Pampa Energía S.A. (PAM) Q3 2019 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and thank you for waiting. At this time, we would like to welcome everyone to the Pampa Energia Third Quarter 2019 Results Conference Call. [Operator Instructions] After the Company's remarks are completed, there will be a question-and-answer session. [Operator Instructions] Before proceeding, let me mention that forward-looking statements are based on beliefs and assumptions of Pampa Energia's management and on information currently available to both companies. They involve risks, uncertainties and assumptions, because they relate to future events, and therefore, depend on circumstances that may or may not occur in the future. Investors should understand that general economic conditions, industry conditions and other operating factors could also affect the future results of Pampa Energia, and could cause results to differ materially from those expressed in such forward-looking statements. Now, I'll turn the conference over to Lida Wang, Investor Relations Officer of Pampa Energia. Ms. Lida, you may begin your conference.

Good morning, everyone and thank you for joining our conference call. I will make a brief summary of various business segments reviewing the quarter's key figures and the latest events since our last call in August. Our CFO, Mr. Gabriel Cohen is here for the Q&A session. Before we get begin, we want to remind to you that Pampa adopted the US dollar functional currency. Therefore, transactions are recorded in US dollars, since January of this year for the comparative period of 2018. According to IFRS, figures are reported in pesos adjusted by inflation as of the year-end 2018 and show in US dollars at closing effects. This comparison might be difficult to read. Therefore for a like-to-like -- like-for-like basis, we are considering nominal figures reported last in Q3 in nominal terms and converting into dollars at an average FX. In this case, the peso-linked subsidiaries such as the utilities, they continue to report on the peso functional currency. So the figures are adjusted by inflation and shown in dollars at September 2019 closing effects. In order to analyze their performance organically and to be in line with the reporting, the comparative figures in pesos adjusted by inflation until the end of 2019 and show in dollars at closing FX. So having made this clarifications, we can start. On slide 5, we can -- we wanted to make a quick stop by reviewing the quarter's financial highlights. Revenues fell year-on-year by 21% mainly because of the 36% devaluation of the peso affecting our peso-linked businesses like Edenor, Transener, TGS, in addition to lower gas prices and FX freeze in E&P -- oil E&P and reduced legacy remuneration of power generation. These negative effects were offset by the commissioning of new capacities since May 2019, adding more than 300 megawatts to the grid and higher gas production. Quarter-on-quarter revenues also decreased by 24%, mainly explained by the high peso depreciation affecting our regulated utilities, lower exports and production at our customs facilities, partially offset by winter season pricing for legacy and gas reference price optimism, the new capacity commission since last May, and higher gas production. EBITDA also fell year-on-year by 5%, mainly explained by lower hydrocarbons prices, reduced legacy remuneration for our power plants and devaluation effect on our price inflation adjusted utilities, partially offset by the commissioning of new power units, the acquisition of Ensenada de Barragan power plant, higher gas production and dilution of peso-linked expenses due to the deval. Quarter-on-quarter EBITDA increased by 10%, mainly because of new power units explained above and full quarter of Ensenada de Barragan, highly -- a higher legacy remuneration and higher gas production and prices because of winter season, offset by peso depreciation and FX freeze at oil prices. As we show on the right below, oil and gas share represents one-fourth of Pampa's consolidated EBITDA, given the current pricing environment at the E&P, while electricity led by power generation takes the other three-fourths. Also it is worth highlighting that almost 70% of Pampa's consolidated EBITDA is dollar-linked, mainly from gas and power. Moreover, as shown in the chart left below, in the third quarter of this year, our CapEx decreased 3% compared to the same period of the last year, mainly explained by lower pace in power generation expansion CapEx, as in Q2, we commissioned PEPE's wind farms and Genelba Plus new gas turbine, which is a key part of our CCGT ongoing projects, in addition to lower Edenor's CapEx due to the devaluation. If we compare to the last quarter, CapEx decreased by 29%, mainly driven by the peso deval at Edenor mostly -- that mostly have peso CapEx, deceleration of peso -- power expansion CapEx due to the last stages of (inaudible) project and the end, the finish of PEPE wind farms, offset by increased gas production mainly at El Mangrullo block. So as you can see on slide 6, in the third quarter of 2019, we reach an adjusted EBITDA of $270 million, 5% less compared to the -- an EBITDA of $283 million recorded in the same period of 2018, mainly explained by decreases in electricity distribution, oil and gas, holding and others, partially offset by increases at power generation and petrochemicals. Moving to Power Generation segment. During the third quarter, we posted an adjusted EBITDA of $131 million, 19% higher than 2018, mainly given by the recently acquired Ensenada de Barragan power plant that we co-own with YPF, and we add at our 50% equity stake. Moreover, it also contributed to our newly commissioned wind farms with PPAs and Genelba Plus new gas turbine, as well as the devaluation impact on our peso-denominated cost and better Energia Plus margins. These effects were partially offset mainly by the reduction on legacy thermal remuneration as per Resolution I, effective as from March 2019, by which capacity payment during spring season of September was reduced around 40% in dollars for Guemes steam turbines and Piedra Buena, as they are the lowest dispatch rate units in our portfolio. The impact on our highest load factor units on the legacy capacity, that's Genelba and Loma combined cycles is smoother but during September, which is the off-peak season it got 20% lower. Quarter-on-quarter winter season pricing for legacy PEPE wind farms with B2B PPAs and Ensenada Barragan contributed to the 31% increase in EBITDA. Generation was 16% higher on a year-on-year basis mainly due to the gas turbines at Genelba Plus thermal power plant that are part of the closing to combined cycle project as well as better load factor at the combined cycle legacy -- combined cycle at Genelba, higher dispatch at Loma La Lata because we managed to get the gas and therefore competitive variable production cost at a CVP so they get dispatched plus higher generation coming from the wind farms, which ranks senior in the dispatch priority because its variable cost or CVP is close to zero. These effects were partially offset by lower load factor at Guemes, Pilar and Piquirenda from our power plants caused by their higher CVP from the partial recognition of imported gas even higher than in the winter season. Therefore, placing them behind in the dispatch priority in the grid plus we've got lower dispatch required at Ingeniero White and Piquirenda thermal power plants, because their variable costs was not competitive vis-a-vis wind generation in the South. Quarter-on-quarter power generation increased mainly because of the higher electricity demand in the grid because it's during winter season. In addition to new thermal and wind units, partially offset by lower dispatch unless at lesser competitive thermal power plant. The availability rates in the third quarter was outstanding at 95% with installed capacity of 4.8 gigawatts. That includes the operation of recently acquired Ensenada Barragan thermal power plant, similar to the 94% achieved -- availability achieved during the same quarter last year and also similar quarter-on-quarter. Regarding the expansions we have in the pipeline, we are currently in the final stages of the closing to combined cycle of 383 megawatts at Genelba. As you can see in the picture on slide 8, last June we increased current gas turbine number three capacity by 19 megawatts and commissioned new gas turbine number four for 188 megawatts. They are billing as legacy until the closing to combined cycle begins operations. However, in mid-October we experienced heavy rains and a flood caused damages to the facilities causing some delays, but we are optimizing the cycles commissioning procedure, so we expect to achieve COD expected in Q2 2020. On the other hand, as you can see on slide 9, by the end of last June, we jointly acquired with YPF the thermal power plant Ensenada de Barragan with an installed capacity of 567 megawatts running a PPA until 2022. It has an expansion project to close the cycle increasing 280 megawatts more with another PPA for 10 years with CAMMESA. By the end of September, the joint venture company executing an EPC agreement with (inaudible) but one Genneia of the -- once the engineering of the initiation is done, the work's kick-off is subject to Pampa and YPF's decision. Regarding the existing debt of ENARSA for approximately $229 million at the end of August, the joint venture company agreed improving repayment schedule and lending conditions subject to the finish of the expansion by the end of 2021, if all commercial conditions prevail. Moving on briefly to the Distribution segment, which was reviewed by our CFO at Edenor, Mr. Leandro Montero yesterday in their earnings call. As shown in the slide 10, during the third quarter 2019, the EBITDA remained similar to the same period of 2018 amounting to $59 million in the quarter, mainly because the FX variation was higher than the own distribution costs update a.k.a CPD, which is overweighted in the salary index that also lacks the CPI and the PPI. In addition to lower demand and higher energy losses, these effects were partially offset by devaluation impact on labor and peso-linked operating costs, lower penalties due to the liabilities regularization agreement executed in last May, as a result -- and as a result lower penalties of Edenor's investments to improve quality of service and collection of retracting instalments and Social Tariff costs that did not happen in 2018. Year-on-year, during Q3 2019, we experienced lower demand of electricity by 5% due to mild weather downturn in the economy activity and price demand elasticity. Quarter-on-quarter, the demand improved because of the winter season. Energy losses reached 23% rate in the third quarter of 2019, 265 basis higher than the 20% for the same period of 2018 and 390 basis above last quarter identified in residential end users especially low-income users that do not have access to the gas distribution grid, partially offset by lower volume of energy demand. We are targeting end users that steal electricity from us by performing market discipline actions and installing customized pre-recharged meters. Therefore, we are increasing our customer base, but this is being offset by plugging off of SMEs and large users due to the GDP recession. Energy costs decreased by 21% in dollars year-on-year due to the peso depreciation, offset by the gradual subsidies removal, but this is still -- have subsidized of the full cost of the electricity. The cost of electricity surpassed for our users. Moving on to the new update in the segment, in mid September 2019, Edenor agreed with the federal government to keep building the tariff schedules in force. Therefore the 19% CPD update, as well as seasonal price for electricity, will both differ. However, Edenor was allowed to keep collecting the retracting instalments for delay application of the previous tariff adjustment in March 2019. As you can see on slide 11, Q3 2019, in the Oil and Gas segment, we posted an EBITDA of $52 million, 32% lower than the Q3 2018, mainly because it is still reflecting the downward trend in gas sale price since August 2018, lower oil prices mainly due to the FX freeze. this measured by the government and higher gas treatment costs at El Mangrullo, partially offset by 13% higher production of gas driven by the vertical integration with power generation and lower royalties and expenses that are peso-linked. On the other hand, quarter-on-quarter, EBITDA was similar mainly explained by the higher gas production and better pricing and seasonal demand starting on June, partially offset by lower oil prices, because of the FX freeze. Our overall production in Q3 2019 increased 11% year-on-year and 3% quarter-on-quarter, reaching to nearly 50,000 barrels of oil equivalent per day of which 90% is natural gas. On the oil side, production level year-on-year decreased 10% reaching to 4,800 barrels of oil per day. But quarter-on-quarter, remained similar mainly because the lower well completion activity at El Tordillo and no contribution from Chirete in the quarter, this is a block that is in process for exportation. During Q3 2019, the crude oil prices sale price decreased year-on-year by 26% and quarter-on-quarter by 18%, reaching $49 per barrel, mainly because the government imposed an FX freeze at all domestic prices as of August 9 for 90 days, and Brent reference of $59 per barrel, selling 20% lower than it should have been. 61% of our production is Escalante heavy oil that is sweet and given the current clean fuels trend, it narrows the Medanito prices. Please turn to slide 12 where we want to explain in deeper detail the situation in gas. Regarding the gas production, the quarter reached an average of 270 million cubic feet per day, 13% increase year-on-year and 3% increase quarter-on-quarter, mainly explained by the production increase at El Mangrullo, a block in which gas evacuation capacity was expanded since the last year end and is fully operated by us. By September 2019, the gas production level of El Mangrullo reached 155 million cubic feet per day, 60% higher than in September of last year and contributing almost 60% of our overall gas production. This positive effects were partially offset by lower production in other gas-bearing blocks because of lack of visibility on sale prices, which was affected by excess of supply driven by the disruption of shale gas developments, partially -- specifically backed up by the Unconventional Gas Plan Resolution 46, and especially during the winter season bottlenecks at the main transportation pipelines. This effect negatively impacted on Rincon del Mangrullo block with a lower drilling rate and natural decline, and a minor decrease at Rio Neuquen and Aguarague blocks. In the case of Sierra Chata, it remained similar production due to the completion of two recent wells in Q3 2019. During third quarter, our accrue weighted average sale price was -- for gas was $3.3 per million BTU, 26% lower year-on-year and slightly higher than last quarter, mainly due to the reduction on the reference price for gas fire at power plants and gas tenders on an interruptible basis conducted by CAMMESA. Since June, gas prices rebounded as it marked the beginning of the winter season with a 36% increase in dollars at power plants reference price by CAMMESA and higher spot price due to the seasonal demand. But since September, it returned to the offtake seasonal prices reflecting excess of capacity -- excess of supply and transportation bottlenecks, also impacting negatively the commercialization in Industrial segment. The fuel procurement for our power generation helped to recover the gas production levels. We are testing in almost all our production there. So it does not improve pricing, we cover our breakeven cost and it helps to have a certain uptake specifically during weak demand periods and to monetize some synergies between power and gas businesses. As you can see on slide 12, the average gas prices that we recorded on demand, have been plunging since second half of 2018 falling to the lowest point in years and hardly covering the country's marginal breakeven cost. Winter season picked up prices, but as evidenced in the past, domestic production was not enough to cover the domestic gas demand needing to cover roughly 20% deficit of gas consumed in winter season with gas imports from LNG and Bolivia, with much higher prices than those paid to domestic producers. Moving on the new sub in the segment, on August, the Undersecretariat of Hydrocarbon and Fuels approved the terms and conditions to explore gas to Chile on a firm basis during the off-peak season. In this sense, Pampa was granted a permit to explore gas on our production in Neuquina Basin to ENAP in Chile for a maximum volume of 21 million cubic feet per day at a price of $3.1 per MBTU, that is net of export duties and transportation costs. Additionally, exploring companies should compensate the higher cost incurred by the power grid due to the use of alternative fuels like LNG or fuel for power plants supported by the government. Regarding the gas we owe to the residential segment, there are three news affecting Pampa and TGS. First, regarding the tariff flattening for winter consumption, we estimate that as of September, receivables collectible by Pampa and TGS will amount to roughly ARS48 million and ARS1.3 billion, respectively. But no regulation was issued establishing the payment. Second, the FX difference on natural gas treated between April last year and March this year, that was said to be collected from the Federal government instalments as from October, Pampa adhered to this procedure and estimated receivables at ARS966 million. But the collection is pending as of today. Finally, the gas regulator decided that the FX variation of natural gas prices and TGS cost variation update should have been granted in October 1, 2019, both to be deferred to January 2020. Before I move on from Oil and Gas, I wanted to give you a quick update of our operations during the third quarter of 2019. 26 wells was drill and 23 wells were completed. Our focus is the development of blocks with tight gas reservoirs. During Q3 2019, seven tight gas wells were drilled at El Mangrullo, which is very important for the maintenance of the record production in the block. We also completed two horizontal tight gas wells at Sierra Chata as I mentioned before. During August 2019, tow shale gas wells in Vaca Muerta were completed at El Mangrullo block, both with horizontal extension of 8,000 feet with two different landing points using super frac technology, with 36 fracturing stages per well using 4,500 fracs of proppant per stage turn to 100 tons of proppant per well. The results of the completion of these wells, which are still in testing phase, are very promising producing at expected rates over 400,000 cubic meters per day since October 2019. Another important milestone was the drilling of a shale oil well at Rincon de Aranda targeting Vaca Muerta during Q3 2019, an exploratory block operated by us with 55% equity stake and we partner there with Total. The well has horizontal extension of almost 7,000 feet, and currently, we are carrying out the final completion works thus ready for testing phase at the end of the year. In Petrochemicals, we posted an adjusted EBITDA of $3 million during the third quarter of 2019, higher year-over-year and higher quarter-on-quarter, mainly because of higher reforming price spreads, lower peso-linked cost due to the deval, plus lower cost of gas, given the market negative trends and virgin naphtha purchased domestically instead of importing. These effects were partially offset by lower styrenes demand and lower spreads. In operating terms, total sales volume of our Petchem segment in Q3 2019 decreased 12% year-on-year and 22% quarter-on-quarter totaling 75,000 tons, due to lower exports and closing of ethylene and BOPs plant, offset by higher SBR domestic sales. Finally, our Holding and Other segment presented an adjusted EBITDA of $25 million in the third quarter of 2019, 22% lower year-on-year, 38% lower quarter-on- quarter. This is mainly due to the lower EBITDA adjusted by our ownership from our affiliate TGS and Transener, because of the peso devaluation and that outpaced cost variation adjustments, in addition to lower income from fees collected at holding. I'm going -- only briefly review TGS as they just had their earnings call last Friday. TGS' EBITDA adjusted by our direct and indirect stake of 25.7% contributed to Pampa $18 million in the quarter from implicit total of $71 million, 36% lower than Q3 '18 mainly due to the FX variation, higher than the last granted PPI that covers cost variation for the regulated gas transportation business, the drop in reference prices denominated in dollars for NGLs, lower natural gas process volumes because of the lower ethane sales due to the Dow Chemical technical outage, which was normalized in October, partially offset by lower cost of gas per million BTU. In relation to the midstream project of the Vaca Muerta pipeline, the northern Tranche for 35 miles was finished connecting the Rincon la Ceniza field with the southern tranche of this pipeline. So far, 85% of this gathering pipeline is commissioned. Regarding the other pipeline, the Main Gas Pipeline tender, the government postponed the opening of feeds until 2020, March 2020. Moreover in October, TGS' Shareholders' Meeting approved the distribution of our dividend consistent in 29.4 million common shares in treasury and a cash dividend to offset taxes if applicable. As for Transener, EBITDA adjusted by our indirect shareholding of 26.3% contributed $10 million in the third quarter from implicit total $47 million. This is 4% higher than the same period of 2018, mainly because of Transener got their corresponding tariff increase of 19% in August 2019. But in August 2018, the scheduled tariff increase was delayed to November in the Q4. Regarding share buybacks, so far we acquired 7.5 million ADRs of which in October of this year, 6.1 million ADRs were approved to be canceled by the shareholders meeting. Because of the market volatility and the difference between the value of the Company assets and the quarter price of Pampa in the stock exchanges, we can see repurchasing our own shares one of the best investment accretive actions toward shareholders that we are undertaking. Therefore Pampa's Board approved the fifth share buyback program for $50 million with a price cap of $14.5 million per ADR. in terms of net income attributable to the owners of the Company, Pampa reported a consolidated gain of $160 million in the third quarter of 2019, whereas in the same period of 2018, a loss of $128 million was recorded, mainly explained by lower accrual of losses from FX difference as a result of change in the functional currency, as I said explained at the beginning of this call. Finally, moving to the slide 16. We must highlight the low and well spread leverage of the Company, as well as the solid cash position held compared to other peers in the industry and in Argentina. We have always been very proactive toward the cash and liability management, especially after witnessing volatility, high yields and narrow window in the international financing markets. We can -- we continue redeeming the short-term facilities highlighting that so far this year, Pampa redeemed at maturity and pre-cancel this year roughly a total of $310 million. The consolidated gross debt, including affiliates at ownership decreased to $2.4 billion, $115 million lower than June 2019, mainly because of the repurchase of own corporate bonds that so far -- at Pampa, we bought back $84 million face value plus debt repayments and to a lesser extent, the deval effect on the peso-bearing bonds. Consolidated gross debt is 93% denominated in dollars. This is lower than the previous June 2019, 99%, bearing at an average interest rate of 7.8% and 75% its place in the parent company. Consolidated cash amounted to $699 million, which is lower than the $863 million in June 2019. Also in Q3 2019, we were holding 93% of our cash in dollars. We also show here stand-alone key debt figures for our bondholders. Even after canceling roughly $310 million the principal maturities belonging to Pampa stand-alone that are left in 2019, and combine until 2022 amounts to $236 million, which is by far exceeded by the $550 million cash position at the parent. Net debt slightly increased to $1.7 billion. However, at the restricted group, the net debt fell to $1.2 billion and the net debt to 12 months EBITDA remain low at 1.9 times at consolidated level and 2 times at the restricted group. So this concludes our presentation. Now I will turn the word to the operator, who will open the floor for questions. Thank you.

The floor is now open for questions [Operator Instructions] Our first question comes from Petr Grishchenko with Barclays. Please go ahead.

Hi, good morning and thanks a lot for taking my questions. I guess first question. My understanding of project financing at subsidiary level was basically non-recourse. And now I'm seeing Pampa actually guarantee some payments under the trust -- under the financial trust and syndicated loan agreement. So I want to get more color on that. And I wanted to clarify this -- if $229 million, and I guess as it relates to, but again the EPC and turnkey agreements are also guaranteed or not?

Hi, Petr. Hi, how are you? So -- this is non-recourse as long as we comply with the closing to combined cycle to the project.

And just sort of fend this point a little more, if the combined cycle is not reached by -- basically in three years, then the Company would be obligated to make a repayment? Basically they won't be accelerated, is that right?

As long as Pampa -- Gabriel speaking, as long as Pampa and YPF will basically Pampa and YPF are required to warn our (inaudible).

Okay. I had a second question...

It's important to note that one thing is only at -- by that of scheduled project completion, okay.

Right okay, I guess the second question, can you maybe provide some more color on the decline in dispatch rates across various plants even for the new capacity? Just trying to understand, is this just demand driven or there were some outages during the period that led to lower dispatch?

Yes, well the -- it is demand driven actually. Q3 in the grid, it was the one of the lowest points of the demand and we bounded a little because it's winter season, but still we are at levels of 2014, 2015 in our levels. This is first thing. Second thing, for the units that are located in the north -- from the center to the north, that's they are -- variable costs have a gas price. It's kind of influenced by the imported gas from Bolivia. So in the variable cost, they kind of like are lagging behind in the dispatch priority, okay. This is first and second. Renewals also have a disruptive influence because in the north, we have solar. So it's -- there's some bottlenecks in the transportation and it doesn't come to the question, but renewals are getting disruptive in the dispatch, ranking in the dispatch and also in the south, where historically, our power plants have the lowest variable cost in the dispatch ranking, because the gas is the cheapest in the country. They even got outpaced by the wind generation, but demand-driven. Of course, we are experiencing around -- have been 34,000 gigawatt hour of demand in the quarter in the country where we usually used to be at almost 40,000. So it's quite -- this is -- since the last year, the demand in the country has been going down dramatically.

Great, Okay.

In line with the GDP, right. The GDP recession, right?

Right, yes. We were aware of that. And I guess, switching gears a little bit, can you maybe discuss a little bit what do you see in terms of payment delays from CAMMESA or any kind of extensions, if you could please maybe quantify them a little bit? I don't know if you mentioned during the presentation, I probably missed that.

Regarding the -- the other question I -- this is very important. Regulating our units were 90%. So as long as you are available, you collect the capacity take or pay, okay. So this especially was low, yes, lower than expected, but because of demand and CVP, same but our availability was outperforming. Now regarding CAMMESA, we are quite in the same pace and lately we've been -- we are around 50 -- less than 50 days of delays. So this is -- CAMMESA is doing the payments accordingly.

Repeat -- I what number did you give?

50 days, less than 50 days. The rule is 42. The highest point was a long time ago. So -- but we are around that level.

Okay, that's helpful. Thank you. And the last question if I may, can you maybe give some more color on how you are seeing debt amortizations next year, and generally speaking what refinancing options do you think are available for the Company? Anything on that kind of -- frankly, would be very helpful, thank you.

Yes, hello. Well, in terms of our debt amortization, the most important thing to be said as of today is that it's our cash position. So in that respect, what I would say is that we have the biggest thing to be amortized. It's the 2023 bonds. But it's -- that's the relevant amortization that we have amid on that. On the other side, whatever it's due for Pampa, here it's bank transactions that are that moment in time with them either repay with our own cash position, or we should expect to be able to refinance. In that respect, we have, as you may have seen already, two transactions that have been refinanced to pesos and we have other dollar amortization. So at this stage, I would say so would be clearly very easy to refinance, it will be better. It's actually at that moment in time and whatever is dollars we'll see when they can do, what -- we are going to cancel that, or refinance maybe the local market. So far bank lines are still available essentially a matter of costs rather than of liquidity.

Got it. Thanks for details. Best of luck to you guys.

Thank you.

Thank you.

Our next question comes from Guilherme Levy with Morgan Stanley. Please go ahead.

Hi, thank you for taking the question. I wanted to understand better, what are the capital allocation priorities should the macro situation in Argentina remain challenging for longer? In this case, for how long should we expect a continuation of share repurchase programs and how should we think about CapEx going forward? And second question, if I may, related to the first one actually, specifically for upstream, what are the next steps now? Is directly investing LNG an option or could we maybe see the Company deploying more cash rather than gas? What we -- what should we expect in the coming quarters? Thank you.

Yes, hello. In terms of the macro situation in Argentina, clearly, we should expect new information with the ones that administration is in place. So I think we cannot tell anything in terms of our future plans until we have -- basically the eventual new rules on outdoor, it change or not. So it's not possible to say what will happen and how long it will -- it would be there. What we are doing as of today is that basically are focusing on maintaining the current expansion in terms of generation. And in terms of E&P, we have the commitments and some exploratory wells in -- some exploratory wells. So once we have a new administration and we will see the policy that it's implemented, we will speak again and tell you what our plan is. Then in terms of share buybacks, well, as you see, the new share buyback program it's limited to be bound and it's being reviewed periodically in terms of how we see prospect going forward, and always having in mind to keep a strong cash position and what we consider conservative leverage. Another question?

No, no that was one question.

Hi. And the second question was specifically to upstream, are there any options to help monetize the gas reserves? I mean, would the Company consider directly invest in LNG for example?

Well about that we have our TGS, our affiliates for that. So, that's their investment, their project. So for Pampa, our focus is in gas production E&P. As Gaby said, we -- in our 2020 budget, we only have our committed CapEx for the blocks, some proactively wells to shale formations to minimum to maintain at least our production that today what we are doing is just testing that to our power generation. In power generation, the expansion is basically as you right, is almost nearing to finish and we don't have any other projects in the pipeline.

Pretty clear. Thank you.

Our next question comes from Ezequiel Fernandez with Creditcorp. Please go ahead.

Good morning, thanks for the Q&A, the earnings materials, [Technical Issues] the useful comparisons on adjusted and unadjusted monetary variables. I connected a little bit late to the call, so sorry if I go into any topic that you referred already. I have two questions.

Sorry, it's very difficult to understand what you're saying.

I will go one by one if you don't mind. The first one is related to oil and gas, if you can give us a ballpark. Sorry, can you hear me any better?

A little bit rough.

All right, I'll take it off the call -- I'll give you a color.

Okay.

Okay. I will repeat my question. If it's fine, then you tell me. Can you give us a ballpark for your 2019 full-year CapEx on the Oil and Gas segment and it's mix between exploration and infrastructure development? And what can be considered the run rate for you current output, and if you have anything to add about 2020, great?

In respect of guidance, we don't have guidelines; in respect of information for 2019, give us -- for this year, will be in line of $200 million.

Okay, great. $200 million for this year. I don't know if you could split that between exploration and recurrent?

One second.

Exploration CapEx, out of this $200 million forecast for this year's $70 million is for what we call expansionary CapEx. Basically this shale wells, exploratory wells plus another facilities that we do at El Mangrullo, a little bit in Rincon de Aranda and Sierra Chata.

Okay, great. All right. My second question is regarding the power distribution side. If you could comment a bit on the hike that were granted already and implemented and what is old or is still pending?

Are we talking about power distribution or that?

Power distribution, Edenor.

Okay, Edenor. Edenor, we got -- so here's the thing. We got schedule freeze, okay. And that schedules include some attractive instalments that was from the delays of the tariff -- prior previous tariff adjustment granted in March. So [Technical Issues] 19% in October, but with this retracting instalments that should have been stopped in August, that we keep collecting roughly half of the tariff increases cover. The other half, the area from the agreement with the government is to get paid in seven instalments as from January 2020.

Okay, great. My third question is related to your direct link between the capital units and power generation. You think you care about being able to self-deal gas to your plants about at the same time? Supposedly, it's not that relevant in terms of margins, what kind of advantage you see there that is important for you?

What's the advantage, it's because we have to understand what the -- the advance that we have by in terms of our gas, with our power generation, that's the question?

Yes. What advantage do you see in selling gas to your own power generation units, considering that the margin is not that big?

Let me tell you why. In the past quarter, a number of -- a significant number of wells in the country has been curtailed in gas and we didn't. Let me tell you why, because we have a certain offtaker. The offtake is our two best-performing power generation units, they are combined cycles, they are very competitive in the dispatch ranking, Loma De La Lata and Genelba. So we -- because they are always dispatched no matter what, because their variable cost is very cheap, and that's why we park our gas to them. That's around 70% of our production, 65% of our production with target to Loma De La Lata and Genelba. Loma De La Lata -- and this is at an advantage. Loma De La Lata is very close to our production block. So there is no transportation needed, right. The second well, for Genelba, we need to transportation and we have a granted for one year. So here is -- this is the very first thing -- certain offtake we have. The vertical integration is very volatile, though the pricing is very -- not very attractive. But it's certain we collect dollar-link and we collect it through our power generation collection. So power generation is in charge of selling this amount of gas on behalf of E&P. E&P and power generation are in the same company. This is not an interco. So there is -- we are away from internal taxes, we avoid are financial transaction taxes, and then the most important thing is that if we didn't have this integral -- vertical integration, how -- in the spot, which is -- it will -- could kill you in the offpeak season or sell it to CAMMESA directly and CAMMESA will send it to our power plant. So this triangle, it's avoided, but before we were subject to a high level of working capital that now we have been reduced dramatically because power generation sales gas on behalf of E&P. I don't know if it's -- if I made myself clear. It's more qualitative improvement then quantitative improvement.

That's very clear, and it has actually taken care of my fourth question. So, I'm done and sorry for the bad connection. Thank you very much.

No problem. Thank you.

Our next question comes from Florencia Mayorga with TPCG. Please go ahead.

Hi, Lida. Thanks for taking my question. And just two questions. The first one regarding E&P. In how many days distribution -- gas distribution companies and industrials are making their payments regarding gas? And the second one is the outlook regarding production after the growth already seen in the third quarter.

Hi, good morning Florencia. So distribution -- distributors, it's very tiny of our production, so it's like 5% or less. And in our production they are paying at 55 base. This is a sale that we practically do in pesos, right and we recorded as such in our financial statements. But it's very tiny from our sale. The major part is coming from CAMMESA being 50 days -- almost 50 days. As I said in an earlier question, industrials -- industrials, if we can agree, but they have a premium, it's around 30, 45 days and we are also exporting since September of this year. We are collecting at 60 days. Yes. Basically the major bulk of our sales are collecting at less than 50 days of collections.

Perfect and regarding production, do you expect that at the same level exceeded this quarter? Would it be seen in the fourth quarter after the growth from El Mangrullo or do you expect a small decline or remain flat?

Hi. So Q4 it's a very difficult quarter for the country, for the gas production, because again seasonality comes along. It's off-peak season but we managed to get our gas production kind of flattish. Again, we are exploring 600 -- I mean 700,000 cubic meters per day, that's roughly 10% of our production. And in Mangrullo it's flat. A main contributor of our production, El Mangrullo is flat.

Perfect and the last question, I believe that you mentioned that you had some deadlines available. Can you disclose how much higher level credit lines that Pampa has as of today?

First of all credit lines are not committed. So it's -- we are not disclosing that and that basically credit lines of the major banks give us most of their most of their cutback lending capacity that's available to us.

Thank you.

Our next question comes from Daniel Guardiola with BTG Pactual. Please go ahead.

Hi, good morning. I have a couple of questions. So my first question is related to the Oil and Gas segment. Considering that and on an overall basis, the average prices of gas have dramatically declined. I wanted to know your thoughts on the likelihood that Pampa may have to pass a negative revision to gathered reserves related to lower oil price. So that's my first question. And my second question is related to the much-awaited hikes in the tariffs of the utility companies. And considering the increase in social unrest on this content that we have seen in the (inaudible), I wanted to know if you could share with us how likely you think it is that the new administration is going to honor, the expected hikes that are related to the RTI? Thanks a lot.

So. Hi, Daniel. Good morning. Our reserves as of December 2018 was 140 million BOE. They are mostly tied to unconventional gas, there is no shale book there. So in that sense, we don't have shale gas book. And that's -- and the breakeven cost for a shale it's really higher than the prices that we are realizing today. That's why this impairment, it's kind of not likely on Pampa, though of course this affects our assessment of the share of our results for the December 2019, though we are, as we said in the call, we are already producing and already drilled, completed wells have shale gas formation and we expect to book some of them to our research. So we will see what kind of -- it's yet too early to tell, but yet, we will have to see what kind of contribution will make it. Then for -- I'm sorry I lost your question. That's the only one I could retain.

Frankly, the second question is regarding the tariffs, the adjustment that we are starting the tariffs of the utility companies in January 2020. And I wanted to know how likely it is that the new administration is going to own all these hikes considering the increase in social unrest and social discontent that we have seen across Latin America?

Yes, hello. Again, it's not possible to answer the likelihood in that respect. So it's -- basically we don't we -- we cannot answer that. What yes -- we can say is that whatever the -- whatever they don't pay it's going to become again a fiscal deficit and it's rather -- it's what we're seeing in the beginning of the call. We need to see what's going to be the plan of the government in terms of an integral plan -- so considering they have to consider different aspects and in balances of macroeconomic front.

Okay. Just -- let me rephrase the question. When you're a considering -- when you're forecasting your budget for 2020, are you considering the hikes?

Clearly, we consider the hikes. On the other side, you need to -- you need to manage liquidity considering that maybe you have delays as it has happened in the past.

Okay, understood. Thanks.

This concludes the question-and-answer session. At this time, I would like to turn the floor back to Ms. Wang for closing remarks.

Thank you so much for joining our call today. Our team is fully available for you, if you have any further questions. Have a good day.

The conference is now concluded. Thank you for attending today’s presentation. You may disconnect your line at this time and have a nice day.