The Coming Decommissioning Wave

The Coming Decommissioning Wave
October 2019

Our previous Infrastructure Ideas column (What Next for Coal?) outlined the (declining) state of the coal-fired electricity generation business. Driven until now by the age of plants and weakening economics, this decline is about to be sharply accelerated by climate concerns. An important consequence of this acceleration will be the impact and costs of decommissioning old – and not so old – generation facilities. The funds required for this decommissioning will be in the hundreds of billions of dollars. Decommissioning, in fact, will likely become one of the largest areas of infrastructure-related financing in the coming decades! Why is this going to happen, and how will it work? Read on…

Power plants close all the time. Since 2000, over 3,000 generating units have closed just in the United States. Historically these closures have been primarily end-of-technical-life retirements, with the post WWII building boom and average expected plant life of around 40 years. More are scheduled to close in coming years: another 6,000 plants in the US have been in production over 40 years, representing about 1/3 of national generating capacity.

What has begun to change is the rationale for closing generating plants. Already, economics – as opposed to just end-of-technical-life – has become a major factor in closing facilities. This is a predictable outcome of a sector which has gone from essentially stable to highly dynamic – driven by technology change (see Not Your Father’s Infrastructure). As prices of electricity from newly-built plants continue to plummet, the higher costs of power from older generating plants are becoming much more visible and problematic for buyers and policy-makers.

The first group of generating facilities to feel this economic pressure has been, interestingly, wind farms. The early generation of wind farms, often built to meet local environmental concerns and with output priced at a premium in most electricity markets, are now vastly more expensive than the newly-built wind farms (or solar). As they come to the end of their initial sales contracts, keeping these wind farms in service is economically unattractive. The first of these farms were coming on stream in the late 1990s, often with 15- or 20-years Power Purchase Agreements and typically being paid on the basis of pre-set Feed-in-Tariffs; they are now coming to the end of those contracts. 2015 was the first year that saw considerable wind farm retirements in the US, with an average plant life of 15 – as opposed to 40 – years. Germany, a country which was an early leader in pushing a “green energy” agenda, has a large-scale version of this issue. 20-year FITs will expire beginning in 2020 for over 20,000 onshore wind turbines, with a collective capacity of 2.4 gigawatts. Owners face decisions of whether to retire the wind farms or repower them (another potential option involves corporate PPAs, along the lines of the recent contract signed between Statkraft and Daimler, whereby Daimler will buy – for a 3 to 5-year period – power from wind farms whose guaranteed FIT contracts are expiring). Elsewhere, repowering of wind turbines has become a major business. Repowering began as replacement of old turbines with taller, and more efficient machines on existing sites; today operators switch even newer machines for larger and upgraded turbines or replacing other components. This makes sense where acquisition of land for new sites may be difficult, and where revenues are contingent on being able to compete with new lower-cost alternatives. In 2018 over a gigawatt of wind capacity was repowered in the US, and an estimated half gigawatt was repowered in Europe. The economic pressure to replace early-generation and more expensive renewables with new and cheaper plants extends well beyond Western Europe and 20-year old wind farms. FITs, the preferred first generation of purchase contracts for wind farms and some solar, have come to be seen as highly unfavorable to buyers, as costs of new equipment kept falling. Spain in the early 2010s, Portugal and several Eastern European countries either forced retroactive changes to purchase contracts or terminated them prematurely, trying to reduce the fiscal costs of expensive early renewable contracts. Yet even with competitive auctions replacing FITs, there remain economically-based risks to contracts. In India, the new state government in Andhra Pradesh has sought to terminate purchase contracts for solar power which are less than five years old. As prices for new solar and wind capacity, and for associated storage, continue to fall, this pressure will be more widespread.

The bigger losers from the economic pressure to switch power supplies, however, are clearly producers of thermal power. In the few places which still reply on oil to fire generation plants, the cost differential between existing supply and new alternatives is massive. In Kenya, the Government has announced its intention to shut several expensive oil-fired plants, starting with long-established and pioneering IPPs such as Iberafrica, Tsavo and Kipevu-diesel. With Senegal and other relatively small markets demonstrating that the option of below 5 cent/kilowatt-hour solar is a reality practically everywhere, we should expect a wave of closures of older oil-fired plants – whose costs run upwards of 15 cents/KwH. Globally, though, oil-fired plants make up a tiny part of electricity capacity. The biggest losers are rather in coal.

Many coal-fired plants have been closing for end-of-life technical reasons. From 2000 to 2015, over 50 gigawatts of coal-fired capacity was closed just in the US, with average closed plant life of over 50 years. More recently, coal – long seen as the cheapest form of electricity supply – has also begun to be supplanted on economic grounds. In the US natural gas-fired plants have come to be widely preferred. Endesa, in Spain, announced two weeks ago that it would shut down 7.5 gigawatts of coal power; the main reason cited was declining competitiveness, noting that its sales of coal power had declined 50% in the previous year. These are large amounts: Endesa has flagged a write-down of over $1 billion related to the retirements. Yet these amounts are still ripples compared with the coming wave.

What will drive a major acceleration of coal-fired plant closures is the continued worsening of economics, and a third factor, coming on top of technical retirements and economic pressures. This third factor is climate concerns. On economics, as discussed in our previous post, various analyses in the US show that costs of electricity could be reduced by closing between 1/3 and 2/3 of the existing coal fleet today, with that share rising to 85% by 2025 and 96% (about 250 gigawatts) by 2030. Regardless of how precisely accurate these estimates are, it is fairly clear that an amount of coal-fired capacity far larger than that retired since 2000 is or is about to become uneconomic compared to alternatives. Coal is not getting cheaper, but wind and solar, and storage, continue to get much cheaper. The big killer, though, we expect will be climate concerns.

The latest IPCC report, along with several others issued in conjunction with last month’s Climate Week, is fueling more concerns about the pace and likely extent of climate change. New data on the pace of climate change and GHG emissions levels is alarming. Every new analysis shows climate change is proceeding faster than previously expected, and pathways to lower-impact carbon concentration and temperature change require larger shifts than in previous analyses. The International Energy Association’s latest annual review found that as a result of higher energy consumption, 2018 global energy-related CO2 emissions increased to 33.1 Gigatons of CO2, rather than decreasing as they had from 2014 to 2016. The IEA also found that climate change is already causing a negative feedback loop in emissions: they estimated that weather conditions were responsible for almost 1/5th of the increase in global energy demand, as average winter and summer temperatures in some regions approached or exceeded historical records – driving up demand for heating and cooling alike, while lower-carbon options did not scale fast enough to meet the rise in demand. Another report coordinated by the World Meteorological Organization, says current plans would lead to a rise in average global temperatures of between 2.9C and 3.4C by 2100, more than double the level targeted in the Paris agreements. The trend seems clear, and before long public concerns will drive much more aggressive public policies.

Coal-fired power generation continues to be the single largest emitter, accounting for 30% of all energy-related carbon dioxide emissions. In all analyses, phasing out coal from the electricity sector is the single most important step to get in line with 1.5°C, and recommendations are getting steadily more strident and draconian. Canceling potential new coal plants will clearly not be enough. Another report from last month, this one by Climate Analytics states that although the new coal pipeline shrunk by 75% since the adoption of the Paris Agreement, to get on a 1.5°C pathway will require shutting down coal plants before the end of their technical lifetime. The report’s models show a need to go from current global coal-fired generation of 9,200 Terrawatt-hours all the way down to 2,000 TWH by 2030 – equivalent to decommissioning about 1.6 Terrawatts (1,600 Gigawatts) of generation capacity. Still another report modeled the need for emissions from coal power to peak in 2020 and fall to zero by 2040 if the world is to meet the Paris goals. Shutting down so much coal-fired generation capacity is a tall order. Yet the political pressure in this direction is building. Several countries in Europe have announced coal phase-out plans: France for 2022; Italy, the U.K. and Ireland for 2025; Denmark, Spain, the Netherlands, Portugal and Finland for 2030, and Germany for 2038. Even coal-rich South Africa is studying a plan involving substantial closures.

This potential decommissioning wave would be very expensive. Closing a coal-fired plant is a high cost exercise. The write-down associated with Endesa’s closures in Spain, noted above, comes to about $200/ KW of capacity. Resources for the Future in 2017 issued a detailed analysis of decommissioning costs for power stations in the US, coming up with a range of observed costs for coal of $21 to $460/KW of capacity, and a mean cost of $117, and estimated future decommissioning costs of between $50-150/ KW. These estimates are slightly lower than the costs indicated by Endesa, but are in the same ballpark, and we can get a rough idea of aggregate costs by applying a midpoint (say $100/KW) to the global coal fleet. This gives us the following projections:

• For retiring 250 gigawatt of coal generation capacity in the US, an implied a cost of $25 billion.
• For retiring 1,600 gigawatt of coal generation capacity around the world, an implied cost of $160 billion.

These costs are large… but are only a part of the picture. The analysis here includes the engineering specific costs, essentially technical and environmental costs associated with shutting down a plant, and cleaning up its site. It does not include other important costs associated with decommissioning, namely labor force and community adjustment costs, and – most critically for newer facilities – foregone revenue and breakage costs. For worker retraining and support, and adjustment funding for affected communities and regions, there are no clear estimates available. Germany’s decommissioning roadmap calls for about $40B in support to affected regions over 20 years, so we can see that the numbers – assuming governments aim to help – are not small. That $40B is greater than the estimated technical costs of retiring the entire US coal fleet. For a ballpark estimate, we could then say:

• For retiring 1,600 gigawatt of coal generation capacity around the world, an implied cost – including community/regional adjustment support — of $300 billion or more.

This still leaves the cost of foregone revenues for those who built and own the plants. In markets where many of the plants are approaching technical end-of-life, these costs may be low. Same in merchant markets where coal is losing customers on the basis of economics, and renewables and/or gas-fired plants are reaching significant scale. But in Asia, where the average age of the coal-fired fleet is closer to 10 years rather than 40, this is going to be a significant factor. If one assumes each megawatt of coal generation capacity has cost about $1M, and has associated equity of around $250,000 and debt of around $750,000, we can do a back-of-the envelope estimate of breakage costs for some 800 GW of “younger” Asian coal plants:

• At an annual rate of return target of 7.5%, with 30 years yet to go, potential future flows to equity over 30 more years would amount to about… $500 billion.
• Assuming average initial debt maturities of about 15 years, so that 2/3 of debt would already be repaid, this would leave outstanding principal debt in the range of … $200 billion

Obviously there are multiple assumptions embedded throughout these estimates. What they serve to show, however, is that the costs associated decommissioning the existing global coal fleet over the next two decades – assuming public opinion and politics coalesce around the issue, which we expect to happen – are very high. As in close to $1 trillion. Not to mention another trillion or so to build substitute renewable energy generation capacity. Annual investment today for comparison, around the world, in renewable energy? Less than $300 billion.

There are a few ideas already, at a local level, about how decommissioning costs might be funded. Germany’s roadmap includes reverse auctions for closure subsidies, where those bidding for the lowest amount of support would get funding. Eventually, plants not winning support at these auctions would be forced to close without state subsidies. Costs of legal challenges have not yet been considered. South Africa’s potential roadmap envisages donor and financial institution support to create a fund, managed by Eskom, to finance adjustment in coal-heavy parts of the country, support workers, and help balance Eskom’s finances during the transition away from coal. Colorado has a plan whereby securitization from ratepayer-backed bonds would pay out plants, and some of the bond income would go for helping workers in affected areas.

However these ideas play out, one thing is highly likely: decommissioning coal-fired plants will become a massive competitor for infrastructure-related financing in the coming two decades. The public portion of these costs – whether through a Global Fund, country-or regional specific vehicles, or just government spending – are very likely to exceed cumulative subsidies offered to renewable energy projects in their early years. A lot of funding, and a lot of creativity, will be absorbed here.

What Next for Coal?

What next for coal?
October 2019

On November 9, 2016, many coal companies threw a party. As a candidate, Donald Trump repeatedly told cheering crowds he would “stop the war on coal,” bring back coal mining jobs and revitalize communities in the Midwest and Appalachia that depended on coal mines. Shares of mining and associated equipment and transport companies soared overnight. The late Chris Cline, once described as the “last coal tycoon,” was so pleased that he immediately contributed a million dollars to the inaugural celebration for Trump.

The party’s over.

Production of coal in the US in 2019 is forecast to be the lowest in 40 years, and has fallen 30% since 2010. Bankruptcies of previously celebrating companies are coming almost monthly. In May of this year, Cloud Peak Energy — one of the largest US coal miners, declared bankruptcy; its mines shipped 50 million tons of coal in 2018. In the recently concluded bankruptcy auction, lenders to Cloud Peak will get $16m in cash… for their over $300m in outstanding debts. In July, another large producer, Blackjewel, also filed. Large mines in the Powder River Basin and the Eastern US were closed. Two more large producers, Arch Coal and Peabody Energy, agreed in June to consolidate their seven mines as a strategy to remain in business. All of this 2019 activity comes on the heel of the October 2018 bankruptcy filing of Westmoreland Coal, the largest independent coal producer in the US: there being no bidders at auction, creditors holding $1.4 billion in claims have been left to try operate the company’s assets themselves to try and recover some cash.

The problem for the mines is the departure of customers, especially in the power industry. In the same US where Trump pledged to bring back coal, no one is investing either in coal-fired plants or coal mines. But plenty of these are closing, accounting for almost half of all coal-fired power plant closures worldwide. And as reported in September by Energy and Environment News, the size of the closed electricity plants is increasing (And Now the Really Big Coal Plants Begin to Close). Navajo Generating Station, which closed the first of three of its units in late September, will be one of the largest carbon emitters to ever close in American history. It will join the Bruce Mansfield plant in Pennsylvania and the Paradise plant in Kentucky as plants that have emitted over 100 million tons of carbon dioxide since 2010 and that will have shut down. Multi-state western utility PacifiCorp announced last week that it would close large power-fired plants in Montana, Colorado and Wyoming – in one case two decades ahead of schedule. In the Southeast US, the picture is the same as in the West: a report this week from IEEFA (Coal-Fired Generation in Freefall across Southeast US) notes a net decline of 48 since 2008 in the number of coal-fired generating plants in the region, with the share of coal generation dropping from 48% to 28% during that period.

The White House narrative on coal was, and continues to be, about regulation. But what happened to coal was not regulation – it was technology. First came the new technologies for drilling for natural gas (commonly lumped under “fracking,” but in practice a much broader set of technology breakthroughs, especially related to imaging of underground deposits), which increasingly made new coal-fired electricity generation uncompetitive with gas-fired electricity. Natural gas plants could also be turned on and off far faster than coal-fired electricity generators, meaning that gas rather than coal was in demand to act as “peak capacity,” when hourly demand from consumers would be above average and need to be closely matched by production. Then came the technology breakthroughs that drove down wind and solar generation costs, enabling electricity from new wind and solar plants to come in at costs less than half that from new coal plants. With new technology also sending energy storage costs plummeting, it will only get worse for coal.

Outside the US, the story for coal is similar: many country-level variants, especially in Asia, but the direction is the same. A report from Global Energy Monitor noted that the number of coal plants on which construction has begun each year has fallen by 84% since 2015, and 39% just in 2018, while the number of completed plants has dropped by more than half since 2015. Infrastructure Ideas’ series on the energy transition in Asia outlined how key policy choices under consideration may affect demand in many of the handful of countries where possible new coal generation is concentrated, namely India, Indonesia, Bangladesh and Pakistan. A study by Carbon Tracker estimated that nearly half of China’s existing coal power fleet is losing money, and that it will become more expensive to operate coal in China than to build new renewables by 2021. A report issued in March by Energy Innovation and Vibrant Clean Energy claimed that replacing 74% of US coal plants with wind and solar power would immediately reduce power costs, at times cutting the cost almost in half. According to the analysis, by 2025, over 85% of coal plants could be at risk of cheaper replacement by renewables. Carbon Tracker came up with similar in a November global analysis of 6,685 coal plants. This found that it is today cheaper to build new renewable generation than to run 35% of coal-fired plants worldwide. By 2030, that increases dramatically, with renewables beating out 96% of today’s existing and planned coal-fired generation. Exceptions remain only in markets with extremely low fuel costs, where coal is cheap and plentiful, or with uncertain policies for renewables, like Russia.

For coal-based power companies, there is no longer much of a future in planning and building new plants. Revenues are declining as a number of existing plants are retired as they reach end-of-life, as we keep seeing in the US. With prices of electricity from natural gas-fired plants remaining low, and prices from new wind and solar plants continuing to fall, more existing coal-fired plants are becoming economically uncompetitive, and either running at low capacity or also being closed, though their technical end-of-life may still be several years away. So the future looks increasingly unprofitable.

There may, however, be an unexpected silver lining. Coal-based power producers may well have another big potential revenue stream out there. Just not the one anyone has been foreseeing, or one that has been there before. That potential source of new revenue? Getting paid to take plants offline. Sound odd? Indeed. There are, however, two big building blocks towards this possible future.

1) There’s a lot of coal left to retire, even with fairly high current retirement levels. China has more than 1 million Megawatts, or 1,000 Gigawatts, of capacity operating or under construction, while the US has over 250 Gigawatts left and the EU has over 150 GWs. And key policy choices in some Asian countries may lead to yet more build-out for a time.

2) Political pressure for action is going to get very high. New data on the pace of climate change and GHG emissions levels is unidirectionally alarming. Every new review of climate change finds it to be proceeding faster than previously expected, and emissions levels remain well-above scenarios for lower levels of temperature rise. With every passing year, potential mitigation plans will become more and more aggressive, calling for faster and deeper cuts in emissions.

Faster and deeper cuts in global GHG emissions are highly unlikely to be achievable without early retirement of the large existing coal-fired fleet. And changing economics do not always translate rapidly into retirement of existing producers. Which makes it likely that at some point, in the not too distant future, closing existing plants faster than they would close on their own will become a top public policy priority. Closing existing plants might be done by political fiat, or, it could be done by paying coal-fired plants to go away. It may well prove that paying them could be a faster way to achieve closure, avoiding drawn-out litigation around contractual rights.

For coal executives, the best hope for offset continued revenue decreases may well be to hope for the creation of a publicly-funded “close coal plants now” funds. It does sound odd, but it may well be their best bet. And in the US, which political party is most likely to favor using increased public funding to achieve a policy objective? It’s not the current occupants of the White House.

Difficult to conceive, but it may come to be: coal executives for… Democrats?

Infrastructure Ideas will explore these plant retirement issues in its next two posts of this series: The Coming Decommissioning Wave, and Blue Coal?

Asia’s Energy Transformation: India

Asia’s Energy Transformation: India
August 2019

This is the fourth in a series on the ongoing, large-scale transformation of energy use in Asia. Previous columns have focused on Pakistan, Bangladesh and Indonesia. As we noted in earlier installments of the series, Asia is the most important global market for energy consumption, investment, and greenhouse-gas emissions. And it is a region undergoing a large-scale energy transition, whose unclear evolution has more importance to the future of both climate change and energy investments than that of any other region.

With over 1.3 billion people, India is the world’s second most populated country, and accounts for about 18% of all the people who live on earth. Somewhere around 2024 India will become the most populated of all. Yet it consumes only about 5% of the electricity produced globally. About 200 million people in India live without electricity, and about twice as many have access for less than six hours a day. Prime Minister Narendra Modi, elected in 2014, has made it a priority to change this, and provide universal electrification in India. Plans provide for roughly a tripling of the country’s electricity generation over the next two decades, a central plank to India’s development and poverty-reduction efforts. Good.

When Prime Minister Modi took office, 2/3 of all power produced in India was generated from coal. Were the plan to triple power generation to succeed the same profile of where power comes from, it would imply adding more greenhouse gas emissions annually than the amount produced annually by the United States. Bad. So Modi has also proposed an unprecedented ramp-up in renewable energy generation. India’s ability to raise electricity availability is critical to development and poverty reduction, yet how it does so will also have a crucial impact on the global environment. So India’s energy challenge is one in which both India and the rest of the world have a huge stake.

The good news is that so far, India’s bet on renewable energy has succeeded far better than most observers expected. Five years ago, when Modi was elected, India’s total renewable energy production capacity was 34 GW, about 10% of its power capacity, mostly consisting of hydropower, with solar capacity at a tiny 1.5 GW. Today renewable energy capacity stands at 80 GW, with essentially all the growth having come from solar and wind farms. This has vaulted India up to 5th globally in renewable energy production, behind China, the USA, Brazil, and Germany, and 4th (ahead of Brazil) if hydropower is excluded. The country’s well-publicized 2022 renewable energy target (just three years from now) is 175 GW, more than double current capacity – and about equal to current combined wind and solar capacity of the USA, or to the world’s total generation capacity from wind and solar power a short decade ago. Doubling wind and solar capacity in three years would seem nearly impossible – except for the fact that this is exactly what India has done over the previous three years.

A big part of this success story, as has been the case in other countries bringing on stream large amount of solar and wind power, has been rapid price decreases. As renewable auctions got underway in Brazil, South Africa, and other places, driving costs down by 75% in 3-4 years in several countries, India seemed like it would be on the outside looking in at the renewables boom. With high foreign exchange risks, government bureaucracy, and loss-making state-owned electricity distribution companies, analysts initially thought India would find it hard to bring solar costs down below $0.10/KwH – double what some countries were seeing, and well above the cost of alternative ways to raise electricity production, mainly through coal. Yet India managed to become a part of the global solar boom, with prices dropping almost monthly for three years. The cheapest prices offered for generating solar have come down to $0.036/KwH (still double world lows – see And Prices Keep Falling), or about half of what power from a greenfield coal-fired plant could be expected to cost.

In a country as large as India, with states as politically diverse as it has, it is unsurprising that adoption of renewables has varied widely across the country. Rajasthan and Gujarat have two of the largest solar programs and the lowest prices. Tamil Nadu’s late 2017 solar auctions brought signed offtake agreements at $0.054/KwH, compared to previous capacity additions there at $0.12. Renewables there are set to account for 35% of total generation capacity in the state. Karnataka and Telangana each added 2 GW in 2018. Several states, however, have no solar generation at all. The government of one state, Andhra Pradesh (AP), has managed to be good news and bad news all in one. On the one hand AP announced a very large short-term target of installing 18 Gigawatts of renewable energy by 2022, almost 20% of the total national target for the period, and tripling AP renewable capacity. Good news. On the other hand, in May newly elected AP Chief Minister Jaganmohan Reddy called for retrospective renegotiations and cancellation of existing contracts for wind, solar and storage contracts in the state. Bad news. At issue is that prices for renewable capacity contracted in the previous 5-6 years are now much higher than prices based on rapidly advancing technology. Not that previously contracted prices are particularly high in AP – tariffs being contested are in the range of 5-8 cents/KwH. These are still attractive prices relative to power generation costs in many countries. The AP problem, however, which is not unique to AP, is that a combination of gross inefficiencies in the state-owned power distribution companies (India has the highest grid losses of any country in Asia, at an average of 25%) and subsidized prices for some consumers means that state-owned distribution companies are virtually bankrupt, and the new Chief Minister seeks to squeeze improvements any way he can. Andhra Pradesh Southern Power Distribution Company (APSPDL) and Andhra Pradesh Eastern Power Distribution Company (APEPDCL), have lost $220m together in the last year. You can see the political logic driving him, but the cost in lawsuits, and the driving away of operators from AP – reducing competition for future capacity bids – is likely to be a very steep price for breaking contracts. As India looks to achieve its 175 GW target for renewable capacity by 2022, and equally ambitious capacity growth targets beyond this, the roadblocks that have stymied even faster growth will have to be overcome.

Roadblock #1 to faster renewable growth in India is the coal lobby. This consists of many actors, the most powerful of which is Coal India Limited, who among other things provides significant tax revenue and employment in India’s poorest states. Indian Railways transports most coal and over-charge for coal transport to subsidize passenger prices. And even as Modi’s government sets highly aggressive targets for the growth of renewable energy, it has continued to declare in parallel that it will build more coal plants on a large scale. Roadblock #2 remains the credit risk of state-run off-takers. India’s distribution companies collectively lose hundreds of billions of dollars a year – despite the fact that new power sources are getting rapidly cheaper. Most would be bankrupt if not haphazardly propped up by governments. It’s a very large-scale problem: A new World Bank report titled, “In the Dark: How Much Do Power Sector Distortions Cost South Asia,” says India’s power sector inefficiencies cost the economy about 4% of GDP a year. And it’s a big problem for new renewables producers whose financial future depends on their off-takers being able to pay their bills. Roadblock #3 is predictability, along with India’s tradition of economic statism. One example is attempts to renegotiate contracts for political purposes, as seen above in the case of Andhra Pradesh. Another is the attempt to force government-owned firms into the picture. That until recently solar and wind auctions in India had functioned as they have everywhere else, with private sector firms being the bidders to provide new capacity, has run against some of India’s economic traditions. Especially in infrastructure, India’s history is one of state control. This June, India tried to turn the clock back in this direction with an auction for 1.8 GW of new solar capacity… which was only open to state-run firms. Though it seemed a shock to the organizers, it was not a shock to anyone else when the auction was undersubscribed by 2/3, drawing bids for just over half a Gigawatt. Very few state-owned companies (leaving aside partially state-owned exceptions such as Italy’s ENEL or France’s EDF) are nimble enough to keep moving down the production cost curve as aggressively as private producers have done this last decade.

These are pretty big roadblocks. In spite of the historic growth of solar capacity, many observers still believe coal will continue to dominate power in India (see Coal is King in India – and Will Remain So, from Brookings). India is the third-largest coal-fired generation producer globally, behind only China and the USA. Even at the impressive level of 80GW, renewables account for only 40% of the electricity generating capacity that coal-fired power does. And when generation factors are accounted for (meaning how often wind and solar plants are producing actual electricity), coal produces still 7 times the power that renewables do in the county. In 2015, India had plans for adding another 100 GW of coal-fired power generation over 5 years, which briefly became (as China’s announced programs shifted) the largest single-country pipeline in the world for new-build coal capacity. Nonetheless, the coal lobby has a big problem of its own. While formerly expensive solar is getting cheap, formerly cheap coal is getting expensive. Since 2007, bid prices to provide new coal-fired have essentially doubled, from as low as $0.036/KwH to $0.07 by 2013. The average price for coal-fired power on Indian exchanges in 2018 hovered around 7 cents/KwH. And while new renewable PPAs are price-fixed without inflation (meaning real prices on the contracts will actually decline over time), coal power is subject to inflation in the price of coal and other operating costs. Transport inefficiencies, disruptions in imported coal supply (as many coal mines cease to operate due to declining or unpredictable demand), and problems in the domestic mining sector have contributed to the rise, and decline in prices is unlikely. Some new coal plants are being commissioned (about 3 GW in 2018), though decommissioned older capacity means net coal generation is no longer growing. At least for now. This compares with net additions of thermal generation capacity of 20 GW annually from 2012-2016. And four years into the announced plan to add 100 GW of new coal-fired power from 2015 to 2020, only about 10% of this has been built. Plans still call for another 90 GW of new plants by 2026. Let’s see. Either way, the consequences of the next set of procurement decisions will be very large.

As the political power of coal and the economic gains of renewables square off, the future direction of energy in India may depend in large part on developments in energy storage (see Fortune India — Why Storage is the Next Big Thing). The issue with solar and wind is of course their intermittent nature. This is a manageable issue when intermittent power accounts for a small share of total electricity on a grid. Though that share is growing in India, the technical weaknesses of India’s transmission grids means problems occur at lower penetration levels of intermittent power, and Indians are naturally loath to see more country-wide blackouts as the monster experienced in 2012. Therefore the potential value of energy storage, enabling renewable energy to be released to the grid at times when wind is not blowing or sun is not shining, is even higher in India than in other places. As a forthcoming Infrastructure Ideas column will review, battery storage costs continue to plunge worldwide, and storage + renewables projects are beginning to replace even relatively cheap gas-fired capacity in the US and elsewhere. The Government issued its first large-scale tenders for storage in March 2019, and states are beginning to follow suit. The cabinet has approved a National Mission on Transformative Mobility and Battery Storage, which aims also to manufacture batteries on a large scale domestically. With India’s world-class engineering skills, one should expect energy storage built in India to be cost-competitive with storage projects in the US and Europe.

Compared to the ongoing energy transition in other countries, the above snapshot may seem to be missing a third player: natural gas-fired electricity generation. In the US, gas has played the largest role in recent energy shifts, and it is playing a big role in new capacity plans in China, the Middle East, and Latin America. It is also a key question mark for Bangladesh, Pakistan, and Indonesia. For India, there is less to talk about. Sure, India is building both gas import terminals and new gas-fired plans. There are offshore gas reserves, as there are for Bangladesh. But the scale, relative to the massive existing coal fleet and the massive renewable plans, is hardly worth talking about. It could become a bigger factor in the equation for India, but only if (a) the government allows prices for domestically produced gas to come closer to international prices, and (b) it also supports investment in transporting gas throughout the country.

Hydropower will also play some role, though the better hydro sites in India have already been developed, and recent dam-building history is filled with cost overruns, social displacement and construction problems, so it’s hard to see this as more than a minor actor. In Eastern India, imports of hydro-produced power from Bhutan, and maybe gas-fired power from Bangladesh, may play a regionally more important role. But on the large scale of large India, this is not where the main battle will play out.

Keep an eye on India. The development and living standards of hundreds of millions depend on continued economic progress there. As does the extent to which the planet will get hotter. High stakes. And a Top 3 coal power going against a Top 3 renewables plan – the stuff of Bollywood epics for years to come…


And the Prices Keep Falling (II)

And the Prices Keep Falling (part II)

In the first of this two-part post, And the Prices Keep Falling, Infrastructure Ideas highlighted the hugely positive side of this Summer’s remarkable solar auctions in Brazil and Portugal. With the price of new solar – and wind – generating capacity continuing to fall to record low levels, energy is getting cheaper for nearly all. And cleaner.

Yet there is a dark side.

Today’s post outlines some less positive consequences of these falling prices for two important sets of players. And we don’t mean the fossil fuel industry. Falling prices have downside for solar investors and lenders, and – surprisingly – for some of the countries who most need solar and wind power.

Falling costs (as distinct from prices) can affect industries in different ways. In some industries, producers are able to maintain previous price levels, or at least ensure that prices fall more slowly than costs. This drives higher profits, and is naturally the outcome to which most firms aspire. In other industries, prices fall as fast, or even faster than costs. This is the kind of outcome which disproportionately benefits consumers. As economists would frame it, consumers are capturing most – if not all – the benefits of falling costs. The solar and wind generation sectors are an example of the latter.

Why this should be the case is a good question, but one with a simple answer. Consumers, and consuming countries, have captured most or all of the benefits of falling solar and wind costs for one reason: competitive auctions. The across-the-board switch from older power procurement methods — negotiated contracts, and feed-in-tariffs – to competitive price-based auctions was pioneered in large Emerging Markets, notably Brazil and South Africa, in the early 2010s. now it is highly unusual to see utility-scale procurement on any different basis. A Bloomberg New Energy Finance analysis in 2016 found that the switch to auctions was responsible for as much of the price decline in countries which adopted them as were technology cost declines.

But what is great for buyers is becoming increasingly problematic for investors and lenders. Prices in recent PPA auctions are falling to such levels that little room is left for either unforeseen operational risks, or for the cost of capital. Already in mid-2018, UK consulting firm Cornwall Insight projected that unsubsidized solar projects would be unviable by 2030 (what happens when renewables eat their own profits?), in this case because of pushing wholesale prices in the UK down so far. Wood Mackenzie’s Emma Foehringer Merchant wrote back in January 2019 of a “finance bubble” in the solar industry. Looking at results of recent solar auctions, Merchant noted “A flood of new investors, like pension funds and insurance companies, now view solar as a stable asset. That “wall of money” going after a smaller pool of projects has created a market so competitive that many sponsors are willing to accept lower-than-average returns. Power-purchase agreement prices have also fallen to new lows, and contract terms have gotten shorter. Industry financial experts say, taken together, those trends have led to a mispricing of risk.” The chorus has become louder after this Summer’s below 2 cents/KwH auctions. A piece by Wood Mackenzie’s Jason Deign (Key to those record-low solar bids?) looked at the mechanics of bidders’ approaches to preparing these super-low priced bids, and concluded that bidders were offering very low prices for Power Purchase Agreements with the idea that they could sell power for higher prices in later years in merchant markets. An assumption which, given the recent history of how fast prices are falling, would seem highly unrealistic.

These emerging risk profiles for new solar and wind generation investments are getting further and further away from “traditional” electricity industry risk profiles, which assumed steady long-term revenues and predictably stable conditions for the life of 15 to 20-year loans. Normally lenders to such projects would adjust to higher risk and lower predictability by charging higher interest rates, but with prices falling so far and margins getting squeezed, new projects and owners have no room to accommodate higher rates – and indeed are strongly pressuring lenders to squeeze margins further down. A likely outcome? Lower profits and higher risks for renewable energy lending portfolios.

As solar becomes a larger and larger – and lower cost — market, one would think this is all good news for industry players, though we see it is not. And there’s another group for who one would think it’s all good news – but it’s not – or at least not for some of the group. This group? Low-income countries.

In principle low-income countries are the potentially biggest beneficiaries of low-cost wind and solar. Often the countries with the biggest electricity deficits, the highest costs of power, and the least money with which to add generation capacity, low-income countries stand to benefit disproportionately from plunging solar costs. And those that move to join those countries establishing competitive procurement auctions will do just that – benefit disproportionately. Their development and economic gains will be huge. The catch? Not all will manage to do so.

The difficulty for many low-income countries lies in organizing access to this new bounty of cheap solar (and wind). It will not happen by itself. Implementing competitive auctions is not an impossible task, but it does require organization, administrative competency, and ability to deliver on a process once it is announced. Many low-income countries face two important hurdles to achieve this. The first hurdle is weak administrative capacity to organize auctions. Auctions, after all, often differ radically from existing procurement mechanisms in many low-income countries, and a poorly handled process can significantly limit interest from solar companies – leading to less competition and unnecessarily high bid prices. This is a hurdle which can be surmounted, but often requires assistance from advisers who have done it before. The second hurdle is probably the higher. The second hurdle is the power of vested interests who benefit from existing arrangements – often high cost, inefficient arrangements. Foremost among these may be the national monopoly utility, and those in charge of supplying raw material – oil or coal – to the existing generation fleet. These vested interests may have significant political power and influence, enough to derail the implementation of administratively complex and novel competitive auctions for solar.

For countries which fail to overcome these two hurdles, the future is bleak. In a world where more and more countries are able to achieve lower energy costs through procurement of low-priced wind and solar generation, those countries whose energy costs are dominated by high-priced, “traditional” thermal electricity resources will become less and less competitive, and fall further behind their neighbors. Failure to join the low-cost renewable energy club will carry very high opportunity costs, both in terms of development, and of foregone economic competitiveness.

So cheer low cost solar. And encourage all not to be left behind.

Asia’s Energy Transformation: Indonesia

On April 17, voters in Indonesia went to the polls and apparently re-elected President Joko Widodo (“Jokowi”) to a second term. Final results are due May 22. This election, and President Jokowi’s second term, if early results are confirmed, will have momentous consequences for infrastructure, energy and global climate.

This is the third in an Infrastructure Ideas series on the state of Asia’s Energy Transformation, following earlier reviews of the energy situation in Pakistan and in Bangladesh. Indonesia shares many commonalities with the other two countries: one of the ten most populated countries in the world (with over a quarter of a million people, Indonesia has the 4th largest population), facing energy high demand growth while running out of domestic fuel sources on which it has relied, and strongly considering a large-scale expansion in its coal-burning capacity to meet its energy needs. The energy choices Indonesia makes in the next few years will have major effects on the availability and cost of energy for Indonesians, and on global climate.

President Jokowi’s initial election, in 2014, was widely greeted as great news for infrastructure in Indonesia. His electoral platform stressed implementing reform programs needed to address Indonesia’s widespread and longstanding infrastructure problems, including beginning to bring in private capital and reduce reliance on Indonesia’s state-owned monopolies. His first term did not live up to expectations on this score: government bureaucracies and vested interests have been largely successful in limiting change. Yet needs continue to grow, and the same problems and choices will now face a second Jokowi administration.

Energy is the most critical battleground between the Indonesian old guard, clearly proponents of both maintaining state control and relying on Indonesia’s coal resources to meet energy needs, and reformers. Indonesia’s current electricity consumption and production are very low for a country of its size, with production capacity of about 60 Gigawatts (GW), slightly over half of which is coal based. The country’s “Electricity Supply Business Plan” (Known as RUPTL) calls for a near-doubling of capacity, to 115 GW by 2025, including from 25 to 35 GW of new coal-fired capacity. This places Indonesia among the five countries with the largest plans for new coal-fired power.

Indonesia’s coal resources are large, and unlike Pakistan and Bangladesh, the country has been developing and exploiting these at a large scale for decades. Indonesia ranks as the fifth largest coal producer globally (After China, the US, Australia and India), and is the world’s second biggest exporter of coal, after Australia. Those resources, however, are not unlimited: Price Waterhouse Coopers forecast that at planned utilization levels, the country’s coal resources would be exhausted by 2033.

Indonesia’s domestic energy resources are not at all limited to coal. The country was an oil exporter, until falling oil production turned into an importer. It has widespread hydropower potential, albeit complicated by land ownership and biodiversity considerations, and among the best geothermal energy potential of any country. About 9 GW of total electricity capacity today is renewable energy, mostly hydropower. The latest RUPTL projected a 300% increase in renewable energy capacity by 2025, to about 35 GW: 6 new GW of geothermal, 12 GW of large-scale Hydropower, and 8 GW of wind and solar (mostly wind). However, development of renewable energy has been largely stalled, due to a combination of land/biodiversity issues affecting hydro and geothermal projects, and of inability to get wind and solar-based power production off the ground. As a result, unlike many countries which are rapidly ramping up the share of energy use based on renewables – largely because these have become the cheapest alternatives, Indonesia has been stuck: not moving forward, and trying to do so mostly with coal-fired megaprojects. President Jokowi’s legacy in Indonesia will be largely determined whether in his second term he succeeds in getting the power sector unstuck, and in moving the country into exploiting low-cost wind and solar electricity, or whether he remains mired in Indonesia’s bureaucracy and vested interests.

Part of the roadblocks to Indonesia’s development of renewable resources is complicated: the land and biodiversity issues which are involved in many potential large-scale hydropower or geothermal projects will not easily be solved. But another part is simpler: country after country is taking advantage of the combination of free-falling technology costs in wind and solar and of auction mechanisms which force competition among the world’s still-growing number of producing companies. IRENA has stated that Indonesia has 47 GW of solar power potential. At least, better said, technically simple. And economically simple. The officially estimated cost of greenfield coal-fired generation may be lower in Indonesia than anywhere else ($0.05/ kilowatt hour), but those estimates like in many other places underestimate both coal transport costs and the impact of current disruptions in the coal market, without pricing in likely medium-term scarcity costs. Wind and solar prices are already on a par with the low-end of coal-based generation prices, and continue to fall.

Where large-scale development of wind and solar electricity in Indonesia is not simple is in the politics. The state-run power utility, PLN, combines a monopoly of transmission and distribution with being the by far largest producer of power. It is an artefact in a world where most countries have separated power generation from T&D responsibilities, and where most have increasingly turned to private capital for financing new generation capacity. And as both a competitor and the eventual buyer of wind and solar power from potential new producers, its enthusiasm for the wind and solar auctions which have triggered rapid growth in renewable capacity in many countries has been superficial. PLN would far rather build power plants itself – which means thermal or possibly hydropower power – than have others build them. Its reasons are a mix of classic bureaucratic inertia and self-interest, and of links to political interests and corruption. The reasons are not economic: the government has pumped between $3 and $4 billion annually into PLN in recent years to cover losses, and letting others finance power which will come at a lower cost to PLN would reduce those losses. A recent documentary released in Indonesia, which the government has tried hard to suppress, is named “Sexy Killers,” and highlights the links between the country’s coal industry, PLN and politicians. And as noted in a recent column by Bill McKibben, the potential for bribes in small-scale, decentralized wind and solar development is far smaller than it is where single mega-projects such as coal plants involved.

The past few months have seen somewhat of a stalemate. A few renewable projects have inched forward, as have a handful of natural gas-fired projects. But large-scale auctions for wind and solar have made no progress. The 2019 RUPTL, released in March, gave more verbal support to wind and hydropower, though without indicating it would take practical steps to bringing this closer to reality. A number of coal-fired plants planned in Java were reportedly suspended or cancelled, yet have re-appeared in the new policy document, and plans for solar are minimal. As noted in its review of the RUPTL, IEEFA called the statements about incorporating more renewables “a cut-and-paste planning exercise that does little to address fundamental problems with Indonesia’s over-reliance on coal-fired generation,” and stated that “Indonesia appears to have embraced what can best be described as a contrarian understanding of power trends with the decision to add less than 1 GW of solar over the next decade.”

On April 23, the arrest was announced of PLN’s CEO, Sofyan Basir, on charges of corruption related to a $900m coal-fired power plant. Unlike in the case of competitive public auctions in wind and solar, this coal project – Riau I – was awarded directly by a PLN subsidiary to a Singaporean company (arrests include one of the Singaporean company’s Board members). A sign of the tide turning? Indonesia’s energy and economic future hangs on the decisions that will be made by President Jokowi in his second term. As does a lot of carbon.

Asia’s Energy Transformation: Bangladesh

Asia’s Energy Transformation: Bangladesh

This is the second in an Infrastructure Ideas series looking at the way energy use is changing in Asia’s major economies, and the momentous choices facing policy-makers there today. Following the previous post covering Pakistan, this post features the world’s 8th most-populous nation – and the country with one of the five biggest project pipelines for new coal-fired generation: Bangladesh.

Bangladesh, known as East Pakistan from 1949 to 1972, is the most densely populated country in the world. Its energy profile has many similarities with that of Pakistan: both countries have enjoyed significant domestic natural gas resources, which played a major role in the development of the countries’ power grids – Bangladesh’s even more than Pakistan’s. Both Pakistan and Bangladesh are relatively low-income, and have among the lowest per capita levels of energy consumption in the world, and among the highest aspirational rates of growth for future energy consumption (Bangladesh’s growth rate has been in the 6-7% per annum range). Both countries subsidized consumption of domestic natural gas resources by keeping prices well below those prevailing internationally, and in part as a result reserves have been in decline and the ability to keep supplying gas-fired power plants is now in question. Both countries have largely untapped domestic coal reserves, generally of low quality, and coal enjoys a major role in future energy planning in both. Bangladesh and Pakistan are also late-comers to renewable energy (leaving aside Pakistan’s large hydropower capacity), with Pakistan having turned somewhat earlier to initial wind and solar power auctions.

Critically, both countries face a similar fork in their energy roads: build substantial new coal-fired electricity generation capacity – potentially making them among the 3 or 4 largest builders of new coal plants in the world – or encourage large-scale development of wind and solar power. The policy choices these two countries make will have major implications for their economies and people, as well as for global climate.

Thinking about growth is essential for understanding Bangladesh’s energy choices. The country’s total power generation capacity in 2015 was only 10 Gigawatts: more than 40 countries produce more electricity than this, while only 7 have more people than Bangladesh. And this is after roughly doubling Bangladesh’s capacity in the last decade. Bangladesh’s energy policy calls for raising power capacity by 2030 to 30 Gigawatts – triple the amount of electricity produced today. That’s growth! Bangladesh needs this much power, both to make up for its very low current consumption, and to support the high growth rate of its economy.

The issue for the country is that its current sources of energy cannot keep up with existing capacity, let alone this projected tripling. Today three-quarters of electricity in Bangladesh is supplied by natural gas, and Bangladesh is running out of it. Reserves are projected to be exhausted somewhere around 2029. Taking advantage of the changes in the natural gas industry – which in the last decade have made it an internationally traded commodity – Bangladesh has begun to invest in import terminals to bring external natural gas into the country. This makes plenty of sense as policy. However, the new imported gas is likely to be needed entirely to substitute for declining domestic gas sources, and is unlikely to be a major source of new capacity. Concerned as well as it is by today’s over-reliance on gas, Bangladesh’s government has focused on diversifying energy sources, which again makes sense. The question is how best to do this.

The Government of Bangladesh’s stated energy plans have for years focused on one principal answer: develop coal. While coal produces less than 500 MW of electricity in Bangladesh today, government projections have shown 2030 capacity as high as 20 Gigawatts – essentially all the planned increase in electricity production for the country. A 20 Gigawatt coal-fired pipeline would place Bangladesh – which is not in the 40 largest power producers today – 5th in the world in new coal-fired capacity: after only China, India, Vietnam and Indonesia. Bangladesh also has an important friend ready to support this policy choice: China. Bangladesh is a country of focus for China’s Belt and Road Initiative, and for Chinese financing generally. IEEFA has reported that Bangladesh has the most proposed coal-fired capacity and funding offered from China of any other country, totaling $7 billion for 14 Gigawatt of capacity (somewhere between 1/3 and ½ of total estimated costs for these projects).

Aside from China, support for coal-fired development draws from two other major sources: one, an outdated sense of economics, and two, perceived greater profitability. Bangladesh has been worrying about running out of natural gas and needing new energy sources for over a decade; during most of this time, coal has been accepted as the lowest-cost alternative, and still today many planners and onlookers think of it that way. Given the historical subsidy for domestic gas, electricity has been relatively cheap for Bangladeshis, and politicians are wary of new capacity forcing a sharp increase in prices. This sense of coal’s cheapness has fallen out of tune with today’s realities, but opinions have been slow to adapt. Coal-fired plants are also, universally, very large projects. Very large projects also, universally, give the greatest opportunities for large profits – regrettably often of the corrupt kind: it is much easier to get rich skimming off a mega-project than from dozens of small-to-mid-size renewable projects. Coal-based electricity also means large-scale domestic coal mining, with similar opportunities.

The big drawback for a coal-based plan for Bangladesh is economic reality. The perception of coal’s cheapness does not match its real costs (and here we only mean economic cost, without speaking of externalities like emissions). Developing Bangladesh’s coal mines will be very expensive, and very large greenfield projects also come with very large risks of delays and cost overruns. Transporting the coal to power plants can also be expensive. Importing coal also has high transport costs, as Bangladesh has virtually none of the needed import infrastructure it would require to feed several coal-fired plants. So coal feedstock is not likely to prove very cheap. A best case, looking costs in neighboring India, is that Bangladesh would produce coal-fired electricity at $0.08/ kilowatt hour – about the average retail price for electricity in the country today. More likely, with all the required ancillary infrastructure, large-scale coal power would cost at least $0.10/ kilowatt hour.

By contrast, auctions almost everywhere for wind and solar power are seeing prices at $0.07/kilowatt hour – even at $0.03/kilowatt hour in a handful of countries. Prices for generation continue to drop. Prices for energy storage, required to make intermittent wind and solar power available around-the-clock, are also dropping fast. The economics of wind and solar will increasingly be better than those of large-scale coal.

The problem for Bangladesh and its policy-makers today is that successful auctions for large-scale wind or solar power require significant planning. Planning is required not only for the new generation plants, but also for associated storage, and for upgrading the transmission grid to deal with large amounts of intermittent power supply. The planning is made trickier due to the lack of available land in Bangladesh, unlike in Pakistan. While Bangladesh has some excellent people resources in its ministries and administration, it doesn’t have a great many of them. One dead-end answer being looked at has been to have the government be the one to build solar plants: this has not worked anywhere outside China (excluding China, wind and solar generation is nearly 100% privately owned), including countries with much more public execution capacity than Bangladesh.
Still, this looks like a better set of problems to have to solve than those associated with coal.

These are big decisions for Bangladesh. Get it wrong and power prices will go up, with attendant political risks. Do nothing, and the economy will strangle for lack of power. Do coal, and the climate equation for everyone gets worse.

Lately, there are positive signs that Bangladesh is making the needed course correction. The Bangladesh Power Development Board’s 2016 Annual Report noted an expected eleven new coal-fired plants to be commissioned in the next five years. Its 2018 Report has this down to three, of which one – the Rampal project – has already seen repeated delays. Gas-fired projects are moving forward closer to the expected rate, with the GE and Mitsubishi joint venture with Bangladesh’s Summit Group – signed in July 2018 to establish five power plants along with gas import facilities – slated to become the country’s largest private investment on record. But wind and solar will be needed to fill the gap and help Bangladesh keep up with growth. Another country to watch for big decisions.

Asia’s Energy Transition: Pakistan

Asia’s Energy Transition: Pakistan

This is the first of a series on the energy transition in Asia’s largest economies. Asia is the most important global market for energy consumption, investment, and greenhouse-gas emissions. Asia is also a region in the midst of a large-scale energy transition, whose pattern and evolution remains to be determined. How this energy transition evolves has more importance to the future of climate change, and to the future of energy investments, than that of any other region. Infrastructure Ideas will focus in turn on the state-of-play in this transition in several of Asia’s big economies, starting with Pakistan.

A few numbers illustrate the importance of Asia in the energy world. Between economic growth and connecting the underserved (just under 500 million of the 1 million people without access to reliable electricity are in Asia), the region dwarfs all others in expected energy consumption growth. Bloomberg New Energy Finance projects that, in Asia, over $5 trillion will be invested in power generation capacity from now to 2050, over $180 billion per annum. Asia is expected to account for nearly 50% of all such investment globally.

Power investments by region to 2050
Asia-Pacific also accounts now for about half of all Greenhouse Gas emissions, and in line with growing energy consumption, the growth rate of emissions from Asia, at over 3% p.a., is triple the growth rate of emissions of the rest of the world. Behind this high share of GHG emissions is not only overall energy consumption growth, but more importantly how much of electricity production in Asia is coal-fired. 67% of all coal-fired generation capacity is in Asia, and essentially all of the growth in new coal-fired capacity globally is in Asia. So as well-reported, Asia is the key battleground for future GHG emissions evolution, and for the scope of future climate change. How decisions are made about more coal, less coal, and the speed of adoption of renewable energy sources will have a disproportionate effect on the rest of the world and future generations.

Pakistan is a key player in Asia’s energy transition, albeit one drawing far less attention than China and India. This is somewhat surprising, given that Pakistan is the world’s 6th most populous country, with about 200 million people. Pakistan also has plans for larger investment levels in new power capacity than all but a handful of countries, and some plans to increase coal-fired electricity production by over 500%… so an important country on many fronts! Let’s look more closely at the state of play.

For a country with as many people as Pakistan, and which has recorded solid economic growth for decades, power production is remarkably low. Total generation capacity today in the country is only just over 25 Gigawatts (GWs), and per capita electricity consumption is only 2/3 of that in India, and only 1/3 of that in Egypt. While 90 million people have gained access to formal electricity over the last two decades, there are still some 50 million people without access, and industry is hampered by extensive load-shedding, often over 10 hours a day. Thus increasing power availability has been a high government priority in Pakistan for a long time, and one can expect that the country will add substantial new production capacity over the next couple of decades.

Pakistan’s power sector is of high importance – for provision of basic services, supporting economic and job growth, and for public finances. It also has some oddities. One is the unusually high share of oil-fired generation: about 1/3 of Pakistan’s electricity is produced from either diesel or fuel oil, probably the highest ratio – by far – of any of the world’s largest countries. This has had and continues to have major negative consequences in terms of higher costs, high GHG and particulate emissions, and large trade deficits (Pakistan imports most of its oil). Hydropower and natural gas-fired generation each account for just under 30% of production, coal about 5% and nuclear a little less. Another oddity (shared with a small handful of its Asian neighbors) is the high percentage of power production which is government-run, at about 50%. A 2018 World Bank Report (“In the Dark”, World Bank 2018) estimated that these public sector plants use 17-28% more fuel per output than their private sector counterparts, and that mostly public policy and management inefficiencies in electricity cost the country 6.5% of GDP annually.

In the last five years, Pakistan has entered into a new energy transition, whose direction and outcomes remain very uncertain. The key energy policy decisions going forward for Pakistan revolve around its current transition, and the 20-30 GW of new electricity production capacity it seeks to add.

It has been clear to the Government that continued reliance on oil-fired generation is financially impossible. Yet between the choices of coal, gas, hydropower, wind and solar, the right direction has not been obvious. Development of more coal-fired capacity has had many supporters in Pakistan: the country has large domestic coal resources, coal has historically been a cheap source of fuel, and some government plans have called for coal to assume an up to 30% share of electricity production – compared to about 5% today. Domestic natural gas became important in the decades after independence, but domestic fields are essentially exhausted, and new imports of gas – while important – are at best replacing previous domestic sources, and are in part diverted to domestic fertilizer production. So the share of gas-fired power production is likely to decline substantially. Hydropower may be an important part of the solution. Pakistan has important developed and undeveloped hydropower potential. In the early decades after independence, large-scale dams were constructed by the country’s public sector utility: its chronic losses and mismanagement have essentially made further investment out of the question. Pakistan has instead turned to auctions, whose winners have to date been dominated by Chinese firms, notably China Three Gorges. This holds some promise of relatively low cost and low emission capacity growth, but contentious water ownership issues close to the border with India, climate-change related hydrological uncertainties, and the sheer scale of the new plants likely limit how big a role they play in overall country capacity growth. This leaves the key uncertainties of the transition between large-scale coal-fired generation increases, and accelerated development of wind and solar resources.

While not an early adopter, Pakistan has begun to replicate the renewable energy auction procurement mechanisms which have so strongly impacted many emerging markets. Roughly 40 new wind and solar farms have been provided PPAs, and at prices (US$0.05-0.07) well below Pakistan’s average power costs.

Pakistan power costsOn the one hand, renewable energy is now the cheapest form of electricity generation in Pakistan. This should not be unexpected, given how falling costs have made wind and solar the cheapest options for new capacity in much of the world – accounting for over 50% of all new electricity capacity additions worldwide in 2017 – and Pakistan’s plentiful wind and solar resources. On the other hand, renewable energy proponents carry limited political weight in Pakistan. Proponents of expanded use of coal, by contrast, carry substantial weight – both domestic supporters who would like to see investment in local coal deposits such as the massive Thar field, and external financiers looking to sell coal and coal-fired generation plants – mainly from China. The Chief Minister of Sindh Province, where many of the country’s coal deposits lie, stated in early March that the long-delayed Thar coal-fired plant would “start soon.” Given Pakistan’s long-unstable domestic politics, and perennial foreign-exchange problems, the verdict on the country’s energy transition remains out. The implications are significant – building another 15-20 GW of coal-fired generation in Pakistan in the coming decades could add up to 100 million tons to annual CO2 emissions – an increase of 40% over Pakistan’s current CO2 emissions, and roughly what 25 million cars produce. And, given the contrary trends in prices, probably leave system-wide power costs at least 20% higher than they could be. This is clearly a country whose energy politics bear watching.

Some positive signs? In January, the 1,320 MW, the proposed Rahim Yar Khan imported coal-fired power plant was shelved, reportedly over concerns about increased fossil fuel imports. And in February, during a State visit, Saudi Arabia’s ACWA power, one of the largest wind and solar generation companies globally, was quoted as seeing the potential for up to $4 billion in investment in renewables in Pakistan.

Renewable Energy as 2019 begins: Winners and Losers

Renewable Energy as 2019 begins: Winner and Losers

Renewable energy continued in 2018 as the largest segment of infrastructure financing globally. Utility-scale wind and solar, and rooftop solar new capacity installations grew again. The days of double-digit industry growth in capacity, however, seem to be past, and with falling costs the total capital going to renewables is clearly at a plateau. There’s good news and bad news for different parties, and in this column infrastructure ideas offers a guide to the winners and losers of the moment.

The numbers for 2018
Based on just-released figures from Bloomberg New Energy Finance, the fastest to estimate year-end numbers, “clean-energy investment” was down 8% from 2017, yet nonetheless, at $332 billion, over $300 billion for the fifth straight year. Within those numbers, investment in all segments were up except for two: small scale-hydro, and solar power generation – the latter seeming counter-intuitive but we’ll unpack it below. Onshore wind investment rose slightly, 2% to $101 billion, while offshore wind came into its own for the first time, recording $28 billion in investment. Bio-mass, waste-to-energy, biofuels and geothermal were all up from 2017, yet together accounting for only about 3% of total investment. Investment in solar, interestingly, fell from $160 billion to $131 billion. Two big factors seem to be have driven the plunge: one visible everywhere, with the cost per unit of new solar capacity continuing to fall be double-digits in 2018, and overall capacity installed still grew from 2017 though the costs of this declined; the other factor being visible mostly in China, where big policy changes led to a 32% fall in new renewables investment in the world’s largest solar market. India’s market, arguably the fastest-growing market in the world from 2015-2017 for new solar financings, also cooled off, with clean energy (mostly solar) financings falling from $13 billion to $11 billion.


1. Investors looking for RE assets. For investment funds and others who built up capacity to finance renewable energy, assets are increasingly there. The $300 billion in new financing in 2018 means renewables continue to be the biggest game in town, with over $2 trillion having been invested in these sectors in the past decade. And while the overall global market may have been slightly negative, the sharp slowdown in China obscures good growth outside of China: non-Chinese investment in wind and solar increased over 20%, and the non-Chinese share of the global RE market went from 45% to 60%. Given how relatively closed the Chinese market has been to external investment, this means the effective pool of investable RE assets has grown significantly.

2. Offshore wind in OECD. Offshore wind, a curiosity only a few years ago, is at $28 billion now the fourth largest segment of clean energy – after onshore wind, utility solar and rooftop solar. It dwarfs other clean energy segments such as geothermal, biomass and small hydro. For many infrastructure funds, offshore wind has another attraction: large average project size. So while there remain a limited number of offshore assets, and they are all limited to either OECD markets or China, this is clearly now a legitimate and important sub-market.

3. Policy-makers. The continued declines in the costs of solar, and to an extent onshore wind capacity, are great news for energy sector policy-makers. In particular, energy sector policy-makers in developing countries – whose task is to address insufficient power capacity and/or high-cost electricity systems – have now at their disposal the means to increase power availability and to sharply cut the average generation costs of power in their economies. Wind and solar power at below 6 to 7 cents a kilowatt/hour – or even below 3 cents are a number of markets are achieving – means new capacity at less than half the average tariff in many developing countries. And everywhere, policy-makers concerned over greenhouse gas emissions and looking to meet “green” policy mandates have well-established options for their electric systems.

4. Solar plus storage advocates. Not yet in the numbers but worth a flag. While new capacity of solar-plus-storage systems account for less than 1% of total 2018 investment, and does not show up in global clean energy numbers yet, one can see this is just around the corner. With energy storage costs plummeting as fast as solar panel costs did a decade ago, we are already beginning to see the first solar-plus-storage tenders emerge with costs competitive with or bettering the costs of new thermal power capacity. Look for this segment to be bigger than biofuels or geothermal within the next 1-2 years, and larger than the offshore wind segment within 5-10 years.


1. Investors looking for RE assets. If the big loser sounds like the big winner, that’s because they are one and the same. There are indeed more and more renewable energy assets available in which to invest, and a greater share of these is “market,” as the non-China share of this segment is where growth is concentrated. At the same time, though, price and risk of RE assets are an increasing concern for investors. Solar power-purchase agreements (PPAs) are increasingly being priced so low that making money has become an increasingly tricky proposition. Or put another way, the benefits of falling RE costs are being largely apportioned to consumers (and policy-makers), leaving thin margins to compensate providers of capital. And at the same time, many markets are seeing shorter PPAs being offered, meaning new solar and wind farms have shorter periods of guaranteed returns, and face the prospect of yet lower-priced competitors when the guaranteed-return periods come to an end. And more investors are coming late to the party, further pressuring returns. Assets are there for investors, but making good returns from them will require being smart.

2. China RE portfolios. If you had financed wind and solar assets in China during the past decade – and if those assets were not being curtailed by the Chinese grid (a big “if”) – things were not too bad through 2017. Not only has China been by far the world’s largest renewable energy market for several years, it’s also paid some of the highest prices for renewable-generated power through Feed-in Tariffs. The kind of wind and solar auctions which have been so effective at driving down the cost of new capacity in Brazil, India and South Africa, among other markets, have come late to China. But with the big policy changes enacted in 2018, China was more disrupted than any other market. Going forward it will be a new game, with China adopting the auction approach – post the 2018 disruptions, this is likely to be good news all around: cheaper RE power across China, increasingly competitive with existing coal-fired capacity and less likely to be curtailed. It will mean, however, a new approach to the Chinese market.

3. Thermal power. New RE capacity additions were more than double the roughly 70-80 GW of new thermal power capacity added worldwide in 2018. Even with the growth of natural-gas fired capacity in the US and China, thermal power is becoming a shrinking market for operators and investors. And this is with continued historically-low natural gas prices, in the $3-5 mmbtu range. Driving this shrinkage is the combination of declining cost-competitiveness of thermal power, as technology improvements are unable to drive down costs as fast they are declining in renewables and energy storage, and policy preferences in many markets. It’s not going to get any better, though natural gas – especially in combined-cycle plants, is increasingly outcompeting coal-fired generation.

4. Small hydro. In the days of early enthusiasm for renewables, hydropower enjoyed a boost in popularity, riding on the same wave propelling new technologies. Small run-of-the-river hydropower plants especially, seen as more environmentally-friendly than large dam-reliant hydropower, began to attract considerable interest from operators and investors. The 2018 numbers show that small hydro has been left far behind by its former renewable peers, wind and solar. At only $1.7 billion, about ½ of 1% of all clean energy investments, and one of the only categories declining in 2018, it looks like the lost stepchild.

5. Proponents of a 1.5-degree limit. For those concerned about climate change, and especially those wanting to see the world on a course to limit global warming to 1.5 degrees, 2018 was not a good year. Yes, renewable energy capacity is growing, and new investments are almost double those in fossil fuel-based power generation. But even with this, the penetration level of renewables in the overall share of power generation is too low for a 1.5-degree warming scenario. Given that the rate of increase of renewable generation has slowed, it becomes harder to see climate mitigation efforts relying just on the economics of new generation facilities. So expect, therefore, both to see escalating effects of global warming – more extreme weather events, more calls for climate adaptation investments – and growing odds of a major discontinuity in energy policies down the road. One good bet: growing interest in funding decommissioning of fossil-fuel generation – watch this space for a forthcoming analysis of the topic.