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Utilities are considered among the most predictable and easy-to-understand businesses that exist. This article, however, is about a rapidly-growing Argentinean utility – both characteristics which the typical utility company investor could find unexpected, and one which has suffered, as almost all Argentinean equities, a sharp drop during recent times. The first relevant question to ask ourselves during this market sell-off is whether there is still a significant downside to this name.
The most bearish scenario that could reasonably be imagined occurs under the assumption that the regulatory environment is reversed back to 2015 (the last year under the previous administration), in which the company had a net profit of ARS 1.330 billion, which, after the 30% currency shift that took place in December of that year, amounted to USD 99 million for its installed “Legacy” capacity of 3,660 MW. In other words, in 2015, the company had a profit of USD 2.7 million per 100 MW of installed capacity. As the required Capex to install an additional 100 MW is roughly USD 100 million, we see that the numbers simply don’t add up for private companies: no private company would invest USD 100 million for a 2.7% return, in any country, as that return is even below the present 10Y US-treasury bond yield. In the current environment, in turn, Central Puerto (NYSE:CEPU) has awarded projects which are requiring USD 700 million of Capex. To make this possible, these projects are backed by 15-20 years electricity sale contracts with significantly higher “new electricity” prices than even those paid under the current regulation (enacted in Feb. 2017) for the “Legacy” installed capacity. In our most bearish scenario, to add insult to injury, we could assume that these contracts are voided, and the company receives in turn, the same 2.7% rate of return that results from the 2015 prices. As, after the completion of the currently awarded projects CEPU would have a total capacity of 4620 MW, employing a 10% discount rate, at 151 million ADRs withstanding (see Form 20-F and bear in mind that one ADR represents 10 ordinary shares) and USD 1.84 of net financial assets per share (see Section 2.6 below), CEPU could be trading at an extremely bearish low of USD 10.1 per ADR. So, it seems that the downside from the present prices is indeed very limited. I strongly believe a more bearish scenario than this can only be the subject of wild political speculation.
So what happened in the past and what is going on now? On one hand, we have to consider that there is a very solid and long-term secular trend of significant growth in electric power consumption in South American countries of around 4% a year, to which Argentina has been no exception. That growth in demand was met by a 2% CAGR in power generation during the last 15 years, an insufficient growth rate that resulted from government investments being matched by private disinvestment: stories regarding privately owned power plants slowly falling into disrepair, about a number of accidents that triggered the collection of cash from insurance companies, etc, are abundant. The narrowing of the supply/demand gap has caused considerable restrictions in the past, frequent blackouts, and Argentina still has to resort to electricity imports from neighboring countries during the peak demand of the system. The correction of this growing electric supply deficit is being undertaken by shifting the initiative back to the private sector. For that reason, the present regulation attempts to establish a remuneration that allows private generators to cover their cost of capital, while funding the required expansion and enhancement of the installed capacity directly from the revenue arising from such capacity.
Could the present trend be reversed? It seems very unlikely that the government will move away from fostering private initiatives in this sector, as the government runs a combined current account and fiscal deficit, and has a ratio of foreign-reserves/GDP around 10% and a debt/GDP around 33%. Government investments that don’t at least cover the cost of borrowing (around 7% in the open market) would just add more fuel to the fire. It is also worthwhile to have in mind that even the most unorthodox administration that Argentina has seen in the past 40 years didn’t nationalize any assets in the electricity generation sector and didn’t change any of the 1992 laws that subject this sector to privatization – but rather established a period of “emergency” during which they subsidized the end-user and, at the same time, paid low prices to private generators. Adding to the usual drama, the present administration has also declared that the overall energy deficit represents an “energy emergency” and rushed to increase end-user tariffs from the bottom lows seen in the past. Seeing this, the political opposition, in turn, is trying to declare a “tariff emergency”. So, it appears that in order for any policy to be implemented in Argentina (be it an orthodox or an unorthodox policy, one thing or the complete opposite) a state of emergency has to be declared first. Looking back from a long-term perspective, I believe that the energy sector, which should fare pretty decently in a country that is rich in natural resources, is simply affected by an excess of drama. While I don’t expect any geniuses to hold office anytime soon, I do expect them to be able to keep the lights on.
– Fair value estimates of around USD 20 per ADR. Regarding the potential upside, we will present a simplified DCF analysis, which, under the current operating conditions, yields a reasonable present value of USD 19.64 per ADR arising from “Legacy” operations, plus an estimated present value of the awarded generation projects. While similar values have been obtained by institutional analysts that cover the stock, this article discusses, in detail, how such numbers could have been obtained.
– Bullish estimates well above USD 30 per ADR. Further, should the growth in the power generation sector continue to take place and some of the management’s expectation on continued market liberalization materialize, a bullish estimate as high as USD 40 can be established on the basis of certain considerations that we will also discuss in detail. In sum, CEPU has a strong financial position that could enable it to grow its capacity up to 6,000 MW, and an equilibrium price for both “legacy” and “new” electricity could be reached eventually, which should be closer to the latter rather than to the former.
Article Summary: This article presents a bottom-up analysis of Central Puerto. While Section 2 presents an overview of the company, Section 3 presents an overview of long-term trends in the Argentinean electricity market, together with the management’s expectations on regulatory changes. Section 4 discusses some of the most significant risks associated to CEPU. Section 5 provides valuations: a base scenario where the present situation remains as is, and a second scenario where some of the management’s expectations materialize. Section 6, finally, presents some concluding remarks.
2. An Overview of CEPU
Central Puerto is the largest private sector power generator in Argentina, with a total installed capacity of 3,663 MW (39% hydro and 61% thermal). Central Puerto is also the largest private player in 3 companies operating a total of 2,554 MW under a consortium with other generators (the FONI power plants, see section 2.5 on “hidden assets” below).
Of crucial importance in the present market environment in Argentina is Central Puerto’s growth profile, with 703 MW (60% thermal and 40% wind energy) of government-awarded capacity under construction and contracted renewable energy projects with large power users.
|Fig 1. Source: Company’s SEC filings|
The importance of this growth profile lies in the fact that the current regulation establishes a very significant price gap between “legacy” and “new” energy prices (see Section 2.4 below), which leads to very high expected rates of return for new energy projects. Given these attractive rates of return, the management guidance on “potential projects” includes additional combined cycles for 1,456 MW and renewable energy projects for 347 MW.
Central Puerto’s renewable energy projects are developed through its subsidiary “CP Renovables” in which it has a 70% stake. These projects are partially funded with loans from the Inter-American Investment Corporation (and other similar or associated organizations) at a Libor+4% and Libor+5.25% interest rates.
In addition to power generation, Central Puerto holds significant but non-controlling stake in two gas distribution companies, which are experiencing an important increase in profitability fostered by recent regulatory changes.
2.1 An adequate corporate structure and very low management fees
A notable aspect of Central Puerto is that it is one of the very few (if not the only) Argentinean listed companies in which no shareholder controls more than 15% of the company, and in which the board of directors consists primarily of management-owners whose primary source of pay is not management compensation but dividends.
In fact, the last shareholders meeting approved an employee bonus of ARS 17 million (0.5% of net profits, a long-standing tradition of CEPU) and a management compensation of ARS 3 million for all 11 members of the board, which amounts to an average of USD 16k a year per individual, or less than 0.1% of net profits. (Yes, you have read that correctly!).
2.2 Solid USD-denominated cash flow from current operations.
In Jan. 2017, the Secretariat of Energy (SE) enacted Resolution 19/2017, updating the remuneration scheme for the old capacity power plants, which was gradually implemented since Feb. 2017 until its completion in Nov. 2017.
The current regulation establishes fixed payments for available capacity, plus an additional price per Mwh (excluding fuel costs, which is provided by the regulator free of charge). Prices are fixed in USD but are payable in ARS at the exchange rate of the date of payment, which de-risk power generators from the effect of foreign exchange fluctuation on their committed capex and/or debt servicing.
Regarding the available capacity remuneration, the remuneration system contains a number of technicalities and is essentially based on certain “Guaranteed capacity bids” or a “Base” energy price that is paid to generators regardless of whether the (available) equipment is used or not, and the “Additional” price that takes place when more than the “Base” energy is effectively required (which is targeted to cover the moments of peak demand). The system requires generators to make their bids carefully, as the regulation also penalizes off-schedule unavailability of generation units. The values are the following (in USD per month per MW):
|Type of energy||Base (May 2017 – Oct. 2017)||Base (Nov. 2017)||Additional (May 17 – Oct. 2017)||Additional (Nov. 2017)|
Source: Cammesa presentation on the effects of Resolution 19/2017.
Since Feb. 2017, the price per Mwh, which does not include fuel costs (which is provided free of charge by the regulator), is as follows
|Type of energy||Generated Power||Operated Power|
|Thermal – Natural Gas||5||2|
|Thermal – Fossil Fuel||8||2|
Source: Cammesa presentation on the effects of Resolution 19/2017.
Importantly, Central Puerto’s assets currently in operation are of much higher quality than the market average and show a stable operational performance.
|Fig 2. Source: Company’s SEC filings|
2.3 Estimates for “Legacy operations”: price increases and tax cuts.
For 2017, the company reported USD 209 million of Adjusted EBITDA from recurring operations.
|Fig. 3. Source: Company’s SEC filings|
As we have discussed in the previous section, tariffs paid to generators have not been yet effective for a full fiscal year (in fact, the last increase has been only effective since November: not even a full quarter has elapsed since their implementation). Regarding the share of the profit of associates, it is worthwhile to mention that Argentinean gas distribution companies in general are undergoing a sharp increase in their revenues and profitability.
The recently reported Q1 results came at ARS 1.69 billion (USD 80 million) of EBITDA from recurring operations. As Q1 coincides with the summer season in the southern hemisphere, where the peak electricity demand takes place, it seems reasonable to expect approximately USD 60 million of EBITDA for each of the remaining quarters. Additionally, the share in the profit of associates came at ARS 143 million, or USD 7 million, which is expected to increase as both price increases kick in, and peak demand takes place during the winter quarters Q2 and Q3. However, as gas-distribution companies do not posses their revenue denominated in USD, a conservative estimate would be a mere USD 28 million for the year.
Additionally, Central Puerto will greatly benefit from a corporate tax cut introduced by the Argentine government: the tax rate will decrease from 35% in 2017 to 30% in 2018, and 25% from 2020. Additionally, a facility to increase depreciation and amortization was recently approved by the Argentinean congress, which could enable an even lower effective tax rate for the company.
For these reasons, we summarize our expected EBITDA and cash-flows from the current “Legacy” operations
|Cash from operations||182||182||195|
|Profit from gas-distribution associates||28||28||28|
Source: Own estimations on the basis of the previous discussion.
2.4 Awarded projects: large gap in “Legacy” and “New” energy prices
Cash from operations will significantly increase as new projects became operational. The currently awarded projects are scheduled to be operational as follows:
|Power plant under construction||Capacity (MW)||Capex (USDmm)||Date|
|La Castellana and Achiras (Wind round I)||147||222||2Q 2018|
|La Castellana II (Wind, Term market)||16||19||3Q 2019|
|Lujan de Cuyo (Thermal co-generation)||93||91||4Q 2019|
|San Lorenzo (Thermal co-generation)||330||284||2Q 2020|
|Achiras II (Wind, Term market)||30||38||1Q 2020|
|Genoveva I (Wind round II)||87||105||2Q 2020|
|Total for Central Puerto||619||643|
Source: Company’s SEC filings
The last prices of generation projects awarded to Central Puerto, whose operating conditions were fixed in 15 or 20 year long contracts, show significantly higher prices.
|Type of energy||Capacity per month per MW (USD)||Mwh (USD)|
|New thermal projects||17,000||8-10|
|Wind power round I||
|Wind power round II||
|Wind power (term market)||
Source: Company’s SEC filings
This means that future projects, with price increases of 142% in the case of thermal energy, and significantly high prices for wind energy, will definitively have a considerable impact on the company’s profitability as they become operational.
While it is reasonable to expect a return on invested capital of at least 15% for the wind energy projects, the listed thermal projects, given their use of existing facilities and attractive energy prices, could attain much higher returns. As a very conservative estimate, upon completion of these projects the company could be increasing its cash flow by USD 96.5 million (15% on USD 643 million of Capex).
2.5 Additional “hidden” assets: prepaid turbines and the FONINVEMEM program
To further enhance its position ahead of future auctions, the company acquired in 2015, gas turbines totaling 969 MW and conveniently located land. These turbines, alongside with all other land and equipment, are recorded at their historical cost in pesos.
The last assets to consider are the FONINVEMEM (FONI) power plants. As it was mentioned, Central Puerto is the largest private player in 3 companies operating a total of 2,554 MW under a consortium with other generators. This consortium was created by the former government during the 2004-2011 period. During such period, the end-user electricity tariffs were frozen, and the deficit between revenue and costs of the overall system (which include a remuneration for fixed/capital costs of generators) were absorbed by the state in the form of government subsidies. During the process, the government also incurred severe payment delays to generators which were eventually addressed as follows: the government built power plants and the private generators would get, from the power plant revenue, their receivables in USD+interests, plus an administration fee for operating the plant. After 10 years, the consortium would be dissolved and they would receive equity in those power plants.
Two of these power plants began operations in 2010, which means that, in 2020, they will be transferred to the private parties, whose participation, however, will be diluted by an unspecified amount. The present administration has made public their intentions to sell their share in these power plants.
The third power plant began operations during Q1 2018 and triggered the beginning of the collections of the aforementioned FONI receivables. The present value of these FONI receivables is USD 550 million, but neither of the FX difference nor the interests have been reflected in the balance sheets for the past 6 years. The recent Q1 results include, as a non-recurring event, the recognition of a taxable gain of ARS 7.9 bn, as the collection of this receivables began during such quarter.
2.6 A solid balance sheet, with USD 1.85 per ADR in net financial assets
In order to support the period of strong growth that is expected for the next few years, Central Puerto benefits from a very solid financial position. In fact, according to the management’s guidance, no debt issuance is required to fund the already awarded projects. A quick look at the balance sheet shows the following
|Total liabilities||ARS 13.1 bn|
|Current assets||ARS 8.4 bn|
|Non-current trade and other receivables||ARS 10.4 bn|
It should be noted that this “non-current” trade receivables consist in the aforementioned FONI receivables, which are denominated in USD and accrue interests at a 30-day Libor+5%. The company’s expected cash-flows from these receivables are, in million USD, as follows:
|Fig. 4. Source: Company’s SEC filings|
So the company holds net financial assets (current assets + non-current receivables – total liabilities) position of ARS 5.7 bn, roughly USD 278 million at the exchange rate of March 28th. That means the company has USD 1.84 in cash equivalents per share.
3. Argentina’s electricity market
This section presents a few significant facts regarding supply and demand of electricity in Argentina and other South American countries, and we discuss management expectations on future regulatory changes.
3.1 Declining reserve margins amid a secular growth trend in demand
The existing electric power generation capacity in Argentina is substantially below demand during peak periods, requiring imports of electric power from neighboring countries. To illustrate the considerable narrowing of the demand/supply gap that took place during recent years, we consider the following data provided in Central Puerto’s prospectus:
|Year||Avg annual available capacity||peak demand||gap||Imports|
|2003||21.07 GW||14.36 GW||46.7%||0|
|2016||27.35 GW||25.4 GW||7.68%||1.8 GW|
Faced with rising electricity demand and declining reserve margins, the current government is in the process of commissioning the large generation projects we have discussed. In order to do so, and unlike the previous administration, which resorted to State-directed investments, the present administration has conducted auctions that aim to foster independent private initiative.
According to the Energy Secretariat, this auctioning process is only halfway through, having awarded 4.7 GW of the expected 10 GW of conventional generation, and with only 8% of renewable energy share, as compared to the targeted minimum of 20% for 2025.
On the other hand, as most Latin American countries, Argentina’ s electric consumption per capita has undergone a secular growth trend during the past several decades, expanding at a 2.86% annual rate, which comes on top of a population growth of 1.14% a year, for a total growth of 4% a year.
|Fig. 5. Per capita power consumption in Brazil, Argentina, Uruguay, and Chile has expanded at a CAGR of 2.47%, 2.86%, 3.4%, and 4.5% over the 1984-2014 period. The population in these countries increased at a 1.39%, 1.14%, 0.4%, and 1.1% annual rate, respectively, for a total growth in electric consumption of 3.86%, 4%, 3.8%, and 5.6%. Source: World Bank.|
This growth compares favorably with high-income countries, which have increased their total electric consumption at an annual growth rate of only 2% a year over the same 30-year period, while showing a significant slowdown or even a decrease in recent times.
South American countries consume 3 times less electricity per capita than the average high-income countries, suggesting that a significant runway exists for further increases in electric consumption, as electricity-consuming technology continues to be introduced in the residential, commercial, and manufacturing sectors.
3.2 Management’s expectations on further regulatory changes
Central Puerto’s management expects certain changes in the regulatory framework.
Shifting fuel purchases back to generators (along, of course, with a corresponding increase in the variable prices per Mwh paid to generators) could allow the company to generate gains, as it was the case prior to 2009, resulting from the difference of the cost of fuel quoted by the regulator and the price actually paid by the company. The company claims that it has obtained quotes for natural gas at a 10% discount to the reference prices set by the regulator. As the total cost of fuel purchases for 2017 totaled USD 832 million (Source: Company’s SEC filings), a potential increase in EBITDA of USD 80 million could be expected on this basis. The price for “legacy” hydro generation is significantly below thermal generation, unlike the historical trend of a similar price. The price of “legacy” energy could increase over time, in order to narrow the gap with “new” energy prices. If granted, this could provide a significant upside to the profitability of existing operations. The term market could be reopened for conventional generation, helping to close the aforementioned price gap.
A long-term equilibrium price for electricity? It seems reasonable to assume that an equilibrium price for electricity that allows for sustainable growth of the installed capacity, while at the same time covering the cost of capital in Argentina (around 10%) should be eventually reached. As power generation is a capital-intensive activity, this long-term equilibrium price should be determined, perhaps, on the basis of the required Capex (which is subject to inflation) and the cost of capital. Considering that the required Capex to install one MW is approximately one million dollars, the regulatory framework should allow efficient generators to reach a cash flow of USD 10 million per 100 MW of new installed capacity. This back-of-the-envelope calculation suggests that the regulatory mean reversion process is indeed incomplete, as Central Puerto’s estimated net profits for 2018 sit at USD 7.1 million per 100 MW, supporting the management’s claims of price convergence. This price convergence, however, could be attained in various ways and in a considerable time lapse.
4. Risks Sovereign default: Argentinean USD-denominated 10Y bond yield is currently at 7.4%, at a significant premium from treasury yields that is supposed to adequately capture the risk of default. Massive currency shift: if the USD/ARS relation evolves much faster than the inflation rate in the overall economy, either a part or the totality of the present USD-denominated cash paid to generators could be shifted back to inflation-adjusted ARS by the present or by future governments. Policy change: the present trend towards market liberalization could be reversed, limiting the upside of the “legacy” energy projects. The present auctioning system for new energy projects could be abandoned, favoring State initiative instead, for the required expansion in power generation capacity, limiting future growth of privately owned power generators like CEPU. Limited access to capital markets: the company could be unable to issue debt or sell stakes in associated companies. This might limit the future growth of the company. The Piedra del guila (hydroelectric) concession expires in 2023, and the conditions for its renewal are still unspecified. Delays: There could be delays in the construction of new projects, which reduce their present value. Increased competition: as the rate of return of the awarded new energy projects is generally quite attractive, if capital is available, there could be more private participants in these auctions which could put pressure on the rate of return.
Considering these factors, a discount rate of 11% for the equity in CEPU sounds as a reasonable number, as that would represent an additional 3.6% in equity risk premium as compared to the sovereign rate. This discount rate could change over time, depending on the evolution of the sovereign rate, and the evolution of the regulatory environment. As the company can obtain financing at a 8% rate, if approximately 33% of the business is financed with debt, we obtain a cost of capital of 10%.
In our base scenario, we assign no value to the FONI power plants, we assume that only the awarded projects are constructed, and that none of the management expectations materialize. Based on the previous discussion, we employ a discount rate of 10% (151 million ADRs withstanding).
We estimate USD 223 million on cash from current “legacy” operations plus the share of associates. This yields a value of USD 14.78 per ADR for the “Legacy” operations. The company has USD 1.85 per share in net financial assets.
As of today, neglecting all growth (including power plants under construction), the shares should have a minimum value of USD 16.63.
Upon completion of the already awarded projects, with expected rates of return of at least 15%, these could yield, at least, an additional USD 96.5 million of cash per year. Upon completion, these projects could add an additional USD 6.38 per ADR.
This totals USD 23.28 per share, upon the completion of the awarded projects, within 1.5 years in average. Discounting this time at a 10% rate, we arrive at a present value of USD 19.64 per share.
We also present a valuation for several of the management’s expectations.
Shifting fuel purchases back to generators presents a business opportunity that could yield an additional USD 60 million per year. This could represent an additional USD 3.97 per share. A 10% stake in the FONI plants (equivalent to 240 MW of combined cycles) yields an additional USD 24 million in cash flow per year. This stake could be valued at USD 1.58 per share. Additional thermal projects for 969 MW in which to utilize the already acquired land and turbines and 347 MW of additional wind energy projects. Assuming an ROIC of 15% on USD 1.2 bn of capex, and an average interest rate on USD 1 bn of debt of 8%, an additional USD 100 million after taxes could be obtained. This could be valued at roughly USD 6 per share. Increased prices for “legacy energy” of 20%, that in turn increase EBITDA from legacy operations by 40%. This could be valued at an additional USD 5.58 per share.
This totals USD 40.41 for our most bullish scenario, when/if these events materialize.
6. Concluding remarks
Even though this is not the most predictable and easy-to-understand utility company out there, the rapidly-growing character of CEPU and the current market sell-off present a compelling opportunity. The adequate corporate structure with low management fees gives confidence that, eventually, a high dividend payout will be established, which should help stabilize the share price over the long term.
Disclosure: I am/we are long CEPU.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.