The Inter-American Dialogue’s Energy, Climate Change & Extractive Industries Program seeks to improve understanding and communication on energy and climate policy issues in Latin America through research, public events, and roundtable discussions. By producing balanced analysis and convening policymakers, corporate leaders, and industry experts, we inform and shape policies that promote energy security and climate change mitigation while encouraging economically, socially, and environmentally responsible development of natural resources.
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An interview with Jed Bailey, managing director of Energy Narrative
Nate Graham (Program Associate, Energy, Climate Change & Extractive Industries): For more than two months, Covid-19 and the measures implemented to slow its spread have had a devastating effect on the global economy, with activity ceasing almost entirely in some sectors. The virtual disappearance of international travel has hit Caribbean economies particularly hard, decimating the tourism sector on which they greatly depend, and which is expected to lag in its recovery as consumers continue to be wary of travel and have less disposable income in their pockets. The current economic adversity in the Caribbean, and that on the horizon, will have numerous implications for the region’s energy sector and raises many questions.
Prior to Covid-19, the Caribbean was a burgeoning market for renewable energy investment with abundant untapped potential, especially in solar power. Additionally, in recent years, catastrophic storms have shined a light on the need for more modern and resilient grids in many islands. How will Covid-19 and recovery spending affect ongoing efforts to invest in these areas? Renewable energy development to date has been driven in part by the regional power sector’s high dependence on imported oil, which has been volatile and often costly, but oil prices have recently reached record lows and may remain depressed for a sustained period. Will islands hit the brakes on renewable energy? And as economic activity languishes due to stay-at-home measures, the region’s utilities are facing an unprecedented power demand crisis. How is Covid-19 affecting them? Finally, how are governments reacting to all these disruptions in the energy sector?
Jed Bailey is the managing director of Energy Narrative, which in addition to its analysis and advisory services, publishes a weekly brief on the latest energy news in the Greater Caribbean. I asked him how he sees the region’s energy sector now and in the post-pandemic world.
Nate Graham: In general, what do you see as the effect of Covid-19 on ongoing efforts to drive renewable energy development and bolster grid resilience in the Caribbean? Is the idea of using fiscal stimulus measures during the Covid-19 recovery to accelerate renewable energy development, grid modernization, and thus economic diversification being discussed, as it is in some other regions?
Jed Bailey: The Covid-19 crisis strikes on the back of five years of rapid growth in renewable energy capacity across the region and threatens to stall the momentum that has been built. Between 2015 and 2019, the Caribbean region increased renewable energy capacity by 50 percent, growing from 2.3 GW to 3.4 GW. Of this total, solar power has grown the fastest, almost tripling from 330 MW in 2015 to 950 MW in 2019. Although most new capacity additions are now renewable energy technologies, renewables are still a relatively small share of the total installed capacity in most countries. Jamaica was an early leader, installing the first privately owned wind power project in 2004, but today renewables still account for just 17 percent of the total electricity generation capacity. Barbados has committed to 100 percent renewable energy by 2030, but currently has just 25 MW of renewable capacity, roughly 9 percent of the island’s total generation park. For most countries, the majority of their power comes from thermal generators burning imported fuel oil and diesel. A few of the larger jurisdictions have access to natural gas for utility scale electricity generation, notably Trinidad & Tobago, Jamaica, the Dominican Republic, and Puerto Rico.
Resiliency is also a major concern for the region. Recent major hurricane strikes in the Bahamas, Puerto Rico, Dominica, Barbuda, and others destroyed power lines and damaged wind turbines and solar power panels. Microgrids are only just now being developed as countries in the region grapple with how to balance investment in resiliency and redundancy with the need to keep electricity tariffs and government spending at sustainable levels.
However, overall, Covid-19 has been a very difficult external shock for the Caribbean region and other priorities are likely to supersede continued efforts in renewable energy and resilience. In addition to the direct human toll and pressure on the region’s health care systems from Covid-19, the collapse in income from tourism and remittances has been deeper and faster than during the global financial crisis of 2008-2009.
Thus, the initial discussions of what comes next that have taken place have focused on reducing economic dependence on tourism, given the expected slow recovery of the sector. Tourism accounts for just over 5 percent of GDP on average in the Caribbean, but many countries are far more reliant on it—in Aruba tourism directly contributes one third of the country’s GDP, in six other Caribbean nations it accounts for a fifth or more of the total, and in a further seven countries it has a share greater than 10 percent. Remittances are also an important source of income for many countries, totaling more than 30 percent of GDP in Haiti, 16 percent in Jamaica, 9 percent in Dominica, and 8 percent in the Dominican Republic. With tourism in freefall and remittances projected to fall 20 percent this year, most countries are focused on simply surviving the near-term shock.
Economic stimulus packages have likewise been focused on near term needs. The IMF, IDB, World Bank, and other multilateral groups have already enacted several support packages for countries in the region aimed at macroeconomic stability, supporting health care systems, and providing cash transfers and other income support to the unemployed. Increasing local production of food and critical manufacturing capabilities are also a priority as global supply chains look vulnerable to Covid-19 related disruptions.
Regarding the possibility of renewable energy stimulus, countries currently have more than enough electricity generation capacity to meet demand given the sudden economic slowdown and the fact that hotels and restaurants remain empty. In addition, most renewable energy and microgrid technologies are imported, and so these projects provide less stimulus to the local economy than investment with greater local content. Overall, for most countries, economic diversification in the energy sector is much lower on the priority list than other sectors, at least for the time being.
Nate Graham: How have past price fluctuations in the price of oil affected political will to pursue renewables and natural gas? Will current oil prices threaten expansion of renewables, or has the Caribbean been burned by oil price spikes too many times?
Jed Bailey: The Caribbean has certainly had several trips on the oil price rollercoaster. During the period of high oil prices in the early 2010s, electricity rates soared, as did inflation, as oil imports are the single greatest use of foreign currency for many islands, accounting for roughly 13 percent of GDP. Some islands softened the economic blow by subsidizing electricity tariffs, while others, such as Jamaica, developed infrastructure to import natural gas and diversify their power generation fuels. The 2013-2014 oil price collapse in turn put proposed natural gas infrastructure projects in Barbados, the Bahamas, Puerto Rico, and the Dominican Republic on hold. Although oil prices soon rose again, rapidly falling costs for renewables and, more recently, battery storage, made these technologies increasingly attractive relative to major investments in natural gas infrastructure. Barbados, for example, is no longer pursuing natural gas imports for utility scale power generation as it focuses on increasing renewable generation. The current return to very low oil prices will further reduce the attractiveness of natural gas for those islands that do not already have the required infrastructure in place, potentially once again stalling the Bahamas’ plans to switch the main generation station on Nassau to natural gas, for instance.
Political support for renewables will remain, but the dip in electricity demand from the economic recession will slow the need for new electricity generation capacity. The ongoing financial drain on governments and utilities will also force most countries to continue to rely on their current electricity generation capacity, as funds will not be available to prematurely retire thermal generators in favor of new renewable capacity.
Nate Graham: Has Covid-19 exposed any particular weaknesses in the Caribbean’s energy sector?
Jed Bailey: The most important weakness is in the financial standing of some of the region’s utilities. The reduction in utility income from falling electricity demand (especially from the commercial and hotel sectors, which constitute the most reliable and lucrative customers for most utilities in the region) will more than offset their reduction in fuel costs. This means that countries that subsidized electricity tariffs in the past, such as and Trinidad and Tobago, have little room to reduce tariffs now to help support the future economic recovery.
The exact situation varies by company. Most of the privately-owned utilities in the region, including BL&P in Barbados, Lucelec in St. Lucia, and JPS in Jamaica, had a relatively strong financial position prior to the crisis. On the other hand, many state-owned utilities, including BPL in the Bahamas and PREPA in Puerto Rico, already had high levels of debt (often from subsidizing electricity tariffs) and have limited ability to raise additional funds without external support.
Nate Graham: Conversely, have there been any bright spots?
Jed Bailey: Although investment in new renewable energy will likely be delayed, the decline in electricity consumption means that renewable energy capacity that is already installed is now providing a larger share of the total energy supply than ever. Because renewable energy sources have nearly zero marginal cost and are generally non-dispatchable (particularly solar and wind, which are most prevalent in the Caribbean), these technologies will continue to be used first, with the lion’s share of the reduction in demand cutting into supply from thermal generators. This reduced call on thermal generators, along with the dramatic fall in liquid fuel prices, will greatly reduce the amount of money spent on fuel imports. For many countries in the region this is one of the largest drains on foreign currency reserves, representing 28 percent of GDP in Turks and Caicos, 23 pecent of GDP in Barbados, and 22 pecent of GDP in Dominica. This should be a welcome respite for Caribbean countries that rely on tourism as a source of foreign currency and will further burnish the region’s already strong trust in and support for renewable energy.
Nate Graham: How have Caribbean governments thus far managed the balance between continuity of electricity services and the health of power companies’ finances, with many consumers out of work and unable to pay their bills? What measures have been taken across the region in terms of subsidized rates, waiving or postponing bill payments, etc., and in which islands are power companies bearing the greatest cost?
Jed Bailey: As in many parts of the world, Caribbean utilities are suspending electricity disconnections for non-payment. In most countries, new electricity subsidies are not being considered, although the fall in the cost of liquid fuels will have much the same effect as electricity prices closely mirror oil prices. In many countries, fuel costs are separated from other utility costs and are passed through directly to the consumer. This can be a substantial share of the total—in Barbados, for example, the March fuel charge represented roughly 60 percent of the total electricity bill for a typical residential customer. When the drop in liquid fuel prices in April is factored in, that country’s electricity customers could see as much as a one-third reduction in the cost per kWh for their May bill. Even so, delinquencies are expected to rise as businesses across the region that depend on tourism see their revenue collapse and workers lose their jobs.
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In recent weeks, global energy markets have been rocked by a perfect storm, buffeted on two fronts by market gusts of historic magnitude. On March 6, a fragile deal of several years between Russia and Saudi Arabia-led OPEC collapsed as the sides failed to reach an agreement on continued supply cuts and instead vowed to raise production in a battle for market share. Meanwhile, as the Covid-19 outbreak reached pandemic proportions, the world entered lockdown and much economic activity skidded to a halt. On March 18, the Brent crude global benchmark dropped below $25 per barrel, its lowest level since 2003. Depending on the length of the price collapse and the pandemic, the effects could be dire for oil-dependent Latin American economies. Meanwhile, the economic contraction will reduce demand for power and limit access to finance for renewable energy projects.
Following several years of sluggish economic growth and increasing fiscal stress in the region, low crude prices will have immediate consequences on public coffers in Latin America’s oil export-dependent economies. Government budgets depend on projected oil prices that are generally much higher than the current price (see Figure 1). The governments of Venezuela and Ecuador are most vulnerable. Upstream investment will also be curtailed because international oil prices are well below breakeven prices (those required to recover costs of production) across the region (see Figure 2). Most projects that are already producing will not be shut in as a result of temporary low oil prices when the long-term economics are still favorable. However, with companies capital-constrained, investment in exploration will be slashed. Argentina and Brazil have among the highest breakeven prices for their most promising reserves.
Figure 1: Current oil prices are well below the estimates used to determine government spending across the region. Brent and WTI closing prices for 3/26/20 shown.
Source: News reports
Venezuela will be hardest hit. Already beset by falling production and US sanctions that restrict its potential buyers, state-owned PDVSA has been forced to sell its crude at steep discounts. PDVSA has been selling its flagship Merey heavy crude blend at discounts of as much as $23 below the Brent international benchmark. Venezuela has very low lifting costs— $10-$12/barrel on average, with some fields as low as $5/barrel—but when shipping costs to Asia and royalties are added, PDVSA is making no profit at today’s prices, and production will likely be shut in when storage reaches capacity.
Ecuador, one of the countries in the region most dependent on oil revenues, was already in a fiscal straitjacket before this new blow. The dollarization of its economy deprives the country of monetary policy tools and gives the government little choice but to invoke austerity and seek emergency funding and the understanding of the IMF, with which it is engaged in a $4.2 billion loan program.
In Argentina’s emerging Vaca Muerta shale play, investment was already frozen due to perceived political risk following the election of President Alberto Fernández. With a relatively high breakeven price of $45-50 per barrel, investment there will remain stalled if prices do not recover. The government of Neuquén Province, home to Vaca Muerta, has called on the national government to guarantee a minimum crude price to producers, but it is hard to see that happening when Argentina is seeking to renegotiate debt payments to the IMF and private lenders to avoid default.
In Brazil’s pre-salt, expected to be one of the world’s largest sources of supply growth in coming years, the breakeven is $35-45 per barrel. Energy consultancy Wood Mackenzie has predicted that 2020 exploration budgets in the country will be slashed by 20 percent. The government was already considering holding off on new bid rounds since so much acreage has been awarded in recent years, so new rounds are now even less likely.
Figure 2: Current oil prices are below the breakeven prices required for several countries' most promising fields. Brent and WTI closing prices for 3/26/20 shown.
Source: News reports
In Colombia, shale is seen as the best hope of boosting the country’s reserves, which will last for about 7.8 years at current production rates. But a public debate over whether to allow fracking is now compounded by the technique’s higher cost, uneconomical under current prices. As a result, the prospects for developing unconventionals in Colombia have disappeared for the time being.
Mexico will not feel the effects of low oil prices as acutely this year thanks to its annual oil hedge, which covered 2020 government oil revenues by locking in a price of $49/barrel for an undisclosed number of barrels. The greater concern is the health of state oil giant Pemex, which owes $6 billion on maturing bonds this year alone. The company’s Maya crude closed at less than $13 per barrel for shipments to the US Gulf Coast on March 18. It appears increasingly likely that a second ratings agency will downgrade Pemex bonds to junk, as Fitch did in June 2019, which could lead to a firesale. The increasingly ailing Pemex, traditionally the source of a large share of government revenue (around 17 percent this year), will further strain Mexico’s public finances beyond 2020.
Finally, the oil price crash and coronavirus have compounded an inauspicious start to oil production in Guyana, which was previously projected to experience economic growth of 86 percent this year. Fierce controversy over the vote-counting process following the election of March 2 has still not been resolved. The price drop is not expected to affect development of ExxonMobil’s Liza 1 well. However, market uncertainty has caused the government to extend, for the second time, a deadline for companies to submit bids to market the government’s share of oil from the Stabroek block, where Exxon is already producing.
The Covid-19 catastrophe could also have negative impacts on Latin America’s power and renewable energy sector. Electricity demand will decline amid the economic contraction. Governments may delay long-term auctions for renewable energy supply, which are reportedly behind 80 percent of current renewable energy capacity in the region and have led to rapid growth in renewable energy investment at prices competitive with fossil fuel generation. Significant disruptions in global supply chains due to the pandemic will cause delays and some ongoing projects will seek to declare force majeure. Financing may dry up in the short term as future demand is uncertain and investors flee to safer assets. According to our analysis, even before the current crisis, many renewable energy projects in Latin America had been delayed, in many cases due to lack of access to financing. Renewable energy developers face greater risk where power-purchase agreements (PPAs) are priced in local currency or the buyer is a state utility with weak finances. Low oil prices also reduce the cost of oil-fired electricity generation vis-à-vis renewable energy generation. Natural gas prices have also plummeted since November, and could continue to sink. On the other hand, sustained low oil prices may make the rate of return of developing renewable energy projects competitive with that of hydrocarbon development.
Latin America’s energy markets will experience turbulence for as long as low oil prices and Covid-19 persist, and will continue to be jolted by aftereffects even after the storm has abated. The impacts on the energy sector have already begun to bleed over into the economy at large and into politics, and will continue to do so. Oil development will slow and government revenues will suffer as a result, serving as yet another warning of the dangers of overdependence on the region’s natural resources. The only silver lining is the hope that the region will be better prepared when the next storm comes.
An interview with Héctor Castro Vizcarra, non-resident senior fellow for the Energy, Climate Change & Extractive Industries Program
Nate Graham (Program Assistant, Energy, Climate Change & Extractive Industries): The 2013 reform that liberalized Mexico’s power sector and ended the monopoly of the Federal Electricity Commission (CFE, the state-owned vertically-integrated utility) was heralded by many as a potential watershed moment for renewable energy in Mexico. Energy companies from across the globe flocked to Mexico’s three auctions for long-term power supply contracts between 2015 and 2017, and contracts were awarded to wind and solar projects accounting for a considerable share of new power demand at prices in some cases previously unseen internationally. The reform was accompanied by Clean Energy Certificates (CELs) meant to ensure that ambitious clean energy goals were reached.
However, the administration of President Andrés Manuel López Obrador (AMLO) has not built on this progress or capitalized on Mexico’s vast renewable energy potential and appears not to see the value in renewable energy expansion—even for reducing dependence on energy imports from the United States, a signature promise of his campaign. The head of CFE, Manuel Bartlett, has deemed renewables unreliable and expensive and, with the nationalistic flair typical of this government, stated that his firm will not purchase power produced by private companies because CFE can produce its own. To that end, a fourth highly-anticipated auction was suspended in December 2018 with no rescheduling in sight and the government indicating at one point that the auction had been cancelled entirely. With Mexican energy demand continuing to grow and generators continuing to seek investment opportunities, Bravos Energía, a private energy consultancy led by some of the designers of the Mexican government’s long-term auctions, is holding an auction of its own.
Meanwhile, new rules published by the energy ministry will extend CELs to clean energy generators built before 2014, weakening a major incentive to renewable energy development in Mexico and jeopardizing ongoing investments, according to critics.
Have the sunny prospects for renewable energy in Mexico dimmed, or can private companies weather the AMLO administration’s unfavorable disposition toward renewables? I turned to the Energy, Climate Change & Extractive Industries Program’s non-resident senior fellow, Héctor Castro Vizcarra, the former representative of the Mexican energy ministry in Washington, DC, for answers about what the private energy auction and the CEL rule change mean for the sector.
Nate Graham: What features make Bravos Energía’s private long-term electricity auction a significant development in the absence of government auctions? Will it be able to achieve results on the same scale?
Héctor Castro Vizcarra: With 70 companies registered, Bravos Energía’s ability to attract a wide range of participants has poised it for success when its results are announced in January. The initiative fills an important strategic role in the Mexican energy sector that, at least for the time-being, has been left empty by the suspension of the Mexican government’s long-term power auctions. That is the role of bringing investment to Mexico, generating large volumes of power at extremely competitive prices, and advancing towards Mexico’s clean energy goals using a transparent and accountable mechanism that prioritizes technical and financial viability. However, it is not necessarily a substitute for the public auctions, which were designed for the CFE basic suppliers, whereas the private auction is designed for a different set of players—all qualified users and qualified suppliers. So far CFE, which purchased almost all the energy in the three government auctions, is not expected to participate, and its participation is not deemed necessary for this auction’s success. There are also important differences in the auction designs.
Mexico’s three previous long-term power auctions were organized by the independent power system operator, CENACE, between 2015 and 2017 following Mexico’s 2013 liberalization of the energy sector. These tenders yielded major benefits for developers and the state alike. They generated contracts with 56 power plants with combined installed capacity of 7,666 MW and commitments of more than 10 billion dollars of investment, with little risk to the Mexican state. The contracts provided long-term revenue certainty, making projects more attractive for financing. The design of the auctions incentivized the generation of energy near demand centers and created competition between clean technologies, driving down prices and producing savings for CFE Basic Supply, the state-owned distributor. And the introduction of significant wind and solar capacity contributed to the diversification of Mexico’s energy matrix and reduction of greenhouse gas emissions. The fourth auction, scheduled for December 2018, was poised to build on these successes but was suspended by the government. Almost a year later, whether or when it will take place is unclear.
Enter Bravos Energía’s Long-Term Electrical Auction (CELP). As in the government auctions, companies can trade capacity, generation, and CELs, as well as a new product called energy balancing, which is flexible capacity that can be deployed as grid variations require. The CELP seeks to encourage clean energy investment and produce low prices while adding flexibility and security to the National Electric System.
The design of the CELP has several important benefits worth noting. Contract lengths are flexible at either five, ten, or fifteen years. By contrast, in the government auctions they have only been for 15 years, or 20 years for CELs. The new product, energy balancing, reduces exposure to spot market prices. Offers of energy are differentiated by both node and place of delivery, competition drives down prices, energy production near the centers of greatest demand is incentivized, and the process catalyzes geographical and technological diversification of power generation, as well as diversified and managed credit risk. The process also provides a transparent operation and a neutral arbiter.
In sum, private energy auctions are an exciting new opportunity to trade large volumes of new generation at competitive prices, bolstering Mexico’s energy security, economic growth, and clean energy efforts.
Nate Graham: What are the specifics of the government’s recent modification to CEL rules, and what is the rationale for the change? What concrete effect will the CEL rule change have on renewable energy contracts in Mexico and the government’s general relationship with the private sector?
Héctor Castro Vizcarra: On October 28, Mexico’s Ministry of Energy (Sener) published new guidelines for CELs that will allow the delivery of CELs to CFE plants (mostly large hydroelectric) built before 2014, despite warnings about the rule change’s potential consequences. CELs, awarded for each MWh of energy produced by clean sources, are tradeable and generators must acquire them each year in an amount corresponding to a gradually increasing share of generation from clean sources (in 2019, 5.8%). They are the principal tool of the Mexican energy reform’s goal to incentivize new renewable energy investment, as renewable generators can sell their excess CELs to other generators with lower shares of clean energy generation. They were meant to facilitate compliance with a mandatory goal of 35% clean energy nationwide by 2024.
Rocío Nahle, the secretary of energy, sees the move as a matter of equity for CFE, whose 60 pre-existing hydroelectric plants were left out of the CEL scheme when it was introduced as part of the 2013 energy reform. In a radio interview with the program Fórmula Financiera she called CELs a “subsidy for clean energy” and cited a projection that the Mexican government (through CFE) will pay 80 billion pesos (about $4.17 billion USD) over the next 20 years to purchase clean energy and CELs to meet clean energy generation requirements. According to Nahle, by granting CELs to CFE projects established before August 2014, this bill will be cut by some 60%.
The changes have drawn criticism from both the private sector and regulators and threaten investment in Mexican renewable energy as well as the country’s commitments under the Paris Climate Agreement. Furthermore, they violate President López Obrador’s avowal that he would not modify the energy reform and constitute another instance of the current administration retroactively changing the rules of the game for private companies.
Opponents of the move argue that retroactively extending CELs to legacy projects could create a vast oversupply and decrease their value in incentivizing clean energy development. In fact, Mexico’s Coordinating Business Council (CCE) warns that the new guidelines put more than $9 billion dollars of domestic and international renewable investment, which was anchored in the original rules, at risk. CCE has declared that the change of rules substantially alters the regulatory framework of the energy sector, generates uncertainty, and threatens the execution of investments. CCE has announced that it will defend itself legally.
The Mexican Solar Energy Association (Asolmex) and Mexican Wind Energy Association (AMDEE) have also issued reminders that a major attraction of allocating resources to renewable projects is in the possibility of commercializing CELs. Under the new rules, projects with an original payback period of 10-20 years may now not recover their investments for 20-30 years. Asolmex has stated that the changes will prevent $1.5 billion in solar investment this year, out of $3.5 billion previously expected, and announced that they will go to national and international authorities to defend their rights. And, in a recently published text, the Mexico Climate and Energy Platform says that this maneuver allows the Mexican government to take advantage of its old clean generation capacity to pretend to comply with CEL obligations while not installing new plants, generating clean energy with new facilities, or paying for CELs at auction.
Even the CRE, Mexico’s Energy Regulatory Commission, warns that the new rules discourage the construction of new renewable energy plants.
In this latest confrontation between the Mexican government and the private energy sector, the government is changing the rules to allow CFE to simulate compliance with pre-established clean energy goals and undermining the energy reform that AMLO said he would not change. Despite the veneer of cooperation constructed by the roundtable, speeches, and photographs surrounding the recent renegotiation of pipeline contracts, this new development is additional evidence that the relationship between the government and private industry is frayed by repeated instances of the administration rewriting the rules. Unfortunately, the outcomes of the pipeline controversy, in which the government wielded the threat of international arbitration to renegotiate contracts, suggest that private companies will struggle to win this battle in court.
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