's move on to the next slide. With regards to the midstream segment, our efforts will be focused on -- in ensuring the integrity and reliability of our infrastructure while simultaneously guaranteeing logistical flexibility and efficiency in the transport of heavy crudes. To this end, we'll invest some $780 million to $830 million in maintenance, geotechnics, tank integrity and operational storage of refined products. We expect that the transported volumes will remain stable during the next 3 years in a range of 1.0 million to 1.025 million barrels per day, in line with the country's production forecast.

Let's move on to the next slide. In the downstream segment, we will allocate between $1.2 billion and $1.3 billion in order to secure the reliability and sustainability of our operations while generating greater value for the segment. The total refining throughput will be in the range of 300,000 to 380,000 barrels per day. As for growth opportunities, we have maintained in our plan the investment to interconnect the original crude unit in Cartagena to Reficar. We have now postponed first operation and first production to 2022 due to the new operation of protocols implemented as a result of the pandemic. We are committed to deliver ever-cleaner fuels to the country, prioritizing a plan that maintains diesel quality at low levels of between 10 to 15 parts per million of sulfur and a maximum of 50 parts per million of sulfur for gasoline by 2021.

Let's move on to the next slide to discuss more details on the investment plan. Organic investments for the planned period will be in the range between $11 billion and $13 billion, out of which $3 billion to $3.4 billion will be executed in the current year, 2020. Most of the investment will go to the E&P segment. 80% of the investment will be in Colombia, and 20% mainly in Brazil and the U.S.

Let's now move on to the next slide to discuss the cash situation. We will concentrate on generating and growing operational revenues, adding to more than $11 billion by 2022. Some $4.5 billion of incremental debt are also incorporated into the plan. This already includes the successful financing achieved in 2020. Gross debt-to-EBITDA ratio for 2020 will be close to 3.5x and will have a downward trend to 2.5x in 2022.

Let's now move on to the next slide. During 2020, we have captured more than COP 3.5 trillion in savings due to growing synergies among the segments as well as austerity and efficiency measures in each of our activities. Over the next 3 years, we will pursue some additional savings between COP 2.5 trillion and COP 3 trillion. Our main challenge will be the total unit cost, where our focus will be on its stability and even its reduction. To this end, we have formulated aggressive strategies to maximize the value of our existing assets, ensuring safe, reliable and efficient operations.

Let's move on to the next slide to discuss our main targets on TESG. Our commitment to technology, the environment, social and governance, TESG, remains resolute; and we are working mainly around 4 aspects. In the environmental front, our main goal is to achieve a 20% reduction in greenhouse gas emissions by 2030, emphasizing in the capture and reduction of CO2, increasing energy efficiency and growing our capacity in renewable energy power generation. We will continue working to reduce routine flaring and fugitive emissions and venting.

In the social front, around COP 1.7 trillion will be allocated by 2024 in social and environmental investments focused mainly in closing the social gaps and promoting the development and well-being of the communities in those areas where we operate. The projects in these areas are mainly around infrastructure; public services; education, sports and health care; and the encouragement of rural development, entrepreneurship and business development.

In terms of governance, we remain determined to improve our information disclosure standards by prioritizing relevant company matters such as the reentry to the DJSI or Dow Jones Sustainability Index and fulfilling the projects defined by the carbon disclosure project. To boost our digital transformation, we will allocate nearly $158 million towards capturing [on] expected returns related mainly to artificial intelligence, blockchain and bots, amongst others.

Let's now move on to the next slide to see the plan targets. In addition to the objectives mentioned throughout the presentation, I would like to highlight on the financial front a cash breakeven below $30 per barrel in 2020 and less than $40 per barrel by 2022. The reserve-replacement targets are under evaluation and will be subject mainly to the evolution of the plan execution and the market conditions. On the other hand, aligned with our commitment to maintain a low-carbon operation, we estimate a reduction of some 1.8 million to 2 million tonnes of CO2 by 2022, according to the target set in the prior plan.

Let's move on to the next slide for our final remarks.

During the first half of the year, as the rest of the companies worldwide, we have faced tough market conditions that have required swift and timely decisions. We implemented a package of measures focused on optimizing our investment plan and reducing costs and expenses, seeking a rapid adjustments to new market conditions while ensuring the long-term value and sustainability of the country. We updated our main operational, financial and TESG metrics for our 2020-2022 business plan, which protects the main pillars of our corporate strategy, guaranteeing group sustainability and ratifying our commitment to the energy transition.

Thank you again for joining us in this second Investor Day of the year. We fully appreciate your continued interest and support in the company despite the very difficult current circumstances.

Now I would like to open the floor to Q&As.

(Operator Instructions) We have a question from Frank McGann from Bank of America.

I was wondering if perhaps you could provide just a little bit more detail on the cash breakeven that you mentioned. What drives the increase from the below $30 this year to the higher range that you're using for the plan? Secondly, in terms of natural gas, how big do you see that getting in terms of as a portion of production over the plan period and perhaps longer term? What do you see as the possible upside there and as a percentage of EBITDA? And then third, just on renewables, what -- clearly that has been -- it's becoming a bigger focus. How much upside is there beyond what you have in the current plan, if you wanted to become more aggressive in renewable investments?

Thanks, Frank. Thanks for being here. I'll start with the last one, on renewables. And then I'll ask Jaime to talk about the cash breakeven and Alberto to talk about the natural gas. So in terms of renewables, what we've said, Frank, is that we want to be in a place, by 2022, where we have 300 megawatts of power generation capacity that will be used for our own operations. So right now, we have 21 megawatts of our first solar plant. It's been working since October of last year. And both on the sides of reducing emissions, we're very pleased with that but also in terms of the economics of the plant. And eventually the savings could be at around $1 million per year. So from that point of view, we're very happy with our first entry, if you will, into using renewables. And as people ask me, "So you're using solar energy to produce oil and gas," and the answer is absolutely yes. We can combine both things and things can actually coexist.

We're currently in the midst of looking at a second project, which would be around 50 megawatts, and you should be hearing from that soon. And we're very enthused with that because, if that comes through, it would be the largest solar park for self-generating power in Colombia. And then we already have a lot of projects in the pipeline, both solar and wind. So that's roughly where we are. It's important for us. As I was saying, it's not only important for the environmental side of things and reduction in emissions but also for cost savings. And clearly, where we are and with prices where we are, it's good to have sources of efficiency as well from energy as such. So Jaime, why don't you go ahead and take the breakeven one? And then Alberto. Thanks, Frank.

Thanks for your question. So with regards to cash breakeven. So firstly, I'd start with kind of a couple of brief definitions. The cash breakeven that we referred to both in the KPIs and in the kind of the plan metrics are we refer to the all-in price that we need in order to sustain our minimum level of cash. And what I mean by minimum level of cash is according to our analysis of our treasury position and the liquidity that we need, how do we sustain a level that gives us confidence [that we can] respond to volatility and unexpected conditions? That level currently is somewhere around $800 million at a group level, right. So that's kind of the baseline that we set ourselves that we don't want to go beneath. The other component of this is that, typically when we refer to this or certainly when we refer to it in the plan targets, we refer to it as an annual target. So we expect to be under $30 in 2020. And we expect to be in the range of $30 to $40 throughout the plan duration...

(technical difficulty)

Jaime? I think we may have lost Jaime. Alberto, why don't you take the question on natural gas? And we'll allow Jaime to come back.

Again going back to definitions (inaudible) 30s (inaudible) we see (inaudible) over -- yes? Sorry. Hello...

Lost you for a minute.

Okay. You lost me there. So I don't know exactly where (inaudible), but [I was] explaining that we have growth in that metric from 2020 to the next years in the plan basically because we have incremental CapEx over the next couple of years. So CapEx is going to grow in '21 and '22. That has an effect on the metric. We also have debt payments through that period. And the relative impact that the initial cash position and the financing flow has on the metric is reduced in '21 and '22. So basically those are the components of the cash breakeven evolution.

Frank, with regards to gas. Gas is indeed absolutely strategic in our agenda. We see gas as the hydrocarbon for energy transition, and right now in our plan 2020 to '22, gas will represent about 17% of the production share. We'll see a slight increase in terms of volume production 2020, about 120 MBDs equivalent and going to 135 in 2022, but when you see our strategy, we want gas to represent about 30% to 35%. So we will be investing a lot in terms of exploration in order to ensure that volumes will begin to increase at the pace expected in the period 2024 to 2030. So gas in terms of EBITDA, when you compare to our numbers in 2019, it represents about 11% of the upstream EBITDA, but when you look at the period of April to June this year, it represented about 53% of the EBITDA. So EBITDA will basically be dependent on oil price behavior, but in the long term we are seeing that gas could be representing a very high portion of our upstream EBITDA.

Our next question comes from Barbara Halberstadt from JPMorgan.

So I have like 2 questions. In your presentation, the indication for operating cash flow and considering what's the CapEx plan, it suggests that we might see negative free cash flow for the next years. So I just wanted to confirm that and if you could provide additional color from that perspective. And also, on the second point, on working capital, by this quarter, you had a buildup in inventory. So just wanted to confirm if we could expect a reversion for year -- end of the year.

All right, thanks for the questions. Thanks for being here. I'll ask Jaime to take the questions, both your questions. Jaime, please go ahead.

Thank you, Barbara. Thanks for the question. With regards to the first question, around cash flow. So there are 2 components of that. I -- the first thing that I would say is kind of where are we here, midyear, right? And what we've seen is positive operating cash flow from the business over the first half of the year, but indeed we have seen negative free cash flow. That's going beyond the operational cash flow and including the CapEx outflows. That's been basically an outcome associated to the market conditions that we had on particularly during the second quarter and also the delayed effect of the cost optimization measures that we have been taking. By that, I mean that, yes, as you know, we enacted an intervention plan by the end of March and early April. And the results, the full results, of that are actually weighted towards the second half of the year.

The outlook that we see for the second half of the year is one where the operating cash flow and free cash flow is actually positive both in 3Q and in 4Q. And for 2021 and 2022, we will continue with that trend. We will continue with that trend. Obviously this is highly linked to the market conditions that we have. As you know, we have some price assumptions in this plan going from $38 average this year to $45 next year and $50 the year after that. And of course, it's also linked to the success that we have with our cost optimization measures that we have announced. That's the overall picture with regards to cash.

With regards to -- your second question was around inventories, right? And basically let me set that baseline. We did have some movement in inventory around in the second quarter. The context for this is that, in late 1Q, we did make a significant provision around inventory devaluation associated to the drop in prices that we were seeing. So basically, from an accounting standpoint, we basically were recognizing in our financial statements that the value of that inventory would likely fall over time, over the period, right? What we've seen is that with the uptick in prices we have recovered a significant amount of that. We still have about COP 120 billion in an accounting provision associated to that and we expect to recovered -- to recover a significant amount. I would say at this stage possibly somewhere between COP 70 billion to COP 90 billion of that COP 120 billion should be recovered over the next 6 months. I hope this answers your questions. Thank you, Barbara.

The next question comes from Ricardo Rezende from JPMorgan.

So a couple of questions on my side. First one is on lifting costs, all right? If we look at the numbers that you guys reported on the second quarter, they were very, very much lower than what you were running before at around $6 per barrel. So is that a normalized level going forward? Should we expect some kind of normalization from those $6 per barrel?

And then the second question would be on the realized prices. I know that we are still only a month on the third quarter, but if you could give us some color on how you're selling, marketing your crude; if we should see a discount narrowing on the third quarter and the fourth quarter compared to what you had in the second quarter, that would be great.

Ricardo, thanks. And I'll ask Alberto to take the first one and give us his view on forward trends and how do we see lifting costs moving on. And in terms of the second question, I'll ask Pedro to provide a bit more color, but I'd like to give you the sense that we are seeing -- coupled with the increase in the Brent as such, we have, as you were mentioning, a strengthening of the differentials. And they're actually looking better even though we're only beginning the -- or in the mid of 3Q as such. So Alberto, why don't you take the first one? And then Pedro, you take the second one. Thanks, Ricardo.

Ricardo, thanks for the question. Our estimate is that lifting costs will be around $7 per barrel at year-end. Indeed, we were able to lower lifting down to $6 given that we faced a substantial reduction in activity because of the combined effects of both the pandemic and the oil price. We had to reduce operations to minimum vital, suspended and postponed well work activities as well as surface maintenance works, closed production, optimized energy costs and contracting services.

Going forward, lifting costs should increase given that we will have to bring production back, reinitiate well work, also facilities maintenance works, but given the level of interventions, optimizations that we are doing in several fronts like energy tariffs, optimization of contract services, especially well work, water treatment and -- what we should -- and we are -- we should see the benefit of the implementation of our digital projects. All in all, we should see a lifting cost in the range of $7 to $9 during the period, hoping to be closer to the lower end of the range.

Thank you, Alberto. Ricardo, thank you for your question. Let me take the one on the marketing of the crudes and the realized price for the -- for this quarter. Our commercial strategy has been very successful at anticipating sales and focusing on our long-term customers and market diversification. That's what is -- we've been doing now for a while. And that really worked during the second quarter, when we have the crisis in demand prices. And but as opposed to the second quarter, we basically focus on placing every barrel in the market.

On the third quarter, what we saw is that demand was picking up and there was a lot of appetite for our crudes. And we have already -- because we're anticipating sales, we have already placed all our programs throughout the quarter. And that looks pretty strong. And that's basically in these lower single digits on average. However, on the fourth quarter, this week, we're already offering and we're seeing that the demand is weakening a little bit, so we are expecting that the fourth quarter might be somewhere in between what we already saw in the third quarter and the second quarter. And that's basically what we're seeing in the market. Thank you.

Our next question comes from Lilyanna Yang from HSBC.

Could you talk a little bit about your CapEx plan? If you had to prioritize or rank the projects or if you had, let's say, $6 billion as opposed to $12 billion for the period 2020 through 2022, what will be the one that comes first as priority, right? And if you can give us an idea of, for instance, how much is maintenance CapEx as well to keep production -- or to deliver the production target that you have for the near term. This is it.

Lily, thanks. Is that your only question with respect...

No. Actually I have a lot, but let me put that all together. Also the other one is on Brazil deepwater, right? You have the first exploratory well with Saturno, right? And it came out dry, as per the [local press and the industry]. So what are the next steps there for Saturno area, right? And if you can give us an idea of how much was the cost of the well or how much you actually paid for the 10% of the block. And what would you need to see before you would consider to write off such investment? That's one also on Brazil, right?

And on the same line, if you can give us an update on the bid process for the FPSO for Gato do Mato with Shell, where you have a 30% stake. And another one, which is part of the bigger one, if you can give us a color about the JV with Oxy, if you can tell us about the breakeven for these Permian barrels. And what have you been able to learn thus far with the joint venture that you think could be used in Colombia on your pilot projects for the unconventionals? That will be one set of questions.

Thanks, Lily. Thanks for being here. Thanks for participating. So I'll provide some context around the first one, on the CapEx. And first thing is that we -- what we actually did when we -- with recasting the business plan for 2020-2022 is precisely do a detailed prioritization of opportunities. So should there be more space going forward and should there be additional inflow into the company in terms of revenues, we'll have the optionality to look at is it going to be investment in CapEx. Is -- are we going to do something else with the debt? So we have the flexibility from that point of view, but we've been very disciplined in terms of how we deploy the capital and how we actually execute the capital. And we have the ability to react very, very quickly.

And I'd like Alberto probably to expand a bit on this in a second. And we were -- as Alberto was mentioning, we have prioritized exploration. We want to keep on exploring gas. It's a very big part of what we do; EOR, enhanced oil recovery; near field so we can -- we've been very successful with near field in the past few years or so. So we want to do that. And as you rightly point out, we have a presence both in the U.S. and Brazil. And I'll talk about Brazil a bit and I'll talk about the Oxy deal; and then I'll go back to Alberto for the CapEx, exploratory CapEx.

In terms of Brazil, 2 things. And you've talked about Gato do Mato and you've talked about Saturno. So in terms of Saturno, the well from an operations point of view, extremely successful, very pleased with the performance in terms of the time and everything else; and has provided very significant information around the potential of the area. And you would know this, but the area in which we are exploring is the size of Rio de Janeiro. So it's a very big area where we see a lot of potential. So we will continue the assessment with our partners. We will continue to work with them and jointly decide best path forward and what do we do to uncap and assess the potential for the blocks.

In terms of Gato do Mato, the FPSO, very, very pleased with having 4 wells down, 4 wells that have been successful; the Brazilian authorities formally now granting the entry of Ecopetrol into the joint venture, very, very pleased with that. And I can say that, based on the results, we're looking at around the first quarter of 2021 going out to tender for the FPSO. So we're looking at all the technical data. We've -- obviously the operator has been working with the markets and providers and everything else, but we're -- in that sense, we're already making some good progress, so we're very, very comfortable with that.

In terms of the Oxy deal. And being these short-cycled activities, we were very quick in terms of starting operations last year. It was only a year ago, July 31, that we announced the deal. September, we started drilling. November, we already had oil in the tanks. So we had production very, very quickly, and then came pandemic and then came the price war around oil. And in the middle of the second quarter, we decided to ramp down activities. And in that sense, we've had 22 wells already drilled, 22 wells that are producing. And seeing the outlook for prices going forward, we decided to restart operations. And we were thinking, Lily, to be restarting around probably August, September. We were actually able to do it in July. So we already have a drilling rig in operation and we're bringing a second rig into the operation. The plan is to drill another 22 wells, and these wells will be put into production in the first quarter of next year.

In the material you saw that we talk about 5,500 barrels, Ecopetrol net. In June, we actually had 18,000 barrels of production in the Permian, so we are very, very pleased from the operations. Breakevens, the Permian is probably one of the best, if not the best, in the U.S. and well below $40. So we're very comfortable with that. Every project is economic in itself, every sets -- set of wells. And the other thing which is great is that operational cost, with everything included for this crude that it's 40 API crude is between $7 and $10 per barrel. So if you rank these operations in our portfolio, they would be amongst the 5 with the lower operating costs.

In terms of what we've learned, we are conducting formal technology and knowledge transfer sessions between our team, the Oxy team, we have people seconded into the operations with our people in Colombia. And we're providing a lot of remote support as well and in things around drilling and completions, in things around fracking, in things around logistics, in things around proppant and how the fracs will actually take place and how they are performing, in things around facilities.

Oxy has been very, very good at very quickly in the space of months designing, building and putting into operation facilities; and that's part of the reason why we have production as quickly as we have. So all that transfer is being -- sorry. All that knowledge is being transferred back into the teams and, as you rightly point out, will help us in all the work we're doing to underpin the proyectos piloto, the unconventional pilot projects in Colombia. Alberto, can you go at the exploration one, please? Can you give us a bit more color? Thanks.

Lily, first of all, in terms of upstream CapEx breakdown during the period, we're going to be spending $1.5 billion in exploration. In terms of production growth, it will be about $5.5 billion, and in terms of facilities maintenance, it will be about $2.5 billion. Specifically in exploratory CapEx, we will be prioritizing investment in Colombia. That's in onshore gas, specifically Piedemonte, and then offshore gas Colombia. And then we will also have to fulfill our exploratory commitments in Brazil. So that covers up what we are planning to spend in terms of exploration. Thanks, Lily.

(Operator Instructions) Our next question comes from Bruno Montanari from Morgan Stanley.

Thanks for being transparent in communicating the changes in strategy on the back of all the market developments. It's very helpful. First question is about the shale JV in the Permian, a quick one. Are you considering hedging the U.S. shale price taking advantage of the nice rebound in WTI prices? Second question is about long-term production trends. I'm trying to understand the production trajectory a little bit better. It's understandable that the 720,000 target is lower than the prior year's plan, decline in the oil price, but if we assume that the JV in the U.S. will contribute with growth, we infer that your output in Colombia will actually be declining. Is that a fair assessment? And what would make you revise your domestic production curve higher in the medium to long term?

And the third question is about asset sales. You have a very strong balance sheet, so different from many other companies, don't really need to have a material disposal program, but would it make sense to divest of any businesses you have purely on the perspective of them not contributing to the required return on capital employed within the current portfolio?

So thanks for being here. Thanks for attending the call and thanks for the question. I'll take the last one, on the assets. And then I'll ask Jaime to talk a little bit about the hedging and then Alberto to talk about the production trajectory. So one of the things that we've developed over the last few years is the ability to understand in detail the portfolio that we have; and that allowed us largely to recast the plan very, very quickly, the 2020-22 plan.

So in terms of any potential divestments, we have a very good understanding of the portfolio. We continuously look at opportunities, and should they happen going forward, we'll communicate it in due time, right. You may remember, Bruno, that a couple years back, we talked about potential acquisitions. And we've done, well quite a few things over the last 18 to 24 months. So in similar way, should something happen in terms of divestments, we will communicate them promptly. Jaime, can you please respond or answer the first one? Thanks.

Bruno, thanks for your question. With regards to hedging, all the decisions around hedging are under the umbrella of our general hedging strategy. I think the -- which is evolving, right? Over the course of 2Q, we did use hedges, with a view to ensure a floor for our pricing, an adequate floor for our pricing, that could ensure the flow of profitable barrels for the organization. And as we look forward then at a group level, we are basically focused on 2 things. We're focused on from a brand standpoint particularly, because that's where we have the largest exposure as a group, to see if there is a business case to ensure or to get some downside protection if there is volatility. And what I mean by business case is, of course, you need to see what is the cost of these hedges. What -- how -- what level of protection do they give us? And of course, in the context of so much volatility, whether we would feel comfortable with that.

That's one focus area. And the other focus area is around the kind of tactical hedges that we do in support of specific pointed transactions, and we do a lot of those. Basically what they do is they give us risk protection for changes between the dates when we negotiate a particular transaction and the day where that transaction is executed. That's the umbrella for this conversation.

[When we think about] WTI in that, the level of exposure that we have at a group level is relatively low, right? So the group's exposure to WTI, when you see at a group level, is relatively low compared to other -- to Brent, for instance, or to diesel. Therefore, it is not a priority at this time. Having said that, we have been -- we have started to look at whether hedges in the Permian transaction would make sense over the long run, right? And it's something that we need to study in more detail going forward. I hope this addresses your question, Bruno. Thank you.

It sure does.

Our next question comes from Anne Milne from Bank of America.

Before that, we're going to answer Bruno's question around production. Bruno, thanks for your question. What we are considering in the plan with regards to Permian production is that production will be slightly increasing from the range of 5,000 to 6,000 barrels per day oil equivalent this year to about 20,000 to 25,000 barrels per day in 2022. So that leaves that our production in Colombia will remain flat. We're assuming in the plan a decline factor of about 17% in our mature fields.

So in terms of growth for the future, we see several alternatives. One is being successful in our exploration efforts, specifically in offshore and onshore gas. Secondly, we want to be successful in the secondary and tertiary recovery projects. We have 51 projects in the plan that, if assumed successful, will bring additional production. And also, we are betting on mature provinces that where we still have a space for growth. So by 2023 and onwards, we will see that the Colombian production will be increasing as well.

We will now move to Ms. Anne Milne's question.

A couple of questions. The first one is I know you had, this quarter, to reduce your refinery output due to lower demand. And I was just wondering if you could explain to us how you decide what level each refinery is going to be and what the advantages and disadvantages of each of them are. Second question is I wanted to know if you have any new targets for leverage or liquidity. Ecopetrol's liquidity is still strong and your leverage is still below your peer group. And so I was just wondering if you have any new targets since your leverage did go up this quarter. And then just a quick question: There was a new loan that was disbursed. It was a treasury loan. Is that from the Colombian treasury? And was that for a specific purpose?

Anne, thanks for the question. I'll take the first one, and I'll ask Walter to give a little bit more detail around. And then Jaime can help us with leverage or liquidity and the treasury loan. In terms of refineries, here is what happened. We started the year with both Barrancabermeja and Cartagena running at capacity -- well Barranca a little bit less than capacity but mainly some 220,000 and Cartagena 150,000 to 160,000. And then in March, back end of March, and April, we saw the dramatic reduction in destruction of demand. And so we had to adapt very, very quickly to cope with the new demand levels in country. And we've talked about it, but roughly sales for products in the -- in a month would be around 300,000 barrels. That's the main products diesel, gasoline and jet. And in April, we were doing 100,000 barrels. So that led us to adapt very, very quickly. And what we did -- and we have a lot of flexibility in Barranca. And we have, well one of the most advanced refineries in Cartagena. So that combination proved to be very, very appropriate. And we were very -- we were able to cope with that need to reduce demand. So in Barranca, out of the 50 plants, we had at some stage some 8 plants or 9 plants running. And out of 5,000 or 6,000 people that we would see every day in the refinery, we had 600 people. So we had to adapt very quickly demand and also all the biosafety and biosecurity protocols to operate. So Walter, why don't you give us a little bit more color around that?

Okay. So thank you, Felipe. Thank you, Anne, for your questions, yes. As Felipe said, we were running both refineries at full rate, but in the middle of March, we -- the demand for our products dropped significantly. And then we needed to reduce Barranca to balance to the local demand so that, that refinery was running around 50% capacity during second part of March, April and part of May also. And then after that, local demand started to go -- to grow, and we have started to increase rate at the Barrancabermeja following the local demand. Margin has been positive, so from that point of view we didn't have a problem. The problem was mainly local demand for Barrancabermeja. And now we are running around 180 KBDs, which is around 80% of the capacity of that refinery. In the case of Cartagena, we needed to reduce rate to around 70% of normal capacity; and that took place second part of March, April and also May. Since that, we have been going up in rate following the local demand but mainly the ability to export. Our commercial group has been doing a great job with exports of our product at the Cartagena refinery. And this has allowed us to maintain that refinery running all the units, and currently we are around 90% of capacity, supported mainly by exports. I hope I answered your question.

(inaudible).

Walter, thanks. And before handing over to Jaime, I'd just like to add, Anne, that we were also able to perform our -- some of our key maintenance on both refineries. Even though at some of them we were in the middle of the response to the pandemic and everything else, we were able to adapt. And we've carried them through not only 2Q but 3Q as well. Jaime, please go ahead.

Thanks, Felipe. Thanks, Anne. Thanks for your questions. Let me provide a bit of color around liquidity on the loans. So I guess, firstly and with regards to leverage, 2Q was a very active quarter. We actually subscribed about $3.1 billion of loans through the period, and there was a combination. And there were basically 3 elements of that. There was a bond placed in the international markets of about $2 billion. There was a line of credit that we had for about $600 million that we pulled in. It was an existing line of credit. And there were about $400 million to $500 million of what we called treasury lines, which yes, yes, I think there is a translation issue in that effectively there are short-term loans that have a 12- to 24-month duration, actually typically less than 12 months. And in Spanish, they are called creditos de tesorería, which can be loosely translated as treasury loans. These are not loans that are received from the government. They are received from private banks, right, effectively. So that -- I think that answers a bit the treasury loan question. With regards to leverage targets, yes, as you know, probably this crisis took us in a very strong both liquidity and kind of gearing position compared to our peers. With these lines of credit that we pulled over the second quarter, we are seeing our leverage increase, 2.4x debt in this quarter we are today. And we think that actually over the rest of the year we are actually -- that leverage ratio is probably going to grow, keeping under 3.5x debt-to-EBITDA, right? The reason why that grows is that, basically when you look at the mix of our operating cash flow and the CapEx requirements that we have, plus dividend payments that we're going to make over the second half of the year, that ratio deteriorates a bit. When we look longer term, what we see is that, by 2022, as our operating cash flow improves and our free cash flow improves actually on a sustained basis, we see that ratio is going to be below 2.5x debt-to-EBITDA. When we look at do we feel comfortable with that, we feel comfortable with that both from a context of the flexibility that we have within the plan to make changes. We believe that we have a lot of flexibility around that. The primary driver for this increase in leverage is actually -- it's actually discretionary CapEx. So we can always pull on that lever if we need to. So that's one reason why we're comfortable. And I think the other reason why we're comfortable is that, when we look at it from a peer standpoint, we are -- we -- despite this increased leverage, we continue to be probably in the high second quartile of companies in the sector with lowest leverage ratios. I hope this answers your question.

Yes, Jaime.

Thank you, Jaime.

Our next question comes from Christian Audi from Santander.

Felipe and Jaime, just 2 questions, please; the first one, on ROACE; the second one, on dividends. On ROACE, you have always stood out in terms of generating a very impressive return on capital employed. Could you talk a little bit about the evolution you expect during the length of the plan; and any color as to differences you expect in ROACE between upstream, midstream and downstream? And then secondly, on the dividend front, if you could talk a little bit, given all the adjustments that you have made to protect the company from market conditions, what should we expect in terms of your dividend payout for this year and during the duration of the plan.

Thanks, Christian, and thanks for your question. Thanks for being today in the call. I'll ask Jaime to give us a bit more color around the ROACE and how we are looking it at the plan. And also if he wants to add up on dividends. But I just wanted to say, in terms of dividends, we have a policy around dividends which is very clear. And the ultimate dividend decision will be based on the decision of the AGM, of considerations and the assessment and then the final decision of the AGM that will take place in 1Q next year. Having said that, obviously it will depend on how we end up the year. And we've managed to go through a very, very, very complicated and tough second quarter. We're seeing a little more support for prices. You've seen how we've adjusted some of the operations that we're conducting. So it will depend on all those aspects, but Jaime, if you want to talk about ROACE and then expand on dividend, please go ahead.

Thank you, Felipe. Christian, thank you and thanks for your question. With regards to ROACE, as we've discussed in the past, our goal in Ecopetrol has been to deliver a return that exceeds cost of capital, fundamentally. And over the last number of years, we had a very good run with regards to creating actually a growing spread between that cost of capital and the ROACE that we deliver. With this plan, we continue with that aim, right. It is challenging. It will be extremely difficult to sustain ROACEs of double digits in the market prices that we're -- or in the prices that we're assuming for the plan. It is very challenging, but we can see -- with this investment plan, we can see ourselves in 2022 with ROACEs in the very high single digits. I mean 8% to 10%, which we compete favorably with the costs of capital that we have as a company. That's what we're expecting. Obviously, to the extent that we have a price upside to our plan assumptions, which -- and I might recall they're $38, $45, $50. To the extent that we have upside to that, ROACE is going to improve in a very direct way. That's what we're seeing. If I were to give you a bit of color with regards to segment behavior on that: In the very near term, and I mean kind of 2020, right, clearly both the upstream and the downstream are challenged because their EBITDA contribution this year, relative to historical, is going to be lower, right, at the current price environment. Midstream remains essentially unchanged with regards to their historical contribution. And what we're seeing from an outlook standpoint '21 and '22 is a very -- a growing contribution from the upstream and a stable contribution from the midstream and a gradual recovery from the downstream, particularly as the Cartagena interconnection kicks in, that project which I'm sure that Walter is going to give us a little bit more color later on kicks in. We're going to see that the ROACE in the downstream improve. That's the general color of that. And with regards to dividends -- and Felipe has laid out the general framework. And from a planning standpoint, what I would say is that, as we look at that range of 40% to 60% payout, we believe that we move within that range closely linked to the actual price environment, right? So given the price environment that we see for 2020 and 2021, which is $38 and $45, we see -- from a planning standpoint, we believe that we should be in the lower end of that range. And as we go to 2022, we're going to be on the high end of that range, but again as Felipe said, this is going to be determined by the shareholders in due time. I hope this answers your question. Thank you, Christian.

Very helpful.

Our next question comes from Luiz Carvalho from UBS.

Congratulations to be -- for being so active by addressing to the company progression through the -- let's say, during the crisis. I also have 3 questions. I would like to come back on the dividend policy. It's clear that second quarter was very challenging. So just (inaudible) on how, let's say, the CapEx allocation and the -- let's say, the capital allocation would match with the dividend policy that the company currently has. That's the first one. The second question is about potential acquisitions and M&A. I mean the company [has been] quite active trying to increase production and keep the reserves in a very healthy level, but what's your take in potential acquisitions or, I don't know, junior companies or, I don't know, some fields in a more advanced stage that could boost your production/reserve life in the more short term? And the third question is more about the lower activity that we have seen on the U.S. [shale]. I mean, when we look to the rig count over the last, let's say, a couple -- I'd say, 18 months, there's much lower activity. So just trying to understand what will be the potential benefits that this is bringing to your, I don't know, [volumeship] with Oxy in the U.S. shale. These are the questions from my end.

(inaudible) Luiz, and thanks for being here. I'll take the number 2 and 3, on acquisitions and the U.S. And then I'll ask Jaime to provide a bit more context on dividends and CapEx allocation. So in terms of M&A, and you've mentioned that we've been quite active. And we've, I think, demonstrated that we've followed strategy in terms of where we want to go. We've gone into Brazil. We've gone into the Permian in the U.S. and we've done a few things in the Gulf of Mexico as well. So I think how I would think about this is that we've been able to exercise the muscle to very quickly assess opportunities, look at the market, see how things are progressing. And then should we see something that's -- that would fit the strategy, we would consider that in detail. Having said that, as we all know, times are a bit stretched in terms of the cash flows, in terms of -- I mean even some -- even when I was looking at prices today, they were up a bit, but there's still uncertainty, and eventually there will be some volatility. We don't know if, in terms of demand and pandemic and lockdowns, are we going to see something that's very tough in the next few months, or no? So we will continue to look at opportunities both to continue to build on strategy and, as you rightly point out, look at production opportunities. But we'll see. I think we'll -- we're being cautious right now with everything going on. And in terms of the U.S., the -- and I provided a bit of color around that, but I'll repeat some of the numbers. So being it short cycled, we very quickly started operations in the U.S. So we announced the deal July 31 last year. September, we started drilling. November, we had production, and we drilled 22 wells. We completed 22 wells. We fracked 22 wells and we're producing those 22 wells. In June, we reached 18,000 barrels gross for the JV, which is very good. So very quickly, we were able to see the benefits of a very, very good operational performance by the operator, and we are very pleased with that. And we were able, because of the nature of this business, to slow down in May. And as -- remember April, when we saw a negative WTI. So we stepped on the brakes. We adjusted things. And we were thinking about, end of 3Q, restarting, around September or so. And we were able to bring the first rig into operation back in July. I think the Permian -- and where we are is one of the areas with the highest potential. It has some of the best breakevens. Our operational costs are between $7 and $10 per barrel. It's very light crude. So it has all the right elements for it to be accretive in terms of what it brings. And in addition to that, we're -- and I've answered this, I think, to Lily earlier, we're bringing a lot of know-how, technology, expertise by having our secondees in the JV; by having the formal technology and knowledge transfer, workshops and meetings and seminars and the like. So we're very comfortable with that. And in the next few months, we'll work on poring the plan for next year and the following year in detail. Thanks, Luiz. Jaime, if you want to take the dividend question. Thank you.

Thank you, Felipe. Thank you, Luiz. Thanks for your questions. So with regards to dividend and how we think about it, I'd say, firstly, we look at that mix between dividends and CapEx from a -- in the context of our capital structure, right? And when we look at that capital structure, what's the baseline position? Low gearing ratio relative to our peers, as Anne was asking before; space to improve that gearing level, importantly; and growing operating cash generation over the next months and years. That's our expectation, right? In that context, 2Q is a tough quarter, but it's one that we believe that's the worst that should be expected and it's in the past, right? The outlook going forward is a better outlook. So in that context, when we look at the -- at what should be the right level of capital allocation and what should be the right dividend assumption for the plan and again recognizing that we don't necessarily decide that but what we would like to propose from a plan standpoint, what we saw is that we -- as a company, we have a full ability to honor the dividend commitments that have already been made, importantly, associated to the 2019 performance. So we have that capacity, and we also have the capacity to sustain CapEx levels when we compare them to the previous years. And of course, there is a strong value proposition associated to sustaining that level of CapEx, as I think it was asked before. To the extent that we can sustain that level of CapEx, we protect reserves. We generate between $5 billion to $6 billion of NPV associated to that too. And it is actually what drives the ROACE target that or aspiration that I spoke about later of being somewhere between 8% to 10% and, in any case, returning to our shareholders more than the cost of capital over the long run, right? So that's the way that we thought about it. And I think, thirdly, it is not part of our plan, but I think it's an important consideration, is that when you look at our price assumptions, $38, $45 and $50, depending on where you see it -- but I think that most of the feedback that we've received, so far, is that it could be conservative. It certainly looks conservative in the short term, right? We feel good about that because of the uncertainties and risks that Felipe has spoken about, but if these risks do not materialize, certainly there is significant price upside and therefore cash upside associated to this plan. Ultimately, using the price assumptions, what you can see is that, by the end of the 2022 period, we have $17 billion of available cash, of which between $11 billion and $13 billion go to CapEx, right, even on a high case. So that allows for $4 billion to $5 billion of excess cash in potential distributions if the shareholders see fit. I hope this answers your questions.

(Operator Instructions) Our next question comes from Guilherme Levy from Morgan Stanley.

I have just one question actually. If you could elaborate on the opportunities to increase with gas production, particularly in Colombia. And I refer here to the supply-and-demand chart on Slide 17. If you can explore what can be done in Piedemonte, in Guajira that wasn't tried before; and also if you can elaborate on the time line for the offshore projects just so we can have any hint on when any potential production coming from there could enter the market. And lastly, if -- those amounts in the chart, if those include any sort of production coming from shale in Colombia.

Guilherme, thanks for the question. And I'll give a very brief context then I'll ask Alberto to expand. There's a few things that I think are important. One, in Piedemonte, over the years, we've become the 100% owner of the main fields, Cupiagua in 2011; Cusiana 2016; and this year, Piedemonte, the Floreña and Pauto fields. So now we have full alignment in terms of ownership and operatorship of the full trend of the Piedemonte gas opportunity. So I think that's one element. And the second one, in Guajira we now have operatorship. So as Hocol bought the equity or the ownership from Chevron, Ecopetrol was a partner then. So now it's Ecopetrol and Hocol, and we have a company that's operating offshore in this very important gas field. So there's -- those 2 elements that I wanted to highlight because they changed a bit the landscape and clearly provide, I think, more not only alignment but opportunities going forward. So I'll ask Alberto to give us a bit more detail around your specific questions. Alberto, (foreign language). Go ahead.

Guilherme, thanks for your question. So in terms of production, what we have included in our plan in terms of gas production, when you look at 2020, our current production is around 120,000 barrels of oil equivalent. And we want to increase production by 15,000 barrels by 2022. In order to do so, we will have to cope the decline in production in Chuchupa and Ballena. That's the Guajira assets recently acquired and operated by Hocol. The declining ratio will be about 17% by 2022, so we need to specifically do something in terms of ensuring reliability and trying to cope up in terms of reducing pressure in compressing -- compression facilities. In Piedemonte, what we are planning is increase our activity in terms of bringing new wells that's in Floreña and Pauto and also debottlenecking treatment and transportation systems. That will allow us to bring additional molecules of gas. And also, there will be activity in the Caribbean onshore by Hocol, where we are planning to increase our production by 10,000 barrels of oil equivalent. Going forward, when you look beyond 2022, we want to be successful in terms of our exploration activities, and there are 2 areas of [prioritization]. One is offshore. And when you look at our plan, by 2024, we would like -- in 2024, 2025, we would like to bring the Orca project on stream. And also in Piedemonte there will be aggressive activity in terms of exploration looking to see all the trends. This is going from the Casanare to the Arauca areas. So there is going to be a lot of focus on gas, Guilherme, definitely.

And we have a question from Lilyanna Yang from HSBC.

One follow-up on the refining and transportation segments. On the refining side, the CapEx of $1.2 billion, $1.3 billion for the 2002 (sic) [2020-2022] period seems a bit high, but as Jaime mentioned, I think you guys have a little bit of flexibility here. So could you give us a breakdown of the investments in refining? Meaning, how much is for CapEx -- sorry, capacity expansion, if any, right? And timing, if you have any FID for the Cartagena refinery expansion project. And how much of that will be for increasing the refining complexity, right, with production of the cleaner fuels, which it looks like it's mandatory by the end of next year, right? So anything on that front will be great. And on transportation, midstream, in second quarter, right, you announced tariff discounts to independent producers. You're helping with the working capital. Those were under conditions of Brent being very low, below $40, right, so what is the status now? Did you end up negotiating any of the crude transportation contracts or the tariffs? And which terms? And also, if you can talk about what we can expect from the rate review for fuel transportation for next year.

Lily, thanks for your questions. So I'll ask Walter Canova to give us a bit more detail on some of the investments and the CapEx that we're seeing forward. And then I'll ask [Milena] to help us with the transportation. Walter?

Thank you, Felipe. Thank you, Lily, for your questions. Regarding CapEx allocation for the downstream of these $1.2 billion, $1.3 billion that you mentioned. Our focus for downstream has been -- the capital [scene] is focused on HS&E, legal compliance and to ensure we have a reliable operation for the following year. And as such, of that amount, I will say 50% to 55% is allocated on turnaround activities and reliable -- reliability improvement process. In this area, I will say that, for example, in the case of Cartagena, we are running in 2021 and 2022 in the first cycle of main turnaround activities for the main process units. And as such, we need to make sure that we secure them properly, and we have our CapEx allocated for that. In the case of Barranca, also we have CapEx allocated for the main activities at Barranca. Mainly we focus on the FCC unit and cracker unit. Those units are running into their 10-year cycles, and as such, they need an important CapEx allocation to make sure that we do a lot of repairs and allow proper operation for those units in the following years. So that is 50% to 55% of the CapEx. Then we have around 25% of the CapEx allocation into HS&E projects and legal compliance, mainly at the Barrancabermeja, to make sure that we keep compliance of the legal requirements, local legal requirements, in term of water disposition and emissions. And then we have -- another 25% of this $1.2 billion, $1.3 billion that is growth projects and product quality. In the case of growth is we are talking about mainly the Cartagena refinery crude interconnection projects. And also we do have some growth projects at Esenttia. Esenttia is our petrochemical affiliates. In term of product quality, the main focus is in some improvement we want to do [in the following years] at Barrancabermeja. As I said, the case of the interconnection of the crude unit at Cartagena, this project was approved at the end of 2019; and the project is progressing, is already in execution phase. And we're expecting to complete this project in the first half of 2022. That would allow the refinery to go from 150 KBD to 200 KBD approximately. This is a project that we checked in the current environment and it has a very good return. And we are -- this is one of the only, I will say, growth project that we have in the downstream that we are progressing in current environment because it's very positive for the future economics of the refinery.

And the -- for 2021, we are planning to reduce the sulfur content of our gasolines at country level. And as such, we are progressing some small projects this year at the Barrancabermeja refinery, but those projects will allow us to meet those 50 ppm maximum at gasoline but with small investments and some cap change-outs. So we are not planning in the short term to change the complexity of the refinery, although we are progressing between this year and 2022 some important, I will say, process to improve the quality of our products and basically to make sure that we have all our diesel and gasolines less than 10 ppm country-wide. But those projects will be developed in the -- between this year and 2022. And these investments for those projects will come mainly between 2023 and 2026. I hope, Lily, I answered your question.

[Milena]?

Lily, thank you for your question. So I'm going to break the question up into 3 components in terms of what we have done to support producers through this period. And basically one could break up what we have done into 3 different things. There were discounts offered over a 2 months period. There were financings, and then there was alterations to a couple of contracts, which more than alterations to contracts, I would say sort of [flexibilizations] of volumes for the year. So in terms of the discounts, we have discounts during a 2 months period. That 2 months period has already expired. There were 3 requirements in order for the discounts to be in place, which were basically a minimum level of volumes going through the systems where there were discounts offered. Discounts were only offered if the FX rate was above a certain level, which was COP 3,600 to the dollar. And there was a moving scale where discounts depended on where the FX was. And oil had to be below $40. So that took place through that 2 months period. We do not foresee any discounts going forward at this point in time with the market where it is right now. The second measure we had was we offered financings through remittance, and this basically had 6 months where we financed up to 50% of their bills. That financing is up to 12 months, with a 6 months grace period after receiving and amortizing the financing. And the financing had an interest rate associated with it.

And then the third thing we did was in a couple of specific cases where clients were not able to meet the volumetric requirements of ship-or-pay contracts. What we basically did was, over those couple of months where they delivered fewer volumes than were expected, they need to compensate those volumes later on in the year. So basically when you look at this from a full year perspective, the impact is marginal, and we basically gave them this flexibility given the current environment. So it's not a change in the terms of the contract of a ship-or-pay contract. It's not a facility that is recurring. It was something we [flexibilized], so to speak, at these specific points in time in order to accommodate producers. So these were the 3 measures. So when you look at the [flexibilization] of contracts and the financings, there's no impact in terms of revenue for the company because, the volumes, you don't receive now. You receive later. And from the financing perspective, we still have an accounts receivable from all these companies. [And as a matter of fact], revenues grew slightly up because we charged an interest on this and then the discounts which only were valid during the 2-month period.

Right, if I got it right. So the level of EBITDA dropped by first quarter and second quarter. Part of it is because of these issues, but part is also because the regular contract provision that allows for lower volume, right? So in the third, fourth quarters, can I already expect a recovery on the revenue, EBITDA to something more like last year's numbers? Or it should still be kind of closer to what we saw in the first half or second quarter.

So when you look at the change in revenues for the midstream and you compare first quarter to second quarter, there is really 2 large drivers in terms of what you see. The first one is -- and it's important to remember. And this is -- these are rough numbers because they change with the FX rate. Approximately 80% of the revenues come from dollar-denominated tariffs, which are oil pipelines. Between 20% and 25%, depending on where the FX is, comes from refined products pipelines whose tariff is in pesos. So the big impact between first quarter and second quarter is basically a reduction in volumes which is not associated to ship-or-pay contracts really. It's associated -- because a ship-or-pay contract [flexibilization] was marginal. It's really associated from lower transported volumes both because there was lower productions; and because in the refined products pipeline, the measures taken by government requiring people to stay at home reduced our transportation volumes of gasoline, diesel, et cetera significantly during that period. So when we look at what's going to happen going forward, you're going to see a sharper recovery in refined products transportation just because of the dynamics of people no longer being under a stay-at-home order, so to speak, and any gradual recovery of volumes in-line for much of what -- to what you have heard from the upstream segment. Those are really the 2 largest moving factors between first quarter and second quarter. It's not related to the ship-or-pay contracts or the flexibilization.

Thank you. We have reached the allotted time that we have for questions. I would now like to turn the call back to Mr. Bayon for any final remarks.

Thank you. And thanks, everyone, for participating. We have over 170, 1-7-0, connections. That's something. We appreciate your interest and participation in following what we do at Ecopetrol. Your questions are very important to us. They can provide us some additional lenses that we need to use to see how we're doing, what we need to do, things that we may need to adjust. So we really appreciate it. We expect that you remain safe, that you take care of yourself and that you and your families are safe throughout these very trying and difficult times.

We've gone through a very tough second quarter. You saw that in the results. We hope that probably the worst is behind us. We've managed to prepare what we think is a very comprehensive plan for the rest of the year and the next couple years. And obviously we'll continue to monitor conditions, how they evolve, how things change; and we'll continue to communicate promptly with you. And we appreciate the comments that some of you have made around the transparency of our communications, the frequency of our communications; and we also value your feedback.

So with that, thanks again for participating. And I hope that everyone has a very good rest of the day. Goodbye.

Thank you, ladies and gentlemen. This concludes today's conference. We thank you for participating. You may now disconnect.