Ecopetrol SA (EC) 2019 Q4 法說會逐字稿

Good morning.

My name is Sofiana, I will be your conference operator today.

At this time, I would like to welcome everyone to the Ecopetrol Fourth Quarter 2019 Results Conference Call.

(Operator Instructions)

Thank you for your attention.

Mr. Juan Pablo Crane will begin the conference today.

Mr. Crane, you may begin your conference.

Good morning, everyone, and welcome to Ecopetrol's results earnings conference call and webcast in which we will discuss the main operational and financial results of Ecopetrol for the fourth quarter and full year 2019.

Before we begin, it is important to mention that the comments in this call by Ecopetrol senior management and 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 digital results are different from the projections shared on this conference call.

The call will be led by Mr. Felipe Bayón, CEO of Ecopetrol; and other participants include Alberto Consuegra, Executive Vice President; and Jaime Caballero, CFO.

We will begin this presentation with the main achievements of the year 2019, followed by the business highlights and financial results under international financial reporting standards.

We will then close with the main targets of the 2020, 2022 plan and a Q&A session.

I will now hand over the presentation to Ecopetrol's CEO, Felipe Bayón.

Juan Pablo, many tanks, welcome, everyone, to this conference call for the 2019 fourth quarter and full year results.

I am pleased to share with you the outstanding operational and financial results for the Ecopetrol group.

In the reserves and production side, we highlight our entry into the Midland and the Permian Basin in Texas through a joint venture with Occidental.

In order to participate in the exploitation and production of unconventional reservoirs.

This JV allowed us to incorporate 164 million barrels of reserves into 2019 numbers.

Another important milestone was the acquisition of 30% of Shell stake in Gato do Mato discovery in the Santos Basin in the Brazilian pre-salt, where we expect to drill an appraisal well in 2020.

Likewise, we highlight the successful drilling of the Esox-1 well in the Gulf of Mexico that is currently in production and the progress of the viability of the research pilot projects of unconventionals in Colombia, also known as proyectos piloto de investigación integral.

We continue positioning Ecopetrol towards energy transition in 2 major fronts.

The first one, by strengthening our presence in gas and transition fuel.

We had 2 major achievements.

The preliminary agreement between our subsidiary, Hocol and Chevron to acquire its stake in the Chuchupa and Ballena fields subject to approval of Colombian Superintendence of Industry and Commerce; and the commercial agreement signed between Ecopetrol and Shell in the Colombian offshore gas province.

We recently announced the creation of a vice presidency of gas led by a petroleum engineer women with more than 20 years of experience in our industry.

The second front is our decarbonization plan.

Having stated our target of reducing 20% of CO2 emissions by 2030, in line with our commitment to reduce the operations, vulnerability to climate change and contribute towards protecting the environment.

Furthermore, in January 2020, we endorsed the World Bank's Zero Routine Flaring initiative seeking to reduce routine gas flaring.

As part of our renewable energy plan, the company set a target of incorporating around 300 megawatts of renewables by 2022.

To achieve this target, we commissioned our first solar field of 21 megawatts in Castilla in the departamento del Meta in 2019, and we were awarded 30 megawatts of -- in the unconventional renewable energy sources auction by the Ministry of Energy.

Also, in 2020, we have scheduled the construction of a San Fernando solar field with 50 megawatts of installed capacity.

We continue to contribute to improve air quality in the cities in Colombia by offering cleaner fuels with higher standards than those ones required by law.

Let's move on to the next slide to review the company's financial and operational results.

We continue to deliver strong results, along with a sustainable growth despite a volatile environment.

Financial results were the highest in the last 6 years.

These outstanding results were obtained, amongst other things, due to the positive operational performance across all of our segments and the positioning of our crudes in markets where they add more value.

This remarkable performance also allowed the highest dividend distribution for the company's history, COP 314 per share.

In terms of reserves, I am pleased to announce that we've replaced 169% of our production, the highest replacement ratio in the last 9 years, and we also exceeded our target of replacing 100% of our production.

This achievement is a result of proper performance and discipline in the booking of both organic and inorganic reserves.

In production, we reached 725,000 barrels of oil equivalent per day, this allowed us to be in the middle of the range of 720,000 to 730,000 barrels per day equivalent that we set at the beginning of the year.

And this result was achieved despite facing operational and security events during the year.

Production levels were supported also by the positive results of our drilling campaigns and an increase in the commercialization of gas.

With respect to the midstream, transported volumes increased by 4% when compared to 2018, reaching 1.153 million barrels per day, beating the segment's target.

As part of the commitment to capital discipline and cost efficiency by the end of 2019, our group achieved cumulative efficiencies for the year of COP 3.3 trillion exceeding the target for the 2019-2021 plan.

Let's move on to the next slide to discuss the market environment.

During 2019, we faced a highly volatile market environment.

Brent price fell $7.50 per barrel when compared to 2018.

The exchange rate and depreciation partially mitigated this impact on the lower price.

Regarding the performance of our crude oil basket, we saw a strengthening of heavy crudes, mainly due to lower supply in the region, reaching a record high discount of minus $5.6 per barrel in 2019.

Our sales and marketing strategy enabled us to establish an even stronger relationship with the refiners, making us a reliable heavy crude supplier for our customers with high-quality standards and competitive delivery services.

Although our refined products experienced weaker margins, our basket spread remained stable when compared to 2018.

Moving forward, our business plan is designed at Brent prices of $57 per barrel, with flexibility to face a challenging market environment.

Now let me hand the floor to Alberto Consuegra, who will tell us about the main operational achievements in 2019.

Thank you, Felipe.

I would like to begin by presenting our local and international exploration activity results, where we participated in 14 new areas, consolidating our strategy focused on the inclusion of assets through acquisitions, farmings and participation in exploratory rounds.

Through the deployment of exploration activities, near 150 million barrels of oil equivalent were incorporated by these covered resources, contributing to the future increase of the group's reserves.

The successful results of the exploration strategy in the near-field exploration areas allowed us to add through production extended test over $1 million of accumulative equivalent oil to Ecopetrol's production.

We are currently assessing the commercial viability on the Jaspe, Andina and Cosecha discovery wells.

Likewise, Bullerengue-3, Flamencos-1 and Boranda wells are in appraisal phase, with the drilling of 4 appraisal wells foreseen for 2020.

It is important to mention that the National hydrocarbon agency, assigned to the Ecopetrol group through its subsidiary, Hocol, 7 exploratory blocks as part of the permanent process of area allocation.

Furthermore, Ecopetrol was awarded with 1 offshore block and 2 onshore blocks located in the Piedemonte area, which will strengthen Ecopetrol's presence in this area of the country.

I also want to highlight the acquisition of 2,000 square kilometers of 3D deepwater marine seismic in the COL-5 block.

This information will allow Ecopetrol to expand and strengthen the exploration portfolio of the Southern Colombia Caribbean.

Additionally, as part of the exploratory areas, licensing rounds in the United States, the MC-904 block located in the Mississippi Canyon area was allocated to Ecopetrol America.

Let's move on with the next slide to discuss production results.

The growth in the annual production is attributable to the positive results seen in the Akacias, Yarigui, Cono Sur and Chichimene fields as well as to an increase in the commercialization of gas, mainly from Cupiagua and Piedemonte fields.

The entry into operation of the Cupiaga LPG plant and the increasing water injection capacity in Rubiales are also worth mentioning.

By 2020, we expect to reach a production within the range of 750,000 to 760,000 barrels of oil equivalent per day, mainly supported by the execution of drilling and recovery projects in our current fields, the reversal of the Florena and Pauto fields and the entry into production of the acquired fields during 2019, which are in line with the segment's investment plan.

Let's move on to the next slide to discuss our reserves balance.

By the end of 2019, oil and gas reserves have an average life of 7.8 years, which improved by 8.3% compared to 7.2 years for 2018.

Organic growth was in line with our target of replacing at least 100% of the production.

Within this component, I would like to highlight, on one hand, the incorporation via primary recovery projects, which contributed with 103 million barrels of oil equivalent, mostly due to the contribution of the Rubiales, Cupiagua and Cono Sur fields.

On the other hand, the secondary and tertiary recovery program, which added an additional 94 million barrels of oil equivalent, mostly due to the performance of the Chichimene, Castilla and Yarigui fields.

Due to the advances related to inorganic growth, 164 million barrels of oil equivalent were added coming from the joint venture with Oxy in the Permian Basin.

Let's move on with the next slide to discuss the successful results of the enhanced recovery program.

The recovery program continues to support our growth and value generation strategy.

The program represented 22% of the incorporation of 1P reserves during 2019.

Within this strategy, it is worth highlighting the beginning of tertiary recovery with polymer injection in the Dina field and 4 new pilots, 3 with water injection in Provincia, Tisquirama and Nutria and one air injection in Chichimene.

Let's continue with the next slide to discuss the results of the midstream segment.

During 2019, we increased the crude oil and product volume transported by 4% as compared to 2018.

Crude oil transported volume increased 5% due to higher domestic production.

The capture of barrels that previously were not evacuated through our pipelines, such as the injection of crude from the Acordionero field in Ayacucho.

Also, additional volumes coming from increasing demand for crude from the Barrancabermeja refinery.

Refined product stability was supported by an increased demand in the border areas that allowed to compensate the decrease in transport due to scheduled maintenance at the Barrancabermeja refinery.

Our efforts remain focused on ensuring the systems operation that are affected by third parties.

Particularly in order to guarantee the evacuation of [Guajira] fields, 46 reversion cycles were carried out with a volume of 11.5 million barrels with no impact on production.

Please, let's move on to the results of the downstream segment.

Due to the challenging market environment during 2019 that spreads in international product prices with respect to Brent decreased mainly Naphtha and gasoline.

In the last quarter of 2019, the higher fuel oil spread had a negative impact on the Barrancabermeja refinery.

This behavior on products prices, together with the strengthening in the spreads versus Brent of the crudes used in our refineries diet implied weaker refining gross margins, resulting in a joint refining margin of $10 per barrel in 2019.

Despite the impact on margins due to the continuous optimization of the crude oil feedstock and the activities related to asset integrity, the refineries joint throughput reached a historical yearly high of 374,000 barrels per day.

Additionally, the refineries reached record levels in yields of middle distillates of 37% in Barrancabermeja and 57% in Cartagena.

During the fourth quarter of 2019, the Cartagena refinery reached a throughput of 156,000 barrels per day, marking a record share of domestic crude in the feedstock, which increased to 92% compared to 77% in the same quarter of 2018.

This increase in the domestic crudes share significantly favored the cost of the feedstock, partially mitigating the impact of stronger heavy and medium crude prices in the international market.

The Barrancabermeja refinery kept stable throughput and operational performance with 222,000 barrels per day for the last quarter of 2019.

Let's move on to the next slide to talk about efficiencies progress.

During 2019, we continued the optimization path of diluent consumption, reducing our dilution factor from 14.8% to 14.2%.

Due to the capacity of the El Oleoducto de los Llanos to transport Rubiales crude oil at a high viscosity, along with the reduction in the diluent evaporation in assets such as Castilla and Chichimene due to the implementation of the change in the diluent specifications.

The aforementioned has allowed to continue with the reduction of its volumes.

On the other hand, the lifting cost was $8.7 per barrel at stable levels due to the implementation of efficiency strategies and the exchange rate effect, which mitigated the increase associated with the increased well maintenance activity and subsoil services necessary to maintain production and an increase of 12% in the energy rate.

Our target is to continue to improve cost efficiencies and capital discipline.

I now pass the floor to Jaime Caballero, who will discuss the main financial achievements of the Ecopetrol Group.

Thanks, Alberto.

During the fourth quarter of 2019, Ecopetrol delivered stable financial results as compared to 2018, mainly due to an improvement in the crude and products basket spread, higher sales of crude oil and a greater devaluation of the exchange rate, this, even with a lower Brent price at $7 per barrel.

EBITDA margin stood at 38.6%, at the same level of the last quarter of 2018, mainly explained by the increase in revenues, which reached COP 18.6 trillion, the highest figure in the last 8 quarters.

It is important to highlight that this quarter typically exhibits a high cost and expenses seasonality, which negatively impacts the EBITDA margin.

Net income increased by 54%, and closed at COP 4 trillion, in line with a better EBITDA, savings in terms of financial expenses and a lower effective tax rate.

Likewise, there are 3 nonrecurring events reflected in net income, which I will explain shortly in detail.

Let's move on to the next slide to discuss 2019 full year results.

During 2019, Ecopetrol delivered the best results for the last 6 years and reached a historic EBITDA record of COP 31.1 trillion.

The result was obtained with a $7.5 per barrel decrease in the Brent price as compared to 2018 as well as a more challenging products price environment for the downstream during 2019 due to high products price volatility.

Growth continued to be profitable, evidenced in a ROACE of 14.3%, higher than the 2019, 2021 target of a ROE greater than 11%.

The main leverage ratio debt-to-EBITDA remained unchanged when compared to 2018, reaching 1.2x within the lower range of the target for 2019, 2021.

The rollover of the 2020 debt maturities is expected in the amount of $434 million.

And if the company's growth strategy requires the execution of financing transactions, they will be done within the announced range.

Net income breakeven went from $37.4 per barrel in 2018 to $29.9 per barrel in 2019, mainly due to the lower crude spread, the onetime gain in Invercolsa, lower effective tax rate and lower financial expenses.

The EBITDA margin stood at 43.9% in the upper range of the last 6 years and had a slight decrease when compared to 2018, mainly related to the increase in enhanced recovery processes that involved additional extraction activities and a scheduled maintenance at our refineries, which involved an import of products in order to supply local demand.

Finally, EBITDA per barrel went from $39.6 per barrel in 2018 to $35.8 per barrel in 2019 due to the lower crude and products basket price.

Please move on to the following slide to see the details of the investment in Invercolsa, its implications on the 2019 results and the expectations for 2020.

Inversiones de Gases de Colombia, Invercolsa is a business group with interest in energy companies with presence in 19 departments of Colombia.

Invercolsa currently has 6 controlled companies in its portfolio and 9 companies with a noncontrolling interest.

This company was founded within the coal gas asset spin-off and currently, directly and indirectly has a 34% share of the Colombian gas market.

Ecopetrol gained control of Invercolsa, increasing its stake from 43.35% to 51.88%.

This change of control generates 3 main impacts in our financial statements.

Firstly, the dividend recognition for the 2006 to June 2009 period, equivalent to 8.3% of the stake in dispute for a total of COP 147 billion.

With the ruling, this amount was recognized as cash and a nonoperating financial income was recognized as well.

Second, a change in the accounting classification of the investment from an associate to a subsidiary investment, which implies under international accounting norms, the line-to-line consolidation of Invercolsa's assets and liabilities and its control companies.

Third, a market valuation of the investment was carried out in compliance with international financial reporting standards applied to business combinations.

This required a fair value exercise and the recognition of the difference with the book value, similar to that carried out in the impairment processes.

This valuation process generated the recognition of a onetime gain of COP 1 trillion, with an offsetting account in each of the consolidated assets.

From now on, Invercolsa's financials will be incorporated within the downstream segment.

Given Invercolsa's economic activity, which consists of transporting products and services to final consumers.

Please move on to the next slide to see the group's net income performance.

Net income for 2019 increased by 14% and closed at COP 13.3 trillion.

I would like to highlight the following: first, an increase in EBITDA of COP 0.3 trillion.

The savings on financial expenses resulting from debt repayments made in 2018 for COP 0.7 trillion and a lower tax rate of COP 0.8 trillion.

Secondly, a greater foreign exchange difference of COP 0.4 trillion due to the lower exchange exposure generated in the valuation of the group's net dollar position.

Thirdly, higher depreciation of COP 0.9 trillion related to the drilling campaign results and improvement in the asset recovery factor that increases fixed assets.

The 2019 net income before nonrecurring effects would have been COP 12 trillion, higher than the one reported in 2018 of COP 11.6 trillion.

Additional, material nonrecurring effects that positively impact net income were: first, as a result of the increase of stake in Invercolsa mentioned about a contribution of COP 1 trillion to net income was generated.

That income did not generate an associated tax and is a nonfiscal gain.

Second, as a result of the agreement with Oxy in Permian by Ecopetrol USA Inc, it is expected that this company will generate sufficient taxable income to deduct the historical tax losses of the Ecopetrol America associated to its historical exploration.

Since the United States tax regulations, contemplate that tax losses can be applied in future tax returns.

Under accounting standards, it is appropriate to register a receivable tax credit equivalent to COP 1.5 trillion, which recognizes the right that Ecopetrol will have to recover the aforementioned tax losses.

Finally, during 2019, we recognized a net impairment of long-term assets of COP 1.4 trillion before taxes, which includes 2 important market factors.

The first corresponds to the change in the outlook for short-term hydrocarbon prices, which decreased considerably compared to the previous year, impacting the upstream segment.

The second relates to evolution of market rates.

Throughout 2019, we have observed a global economic slowdown, which has been reflected in lower discount rates.

This benefited the recoverable value of the assets in the downstream segment.

Let us now move on to the next slide to see the business group's cash flow.

At the end of 2019, Ecopetrol maintained a solid cash position of COP 12.1 trillion.

Cash flow from operations, including working capital, was robust, totaling COP 27.7 trillion.

As a relevant milestone, working capital benefited from the COP 5.4 trillion in income received as balance in favor from the fuel price stabilization fund.

Cash flow from investment activities showed disbursements of COP 14 trillion, which includes the greater execution of organic CapEx as well as the outflow of resources for inorganic activity carried out during the year.

Cash flow from financing activities had outflows of COP 17.2 trillion where we highlight: First, diversements of COP 13.9 trillion distributed as dividends to our shareholders and minority shareholders in the subsidiaries; and secondly, outflows were COP 3.3 trillion for periodic amortization of principal and interest payments.

2019 CapEx execution amounted to $4.4 billion, of which 80% were organic and 20% were inorganic investments.

92% of the investments were executed in Colombia and the remaining in the group's positioning within high prospectivity basins in the United States and Brazil.

It is worth highlighting that out of the total 2019 organic investments, 79% were focused on the upstream segment and 67% were focused on the increase of hydrocarbon reserves and production.

Regarding expectations for 2020.

The investment plan considers between $4.5 billion and $5.5 billion, aimed at underpinning our growth plans.

The plan will be financed with cash generation.

80% of the investments will be directed towards the upstream segment to contribute to the target of organic production.

In the downstream and midstream segments, the investments are mainly focused and ensuring the reliability and sustained profitability of the operation of the refineries and of the entire pipeline and polyduct network.

Likewise, as part of the group's sustainability and competitive strategy more than $150 million will be invested in energy transition and decarbonization, around $129 million in the development of digital transformation and innovation projects and more than COP 1.7 trillion in strengthening social environmental investment programs, which are intended to close social gaps in our areas of operation and promote sustainable development and community welfare.

I now give the floor to the President for his closing remarks.

Thank you, Jaime.

For Ecopetrol, it is a top priority to continue advancing our ESG agenda.

On the environmental front, decarbonization is one of our priorities.

Between 2010 and 2019, we reduced CO2 emissions in more than 6.6 million tons and endorse the climate and clean air coalition, which has provided a strategy for reducing fugitive emissions and flaring aligned to international standards.

With regards to the social front, we increased our investments to COP 245 billion in 2018.

And now for the period of the 2020-2022 years, we have increased our social and environmental investments to COP 1.7 trillion.

On the governance front, we completed an orderly transition in our Board of Directors.

We also created the Innovation and Technology Committee that reports to the board.

This will help us further promote the progress towards digital transformation, as in prior years, we ratified the anti-corruption and transparency pact, which reaffirms our commitments to strict compliance with the code of ethics and business conduct.

The company ethical principles, zero tolerance for corruption and the total willingness to support government initiatives on this matter.

Please move on to the next slide to present the main objectives of our 2020-2022 business plan.

The 2020-2022 business plan fixed for the company to continue its path of profitable and sustainable growth, focusing on activities in Colombia in a highly prospective international basins.

Organic investments are estimated to reach between $13 billion and $17 billion.

This plan maintains the focus on capital discipline, cash flow protection and cost efficiencies, which will generate a solid operation cash flow estimated to be between $21 billion and $22 billion and a ROACE greater than 11%, all this with Brent prices of $57 per barrel.

The gross debt-to-EBITDA ratio will remain below 1.5%.

The carbon footprint reduction and incorporation of renewable energies play an important role in this plan.

By 2022, we expect to reach a total cumulative reduction of between 1.8 million and 2 million tons of CO2 equivalent and have 300 megawatts of renewable energy sources available for our operations.

In this period, we'll be investing COP 1.7 trillion to improve the quality of life and support business and rural development of those communities where the company operates.

All this, in addition to the contributions made by the company in terms of direct taxes, indirect taxes, royalties and dividends.

This plan for 2020-2022 period reinforces Ecopetrol's commitment to a safe and environmentally sustainable operation, protecting biodiversity and the communities in the areas where we operate and also generating value for its shareholders.

Let's move on to the next slide to present the closing remarks.

2019 was a positive year in terms of financial and operational results.

We met our goals, and we set some new records.

The first one, the highest financial results for the last 6 years, reaching a net income of COP 13.3 trillion and EBITDA of COP 31.1 trillion and an EBITDA margin of 44%.

Second, the highest reserves replacement ratio in the last 9 years, despite a 15% drop in oil prices when compared to 2018.

Third, the distribution of dividends of COP 314 per share, the highest in the company's history.

Fourth, the crude oil versus Brent price discount record of minus $5.6 per barrel on an average for the year.

In 2020, we will continue to pursue opportunities for profitable growth, and moving forward, the ESG agenda, the technological innovation and digital transformation agendas.

Finally, by year-end, we expect to share with our stakeholders, the group 2030 strategy, offering a long-term vision of the company in the face of the challenges and opportunities offered by the energy transition.

Thanks, again, for participating.

And with this, I will now open the floor for questions and answers.

(Operator Instructions) And our first question comes from Daniel Guardiola from BTG Pactual.

So basically my questions are basically focused on better understanding the 2020, 2022 business plan.

Okay.

And my first question is regarding the expected production.

I would like to know if you could share with us more details on what are the expected sources of growth that would allow the company to bring production up to 780,000 to 800,000 barrels per day by 2022.

That'll be very good if you could provide some details on that expected growth.

My second question is regarding also the business plan, where you basically mentioned that you're planning to install 300 megawatts of generation capacity, basically, renewable energy?

And I would like to know what is the expected EBITDA or cost efficiencies related to this investment?

Also regarding the same plan, I would like to know what portion of the expected CapEx is expected to be allocated into inorganic growth.

And if you could provide more details on the M&A strategy of the company?

And then last question, just very brief.

And regarding -- taking into consideration to this plan is a 3-year plan, I would like to know if you have considered if -- have you ever considered to eventually mitigate the volatility of results by hedging a portion of your expected production in the future?

Felipe here.

So in terms of the 2022 business plan, as you saw from the material, we've signaled a few things in terms of production growth, and I'll ask Alberto to comment a bit more in terms of the detail.

But basically, what we're saying is we want to see our production -- basically moving from where we are today, if you think about where we ended up last year, 725,000 barrels to a range between 750,000 and 800,000 thousand barrels.

So there's a significant increase in production levels.

And it's a combination of things.

So it's a combination of some of the fields that are coming back to Ecopetrol that are coming to Ecopetrol.

So for example, we have -- this weekend, we will be receiving the operation of Florena and Pauto, what we call the Piedemonte assets.

So that's an important source of additional production.

So that's coming in.

We also see, in particular, some new projects coming on stream, not only in the Piedemonte area, but in Cono Sur, Akacias in El Meta that will be coming in, some additional production coming on from Rubiales.

And remember that, Daniel, we don't give specific guidance on a field basis.

But I do want to provide a bit of color, additional color around some of these levels.

Secondary and tertiary recovery continued to be fundamental to what we're doing.

So a lot of investment going into that.

There is a -- an addition, which is great, and we've given some guidance on that, which is the Permian JV, Rodeo JV, which will give us this year some 7,000 to 9,000 barrels, and we'll be increasing, increasing over the course of the next few years.

You saw that or basically -- I'll share with you, we will be seeing some 90 wells, 90 wells drilled in that JV this year, 50 of them online, 4 rigs running.

So that's going very well.

That's going very well, and we see an ever-increasing sort of production.

So there is quite a few different sources of production that we see coming in.

We want to increase our presence in gas as well.

So there will be some efforts to bring more gas as part of that, you saw in the presentation, we're talking about Chuchupa, Ballena.

There will be some volumes coming from that acquisition.

So I know I've listed 8 to 10 different things.

We'll continue with a large investment in production wells that we will be drilling.

So all of that will contribute to the growth in production.

In terms of renewables, and I'll go swiftly into that.

So we've signaled that we're going to be growing for -- from what we call Auto Henderson, which is the power generation capacity that we use for our own operations.

Where we -- last year started the year with 43 megawatts that was biomass.

So the sugarcane bagasse.

And we added last year 21 megawatts from the solar, our first solar farm in Castilla, in el Meta.

We've announced that this year, we will bring 50 megawatts from CENIT, the San Fernando station.

So that will take us well over 100 megawatts.

In addition to that, we've bought 30 megawatts from a recent auction on renewables from the Ministry of Mines and Energy, and we have line of sight between solar -- between mainly wind and solar, we have line of sight of projects that can take us to the 300 megawatts.

So in terms of what this brings.

So clearly, it brings a substantial reduction in emissions.

So that's a very key driver of why we're doing what we're doing.

And I think the other thing, and we'll be able, as we move forward, provide more data on this, bear in mind that the operation from the solar plant or the solar park in Castilla has only started in October, but we're seeing a substantial reduction in the energy prices that we use for our own operation.

So it brings 2 very good things: reduction in emissions; and it's already providing us with some very good efficiencies that directly hit lifting cost, which is one of the issues that we are dealing with.

And back to your first question, as we see ourselves increasing the level of production, we will eventually need more power to move the fluids that we produce.

So I think in this sense, we've seen that our renewable strategy is very, very good in addressing both things: emissions and in terms of CapEx.

So in terms of the third one, CapEx.

So you saw that last year, we had a very large effort in terms of doing inorganic acquisitions, both in the U.S. and I've talked about the Rodeo JV, and that's the official name of the joint venture.

We did some big, big acquisitions as well in Brazil, both in terms of our exploration footprint in the Pre-Salt and in Gato do Mato.

And actually, these things that were inorganic last year are now part of the organic portfolio.

So that's the first thing we need to think, right?

We incorporate them.

But if you look at the forward plan, it's probably -- we've talked from $14 billion to $17 billion in the next few years.

I think you can sort of think about this as there's going to be $10 million to $13 billion in-country and some $3 billion to $4 billion internationally, most of that in the U.S. and in Brazil.

And I think that provides you a bit of a color or frame around where we are.

In terms of hedging, and I'll ask Jaime to provide a bit more detail, but we've done some tactical hedging at transactional level.

So very specific on -- on very specific transactions and trade deals that we've done on some specific volumes.

We've looked at having the opportunity or the tools, if you will, to an additional hedging if required.

But I'll ask Jaime to go into a bit more detail in terms of how we're viewing this from the overall sort of environment and context point of view.

Daniel, so starting with the hedging point.

In the business plan, we don't incorporate any specific assumption around hedge volumes.

That's the first thing that I would say.

So our business plan is produced under an assumption that we are capturing kind of market prices.

And having said that, we are prepared to perform hedges where we think there's a business case.

As Felipe discussed, we've done a number of tactical hedges over the last year that have worked very well, and we continue to monitor kind of fundamentals, if you will, to see if there's a case for a business case -- a case for hedging, strategic hedging.

What I would say in that regard is that our biggest exposure, of course, is Brent followed by diesel.

That's where we are focusing our attention.

And probably thirdly, I'd say WTI, given our increased exposure to Permian volumes.

That's where we're focusing our attention right now.

Currently, we don't see a robust business case to perform any material hedging on any of the 3 to give you an indicative amount.

Hedging 50% of our Brent exposure would cost us around $350 million, $380 million currently, and we believe that with our current plan and its resilience in the $50 to $60 kind of price range, there's not a clear business case to do that.

We continue to monitor this.

It could change in time, but that's where we are right now.

Lastly, I would like to refer briefly to the -- to your question around CapEx.

And I would just like to confirm that in the $13 billion to $17 billion range that we provide for CapEx execution going to 2022, there is no inorganic CapEx assumption.

So the totality of that range is organic, right?

It's underpinned by our existing plans.

The way that we think about inorganic, from our financial standpoint, is that we have extra capacity, given our cash generation and given our current gearing ratio, to fund transactions that could go anywhere between $2 billion to $4 billion, if there was a solid case to do so.

That is not included in the business plan at this stage simply because we are not committing to specific M&A transactions.

We look at those on a case-by-case basis and always with a view of ensuring value accretion as we did last year.

Our following question comes from Pavel Molchanov from Raymond James.

This is Muhammed Ghulam on behalf of Pavel Molchanov.

So you guys have mentioned that there is regulatory approval from the Council of State to begin some small-scale shale activity.

Are you concerned that this -- are you concerned about the risk that this activity will create more tension with the public and perhaps more social disruptions, even beyond what you guys have experienced in recent years?

That's it, Mohammed?

Do you have any other questions?

Do you want to put them to us and then we'll take them?

Or...

Yes, sure.

And then other one on the offshore partnership with Shell.

What would you need to see before approving development of any of the offshore discoveries?

Is it a matter of just higher prices or is there something else?

Okay.

Good.

So Muhammed, thanks for being here.

Thanks for being in the call.

So I think it's good to provide a bit of context around the unconventional development in Colombia.

So the first thing is that efforts to develop the unconventional resources or potential that we think or in our view, exist in-country, have been going on for more than 10 years.

So there is a lot of, in this sense, work that has been done, lots of discussions that have happened in support of doing a potential development for unconventionals in country.

So the second thing of context is that the government issued a strategy in which there is something called proyectos piloto investigación integral.

So these are pilot projects of comprehensive investigation.

And I'm sort of liberally translating a bit the meaning in Spanish.

And this recommendation to do the initial approach to the assessment on the potential and the feasibility from a socio-environmental point of view is the result of a commission of experts that was appointed by government, a lot of them from social sciences, from environmental sciences that did some work almost a year ago.

So this group of experts, 13, some of them international experts, basically came out with a recommendation that said the right way to do this and to assess from a scientific point of view, the feasibility of doing unconventionals in Colombia is through these pilot projects.

So that's where we are.

And following that, there were some demands, legal demands against unconventional development in Colombia and the Council of State or Consejo de Estado, which is the highest administrative court in country, ruled out that said, yes, we cannot do full-scale or full-blown unconventional development in countries, but you know what, we can do the pilot projects.

So that's where we are.

And I think it's important to put that context in place.

So in terms of tension, what you mentioned in tension.

Remember that the country has moved from a very long internal conflict to something where we, in most of our regions of operations in the country -- and remember, we operate in 330 of the 1,100 municipalities in country.

So we're everywhere in Colombia.

We've seen a substantial improvement in operating conditions.

With the exceptions of a few areas, 2 of them notably in the borders with Ecuador and Venezuela, we've seen a dramatic improvement in terms of our operating conditions.

So from that point of view, we're quite comfortable.

So I think, overall, and this is probably not unfamiliar to some places in this continent and in Europe and in other parts of the world where there is a concern from younger people in terms of opportunities, the environment, climate change and the likes.

And I think what we've said, and I'll just reinforce that here, first, we don't need to do the unconventional development quickly.

We need to do it well.

And we know how to do it in a way in which we're transparently interfacing with the communities, with the governments, with the unions, with academia, with everybody else.

And so that's what we'll do.

And we're committing to do those pilot projects when the regulation and the legislation is ready and the government is working on that.

Once that regulation's published and the -- subsequently, there's going to be detail from a technical, environmental, social point of view, we'll be able to submit our request for environmental licenses and do the pilots.

So I think we're quite comfortable.

Obviously, there's a lot of work in terms of specifically working with those communities.

Remember, the overall general area where the pilots would be developed is the same area where we've had oil and gas industry for the last 101 years.

So we're quite comfortable near Barrancabermeja where we have a strong presence, so we'll basically move on in that direction.

I know I've given you a very long answer, but I think it's important to provide some of the context in terms of where we are and just finalizing with that.

We're committed to do the pilots and ensure that we can assess and understand and decide as a country on the potential of unconventionals, which we think is important.

Remember 2 things: the most costly energy is the one that you don't have; and it's fundamental that we continued to do everything that we need to do and that we can do to ensure there is energy securities not lost in-country.

Offshore partnership with Shell.

So we announced that recently.

We're very, very and extremely pleased with that.

A world-class company that brings not only their expertise on ultra-deepwater developments of this nature, but also around gas.

And they're clearly a leader around the world in terms of development and marketing of gas.

So what needs to happen?

The agreement that we signed with Shell basically allows us to drill an additional appraisal well and DST the well.

So we will have a dynamic production data from the well that will inform all the work that we need to do around the definition of the development concept for that area.

Remember that these discoveries were done in the last 2 to 3 years, that the last wells were drilled in '17.

We at Ecopetrol have said that we envisage a potential of basically around the same as we have in reserves of gas for the year.

We have a 3.8 tera pies cúbicos.

We have 9.8 -- 3.8 Tcf, I'm translating into English.

Sorry about that, Muhammed.

And we think that this area could have resources of some 3 Tcf.

Again, as I said, we need to drill the appraisal well, we need to DST the well and that will provide a lot of data in terms of how do we actually approach the development.

Our next question comes from Frank McGann from Bank of America.

Two questions, if I could.

One, just in terms of diluent.

I was just wondering how low you think the usage can get if you have substantial or material downside from where you are today?

And secondly, in terms of the tax rate in the fourth quarter, I know there was a lot going on in the quarter.

But -- and a lot of adjustments related to the write-off and the acquisition and such.

But just -- what drove the tax rate to be positive?

Frank, thanks for the question.

In terms of diluents, what we are seeing starting in 2019 is a reduction in terms of the dilution factor.

We went from 4.8% to 4.2%.

And what we are seeing in the future starting in 2020 is new projects being implemented in terms of co-dilution using LPGs instead of naphtha and then also implementing some heating projects in the Ocensa pipeline.

So at the end, by 2021, we are expecting to see a dilution factor under 4%.

Frank, this is Jaime.

I'm going to talk briefly about the tax effect -- the effective tax rate.

I think there's 2 angles on it.

There's a full year angle, and there's the 4Q angle.

When you look at it from a 4Q perspective, if you're trying to compare 4Q 2018 versus 4Q 2019, you did have a number of extraordinary items.

4Q 2018, the tax effective -- the effective tax rate was 28.4%.

We actually ended up in 4Q '19 with a negative effective tax rate of minus 20%.

The bulk of that is the deferred tax rate that we introduced for the U.S. business on occasion of the Permian transaction.

That's about -- that has an impact of about 41%.

There's also another impact associated to recognizing the fair value of Invercolsa, which is the distribution -- the gas distribution business that we're now treating as a subsidiary within our financial statements.

Those are the 2 big items.

When you look at it from a full year standpoint, we go from an effective tax rate of 36.9% in 2018 to 24.1% for 2019 on a full year basis.

And the way to bridge that movement, you would have the activation of the deferred tax in the U.S. representing about 9% of the delta.

You have a 4% associated to the reduction in the nominal tax rate here in Colombia due to the financing law.

You have about 2% related to the recognition of Invercolsa's fair value and you have another about 10% associated to stronger results in Reficar, but you may recall that because Reficar has an advantaged tax structure, it actually helps and contributes to the tax effective rate -- to the effective tax rate of the group to the extent that it has better results.

Those are kind of like the big 4 components of the bridge.

The following question comes from Julia Park from UBS.

I have 2 questions here.

First is in terms of capital allocation.

We see the company with a solid cash position but with a strong CapEx guidance for 2020, a 53% increase from 2019.

How can I see dividends going forward?

Also in terms of reserves growth going forward, most of the investments are placed in Colombia.

However, we're wondering if we could expect significant increases coming from inorganic growth.

Also, will the company be able to replace 100% of its production through organic growth?

And the second question is in the downstream segment.

Last year, we have seen use of the government trying to lower the deficit in the fuel stabilization fund.

While we haven't seen any recent news on that, we think this is a potential risk for the refining margins.

How do you see this matter going forward?

I mean how could the government lower the deficits of the fund without hurting produces margins?

Do you think changing the price policy from the export parity to import parity would be a potential solution?

Thanks, Julia.

I'll take the first one and then I'll ask Tomás and Jaime to comment on the second one.

So the first thing I'll start with is some of the things that we did last year or the things that we did last year that were inorganic.

So the Rodeo JV in the Permian and some of the things that we did in Brazil to enter the Pre-Salt will now be treated as organic.

So I think that's the first thing.

So some of those efforts that we did inorganically will become organic as we move forward.

If you think about forward CapEx and bear in mind, we've done everything at $57 per barrel, but we need to be cognizant and acknowledge the uncertainty.

I don't think it's still to a massive volatility, but clearly, uncertainty that we're seeing in the last few days around prices, and we'll see where we end up.

But at $57, we've poured into the plan, the 2020-2022 plan some $14 billion -- or $13 billion to $17 billion.

All of that's organic.

So I just want to highlight that and $10 billion to $13 billion will be invested in-country, in Colombia, and $3 billion to $4 billion will be in the U.S. So that's basically the split in terms of how we see the CapEx.

In terms of the dividend going forward, which is the other bit in your question, we have an existing dividend policy that basically talks about distributing 40% and 60% of the adjusted net income of the company in a specific fiscal year.

But I'd like to add a bit of color here to some of the questions that we've heard before, even in the prior call.

So in order for us to move forward with a recommendation on the dividends, this part of being at 40% to 60% range of the adjusted net income is fundamental.

But the Board of Directors also assesses things like the macroeconomic environment, which is why I was talking about the price deck that we are using going forward for our plan.

But we also need to consider things like the ongoing uncertainty around coronavirus in China and how it's spreading and potential impacts on demand and supply.

So that's clearly something that we'll look.

And the other fundamental thing that we need to look at when we're looking at dividends is how do we see cash projections in terms of achieving our strategy goals and our growth plans.

And you saw that we've talked about growing production, growing investment.

So all of that is considered in-depth when we talk about recommendations for dividends and distributions.

And I'll end up saying, soon, you'll hear about specific recommendation on the dividend plan.

So that's going to happen soon.

And that will be put into consideration of the AGM that happens at the end of March, and it's the AGM that will have the accountability of the approval of that dividend proposal.

So I just wanted to provide a bit more color around specifically the dividend.

Second, which is the 100 reserves replacement going forward.

And I think you were mentioning the organic side of the equation.

I'd just like to step back for a bit and say, in 2017, '18 and '19, with 126% to 129% and 169%, we've been able to replace 100% of our reserves without benefiting or being impacted or we've managed to offset the impact of prices, and I think that's very important.

So internally, as we think about it and we've talked about this publicly as well, we want to be able to replace 100% of our reserves going forward.

We didn't do that in '15 and '16.

So I think going forward, we need to think that we've demonstrated we can move very quickly in the inorganic side of things and bring them on stream.

We were giving some guidance around our Rodeo JV, where we've -- this year alone, we'll have Ecopetrol net production of 7,000 to 9,000 barrels.

Last year, we booked 164 million barrels of reserves.

So that's going very well, and we see more coming from that as we move forward as well as some of the investments in Brazil.

Gato do Mato may bring some 90 million barrels of contingent resources going forward.

So I think it's a combination of both things.

In terms of organic, inorganic.

And we've demonstrated we can move quickly and swiftly in the inorganic, incorporate that into the portfolio.

So we'll be looking at all the potential opportunities and avenues to continue to ensure that we grow our reserves.

And I'll end up saying in the last few years, we've moved from below 7 -- in terms of R2P, 7 years to almost 8, 7.8 years.

So we're moving quickly and will continue to do so.

In terms of the stabilization fund, and I'll ask Jaime and the team to comment on that.

Currently, we have an export parity, which is the -- if you look at the frame of how prices are actually constructed in-country.

Eventually, things will move on.

The government has been very vocal about the need to basically limit the swings that the stabilization fund has without impacting prices for the end user.

So we see this will move on.

And as a company, we'll be ready.

When prices or the price link to an indicator, big flat indicator or import parity, competition will increase, and we'll be ready to cope with that.

Jaime?

Julia, just to add a bit of color to the frame that Felipe has provided.

Clearly, any change associated to formulas or at least that the changes that have been discussed with the government and that the government has shared with us that they're contemplating, are changes that have a positive impact on our business.

Basically, the 2 -- the proposals that are being discussed.

There's one associated to moving to flat pricing in products like diesel and jet.

There is another proposal around moving to import parity around gasoline.

In both cases, they actually improve the remuneration that is recognized to the producer.

There are no scenarios contemplated at this stage that actually affect negatively the compensation that is provided to producers.

So this would be an upside to our business plan.

Directionally, and I would like to emphasize the word directional, the relative impact that this could have on our margins could be between $1 and $1.50 per barrel, depending on the product, and depending on the formula and how that formula is designed.

So -- and obviously, to the extent that this occurs, in time, this will certainly -- probably enable further investments in the downstream segment.

And for sure, and I think this is the primary motivation that the government has on this, it would also stimulate competition, particularly in certain geographical areas where there are supply challenges.

Our next question comes from Camilo Roldan from Davivienda Corredores.

Felipe and all the Ecopetrol team, I have just one question.

Regarding the imports of oil and products, basically, knowing that in 2019, it was a typical year where we saw that an increase of these imports due to the refineries maintenance.

And for the 2020, are we expecting to continue having the same behavior that we saw in the third and the fourth quarter?

Or are we expecting to increase due to, as you mentioned, in the Spanish conference that we are going to have a small stop in one of the refineries?

Thank you, Camilo.

Yes, as we mentioned, I'll expand a little bit on what we talked about in the Spanish call, yes.

We were impacted in 2019 by 2 major turnarounds that we had in refining.

We had -- in each refinery, we had a major turnaround in hydrocracking in Cartagena and diesel hydrotreater in Barrancabermeja.

These were all diesel -- the major diesel producers in the country and obviously would have an impact on the import balance.

Looking ahead to 2020, as you know, we have plans for first quarter and fourth quarter turnarounds, which is normal in refining.

We have a, as I mentioned in the Spanish call, we have a diesel hydrotreater turnaround going on in the first quarter -- that will be going on in the first quarter, that will have the an impact slightly on that import balance.

But it's all being done in preparation for the fuel quality improvements that we're looking at for end of year and continuing with that fuel quality improvements in line with discussions with the government.

So we're pretty much have a standard turnaround schedule for 2020.

We have a cluster turnaround in the fourth quarter that's not related to diesel, and we do have an impact in the first quarter of this year due to some turnarounds that we have.

Probably a good time to mention that we have -- in the first quarter, we have had an outage in one of our hydrogen plants that has impacted diesel production in the first quarter as well because we've had to have our hydrocracker down.

So basically, hydrogen is a critical input, obviously, to hydrocracking, and we had a downtime in one.

So we're mentioning that, that this will be an impact in the first quarter that will impact diesel.

But it's not related to a major turnaround in Cartagena.

It's related to another plant that went out and is having an effect on the hydrocracker.

Our following question comes from Juan Pablo Diaz from Porvenir.

I have 2 questions.

My first question is regarding the differential in the crude basket.

After the reduction shown in 2019, what do you expect the evolution of this differential to be throughout this year?

And what would be the strategy to maintain or reduce it?

And my second question is regarding the EBITDA margin, which has been showing increases in the last 3 years.

And in last year, it presented a reduction.

How do you expect it to show growth again, if you do, with new strategies to implement new efficiencies or improve existing ones and considering that enhanced recovery expenses will continue to be present?

Juan Pablo, yes, I'll take the first one, and I'll ask Jaime to talk about the second one.

So I think it's always important to remember, in last year, as we reported, we had the record of in terms of the lowest differential for our crude basket.

So it's important to remember that we have positioned ourselves as a reliable source of heavy crudes in terms of, obviously, the volumes, the quality and the timing of how we actually provide these crudes to the market.

We have adjusted in line with strategy.

We have adjusted the destinations of some of those crudes.

So in average, last year, I think it was 48% of our crudes went to Asia.

And over the last 3 months of the year, it was 53%, 54%.

So we've been very good at very quickly adjusting.

Having said all of that, and especially in light of what's going on with the coronavirus, there's already a reduction in some of the runs of refineries in China, particularly.

But again, this is something we'll need to monitor.

We'll need to understand where it's going to go, potential impacts.

I was mentioning earlier in one of the other questions that as I was building on what was -- I was saying that we are a reliable source of crudes.

Our crudes have become part of the base runs in the refineries.

So even though refineries in China have reduced their runs, we have not seen an impact in our exports.

We have direct relationship with those buyers with the refineries themselves, and we will continue to strengthen and work through that relationship.

But I think it's early days.

I think that the world's just every day and every hour sort of getting a lot more information awareness of what's going on, how this eventually will spread?

How deep geographically and where and what's the impact?

So we'll keep our radar sweeping.

We'll ensure that we are quick to react.

But I just wanted to say and that's why we're not providing any guidance, directionally, I think the spreads will soften, the differentials will grow a bit.

But we see ourselves as an advantaged supplier of heavy crudes, in particular to that part of the world.

Jaime, if you can take the second one.

Juan Pablo, yes, effectively, EBITDA margin dropped slightly, probably year-on-year.

We did have a drop of around 1.5% when you compare both years.

There are 5 factors that explain that drop in the percentage margin.

The first factor is that -- is actually when you see a bit the composition of the incremental production that we're bringing online, as you know, we are growing production in the E&P segment.

However, the makeup of the field is changing in time.

And those fields at times have either different royalty regimes, in some cases, and in other cases, they actually have different margins associated to their operation.

As that mix is changing in time, it is having some effect in the relative margins of the incremental barrels that are added.

I'm going to go in a minute, how do we see that going forward to 2022?

The second point that affected EBITDA margin last year was around the diesel imports that we made.

I think Tomás has explained that in a lot of detail today.

It's due to program maintenances that we performed last year and that's something that we don't see as something that will sustain over time.

What occurs there is to the extent that we are importing diesel as opposed to using ours, it weakens the relative margins that we see around that.

And it increases costs, variable costs, in particular.

The third component that affected EBITDA margin was, I would say, generally, the difficult environment experience in the downstream.

As you know, particularly the second half of the year saw weakened differentials around gasoline and naphtha, in particular, and a bit of fuel oil, and that is reflected there, too.

Those -- I think those 3 components are the biggest contributors to that.

There are 2 other specific events, I'd say.

There were a number of extraordinary operational expenses that we reflected in 4Q that had a bit of a contribution on the general balance, and last but not least, and something that is documented in the full report that we provided, we did make an adjustment in the way that we were recognizing revenues associated to the ship or pay that we have with Frontera Energy in the midstream that is related to the progress in the legal case that we have with them.

As time progresses, we have been reviewing our provisions and our accounting treatment in that matter and we believe that whilst our legal position is unchanged, given that there is an important balance accumulating with Frontera in that regard, we believe that there is a potential risk associated to their ability to pay and have therefore updated our recognition of that revenue accordingly.

Those are the 5 biggest components.

As we look forward from a plan guidance, we believe that much of that -- of those effects are normalizing over time, and we believe that in the '20 -- in the 2020 to 2022 time frame, we are going to be moving in that range of 44% to 47% EBITDA margin.

This concludes today's Q&A session.

I will now turn the call over to Mr. Felipe Bayón for final remarks.

Well again, thanks, everyone, for participating today in this conference call for 4Q and 2019.

We are very pleased with the results that we've provided the market.

I'd like to take the opportunity to thank the 13,000 direct employees that work in the group, say, everybody that helps us through the contracting side of things.

In particular, I want to thank you for being on the call, for your questions, for following on Ecopetrol, and providing feedback that helps us better communicate, better improve how we actually relate to yourselves, understanding what are the points of interest and some of the things that we need to further do deep dives and provide more color around.

So thanks again for being on the call.

We're very pleased with the close of the year and we're also satisfied that we could provide guidance and a frame for the 2020-2022 business plan.

Thanks and have a great day.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.