The Future of Natural Gas Pipelines

July 2020

The month of July was not kind to the Oil & Gas pipeline business.  In a span of days, three major US pipeline projects were halted, in three different parts of the country.  The headliner was the Atlantic Coast Pipeline, a US$8 billion 600-mile natural gas pipeline project across West Virginia, Virginia and North Carolina: at the end of June, sponsors Dominion Energy and Duke Energy won a major battle at the US Supreme Court, receiving approval to cross the Appalachian Trail; a week later, the sponsors issued the stunning announcement that they would no longer seek to complete the project.  That same week, the Dakota Access Pipeline, after years of protests and battles with lawsuits, was ordered by a Federal Judge to cease transporting oil from the shale-oil fields of North Dakota to the Gulf of Mexico.  The Williams pipeline was intended to bring Pennsylvania fracked natural gas to the New York City area through a 200-mile pipeline, at a cost of over $1 billion, but – again the same week — failed to obtain its needed permits from either the state of New York or the state of New Jersey.  Yet another project, which has faced high-profile legal challenges for years without getting off the drawing board, the Keystone XL oil pipeline, saw an appeal from the current US administration to let it proceed turned down by the US Supreme Court.  A New York Times headline at the end of the week asked “Is This the end of New Pipelines?

Infrastructure Ideas had reviewed recently the prospects for the Natural Gas business as a whole (“What Next for Natural Gas?” from June 2020).  This post takes a follow-on look at the business of natural gas pipelines.  And a rising new competitor in energy transport.

It seems like only yesterday that the natural gas pipeline business was booming, a bright spot where so few large infrastructure projects were proceeded.  In the US alone, there are ongoing projects involving some $60-80 billion of investment in Oil & Gas pipelines, and projects worth close to $100 billion more have been announced.  Now the future looks uncertain, at least for any pipelines crossing outside of Texas and neighboring friendly states.  The same factors that have turned the situation upside down in the US are not yet playing out with the same visibility in the rest of the world, but one should expect that they will.

Environmentalism gets the loudest credit for derailing the pipeline projects in the news.  In the case of the Atlantic Coast Pipeline, legal challenges – based on “Not in My Back-Yard-ism,” environmental concerns along the planned pipeline route, and climate change concerns – had major impact.  The estimated costs of the project rose from $5 billion to $8 billion due to the related delays, and even a Supreme Court victory on one issue was no insurance against the risk of successful challenges on other issues.  Dominion CEO Thomas Farrell told investors “To state the obvious, permitting for investment in gas transmission and storage has become increasingly litigious, uncertain and costly.”  A piece in Forbes along the same line pointed out that pipelines were increasingly losing in the courts.

One aspect worth noting of the court decisions tilting against pipelines is the role of insufficient due-diligence.  The current US administration, among others, has sought to increase the level of infrastructure investment by encouraging the bypassing of environmental and social reviews, which is precisely what sank the Dakota Access Pipeline.  In the case of the ACP, judges repeatedly found that reviews had been inadequate and incomplete, forcing delays and cost increases.

Yet while environmentalism played a major role, what really bodes ill for the pipeline business, and what underlay the decisions made this month going against the projects, is economics.  The price of electricity from wind and solar increasingly is beating the price of electricity generated from natural gas.  Economics going forward will only get worse.  Technology is continuing to make solar and wind power cheaper, while natural gas prices are now, on the one hand, too low to enable many players in the business to stay afloat and explore and develop more gas reserves, and on the other hand being pushed up as the cost of transport pipelines are going up.  Combine this with the kind of regulatory concerns over emissions which have been growing in the US northeast, and more recently Virginia, and you have a battle going increasingly in favor of renewables, and increasingly against natural gas.  A report out of the Goldman School of Public Policy in Berkeley last month went as far as claiming that the US electricity grid could lower rates while getting 90% of its supply with no greenhouse gas emissions by 2035.

In a tell-tale sign of how big the ongoing shift is, the same day that it and Duke Power announced they would abandon their $8 billion project, Dominion Energy also announced that it would sell most of its natural gas assets to Warren Buffet’s Berkshire Hathaway, in a transaction valued at close to $10 billion.  The sale includes over 7,000 miles of natural-gas pipelines.  For a utility that has relied almost exclusively on coal and natural gas, and been one of the staunchest defenders of fossil fuels, the two announcements heralded a major watershed.  Dominion, the 6th largest US utility by revenue, will instead shift its business to wind and solar power.  It is already competing to become of the largest players in the burgeoning offshore wind industry (see “Offshore Wind: the Next Big Thing,” January 2020).

Coincidentally, the book out this month Lights Out: Pride, Delusion and the Fall of General Electric by a pair of Wall Street Journal reporters, focuses on the massive losses incurred by GE Power, one of the biggest players in the energy business worldwide.  Most of the blame for these losses, along with general opacity of finances and practices, is laid in the book at the feet of decisions made by former GE CEO Jeff Immelt to bet the house on natural gas – especially with his single largest acquisition, that of French natural gas turbine producer Alsthom.  Too much, too late, for the natural gas business.

Contrast the fate of the O&G pipelines with that of the Grain Belt Express.  One big energy transmission project which is going forward in the US at the moment is the 800-mile, $2.3 billion, 4-Gigawatt high-voltage power transmission line, which will tap convey wind-generated power from Kansas through Missouri and into Indiana and Illinois.  This is also a new generation of energy transport: the high voltage DC/ Direct Current line. Today’s transmission lines run on alternating current, and AC transmission involves significant energy losses over distance.  In a future where renewable energy resources are often located far from the centers of consumption, long-distance DC lines like the Grain Belt Express will be a major focus of new infrastructure investment.

Outside of the US, chances are that new opportunities to invest in natural gas pipelines will also be limited.  China is certainly one place where more will be built.  But there the assets will be owned by the Government.  The Government announced in late 2019 that it would establish a National Oil & Gas Pipeline Company (“Pipe China”) by combining pipelines, storage facilities and natural gas receiving terminals operated by China National Petroleum Corp (CNPC), China Petrochemical Corp (Sinopec Group) and China National Offshore Oil Company (CNOOC).  Beijing aims to complete the asset transfers and start operation of the new entity – valued by industry analysts at more than $40 billion – by October 2020.

In Europe, the mega-project pipelines envisaged to bring either Russian or Caspian Sea natural gas to western Europe consumption centers will face an increasingly precarious future.  Incentives to built wind and solar resources have always been more generous in Europe than elsewhere, and combined with the ever-cheaper availability of wind and solar, will make natural-gas generated electricity begin to look like an expensive choice.  We can also anticipate that, as concerns around climate change continue to grow, political pressure to reduce or eliminate energy-sector greenhouse gas emissions will be strongest in Europe.  This is increasing the risk that, even with long-term offtake contracts in place, the owners of pipelines bringing natural gas to Europe will face the kind of scenarios which have played out in the US this month: legal challenges and regulatory decisions that shorten their life-span significantly.

In the rest of the world?  LNG import terminals will retain their attraction for a time, as they raise few of the local environmental and social concerns, notably rights-of-way, which arise with pipeline construction.  But the future of within-border energy transport increasingly looks to be with long-distance DC electricity transmission lines, and not with natural gas pipelines.

 

 

What Next for Natural Gas ?

June 2020

2019 was a record year for Liquified Natural Gas (LNG) producers and shippers. Global demand continued to grow strongly, 12.5% from 2018, to a record 359 million tons. Imports grew mostly to Europe, but also to South Asia. Relative newcomers to LNG imports, Bangladesh, India and Pakistan imported a collective 36 MT. Consumption in China, the third largest importer after the UK and France, grew 12%, continuing to outstrip domestic production growth. The year-to-year increase in trade, at 40 MT, was itself another record, and brought the increase for the last four years to 95MT, meaning the LNG market had increased by almost one-third in only three years. The spot LNG market, which facilitated flexibility in sales compared to standard long-term contracts, had grown from just over 10% of the market at the beginning of the decade to nearly 1/3 of all sales. The market had grown so attractive that the rush was on to jump in: 30 MT of new capacity came on stream in 2019 – on top of 100 MT from 2016 to 2018, and financing for 71 million tons of new capacity reached FID. Meanwhile on the domestic side in the US, natural gas continued to be attractive as a source of supply for new power plants as coal capacity is being phased out – with gas now being far cheaper than coal. Of the last 29 GW of coal power generation retired, 23 GW have been replaced with natural gas, especially in the large PJM interconnect market.

2020, after the record 2019, could have hardly have come as a bigger shock for the gas industry. Thanks to COVID-19, 2020 will see the largest annual drop in energy investment in history: 20%, according to the International Energy Association. The projected drop in investment in oil & gas is even larger, 33%, and after the record 2019 for new LNG FID decisions, the expectation for 2020 is… zero. Natural gas prices have been hovering around historical lows of $2/MMBTU. Oil prices have shown some recovery, after the Saudi Arabia-Russia deal to curb surpluses, but the global gas market remains extraordinarily oversupplied. With LNG storage nearing capacity, as happened in April for oil, the worst is likely still to come, and negative prices for LNG cargoes late this Summer cannot be ruled out. Unlike the oil market, there’s been no sign of a coordinated response to address the glut, meaning the fallout could be deeper and longer. For the fracking-focused companies in the US, the outlook was already grim, and it is only getting worse: in 2019 42 E&P companies filed for bankruptcy, involving over $25B in debt. Moody’s noted “We are seeing slowdowns and negative cash flows spill over into the oil services sector that relies on the E&P companies for their business, and heavy hitters such as Schlumberger and Halliburton recorded significant losses in 2019.”

Natural gas tanker

So what’s next?

Optimism has been ruling projections of the future of natural gas for several years. With the increased production from the development of new E&P technologies, and a vast increase in investment in transport capacity, natural gas became cheaper than all other fossil fuels – including coal – and far more widely available than before. With growing concerns over carbon emissions and climate change, gas also benefitted from being seen as better than coal on the environmental side. Forecasts at the end of 2019 projected a near-doubling of global LNG demand from 2018 to 2035 (McKinsey, Shell), outpaced by even faster growth in supply – excess supply was expected to keep prices low into the mid-to-late 2020s. In the US, a 20% growth in demand from the power sector was seen by 2025, and the industry announced plans for some $30B in new interstate pipelines over the next five years. Only the production end, as noted above, was seen as facing continued difficulties.

Optimism is now on hold, pretty much across the board. In one year, LNG prices in Asia – the highest in the world — plummeted from $12/MMBTU to $2/MMBTU. Courtesy of the IEEFA, here is a list of the LNG projects put on hold or cancelled in the last three months:

• March: Santos-Barossa/Darwin (Australia); Sempra-Costa Azul/Port Arthur (Mexico-USA); Woodfibre (Canada); Woodside Energy – Pluto Train 2 (Australia); Shell/ETP – Lake Charles (USA); Magnolia LNG and Bear Head (USA-Canada)
• April: Qatar Petroleum – North Field East (Qatar); Shell Crux (Australia); Exxon Rovuma (Mozambique); Golar/BP Grande Tortue (Mauritania and Senegal); Pieridae/ Goldboro (Canada)

McKinsey’s annual natural gas outlook for 2019 had noted that of the 100 projects potentially planned to add new LNG capacity, each would need a maximum full break-even price of $7 per million British thermal units (MMBTU) to stay competitive: more than three times current prices in Asia – the “strongest” LNG market, with prices possibly heading still lower.

For the US power market, probably the largest user gas user, forecasts from the EIA have now shifted significantly. In 2019 the EIA had estimated natural gas would be the largest segment of the US power market until well beyond 2050, with an 8% higher share than renewables even in 2050. The new 2020 EIA outlook instead sees renewables with a 2% higher share than gas by 2050. Interconnection queue requests across all the major North American markets show that over 90% of new requests now consist of solar, wind and storage. This is spite of gas prices not only being low being getting even lower. The problem? A combination of costs and policy. From a cost standpoint, the fall in natural gas prices is being paralleled by continued technology improvements and falling costs for wind, solar, and energy storage. The cost declines of wind and solar, being technology-driven, are unlikely to reverse themselves, whereas the cost of declines of natural gas, now being driven by supply-demand imbalances, have an unpredictable future. From a policy standpoint, the “climate honeymoon” of natural gas has waned, if not ended. Three converging environmental trends are working against natural gas: (1) growing concerns on the climate front, as this week’s news indicate that even lower emissions during the COVID epidemic do not seem to have reduced atmospheric carbon levels, and climate change projections continue to get worse; (2) new studies of methane leaks are increasingly raising estimated average emissions from natural gas related projects, making natural gas now seem only marginally better than coal on the emissions side, and far less preferable than renewables; (3) studies on fossil fuel pipeline environmental effects are also raising the level of concern of damage from natural gas transport (a study of the 2010-2018 period in the US documented more than 5,500 total pipeline incidents, more than $4 billion in damages, and evacuations of almost 30,000 people – with a strong and unexpected correlation between the number of problems and how new the pipelines were). A number of US cities (San Jose is the largest) and utilities have moved to impose bans on new natural-gas infrastructure. Even existing gas power plants are becoming policy conversation targets, for possible replacement by cheaper renewables: in mid-2018, already, GE closed a $1B natural gas plant in southern California only 10 years into a planned 30-year life. Even the more politically conservative Midwest has seen regulators decline to endorse new gas-fired plants. In Europe, the European Investment Bank (EIB) announced in November that it will stop backing fossil fuel energy investments, including natural gas, in 2021 unless they negate their emissions through carbon capture or offsets.

The answer to what’s next for gas is, well, not much fun. At least for gas exploration, production, and transport companies. On the one hand low prices are likely to persist, which will lead to an increased number of bankruptcies in the E&P sector, and keep investors in LNG liquefication, transport, and gasification on the sidelines for any new projects, possibly into the middle of the decade. In the short-run, existing importers using spot prices (and not locked into long-term contracts) will see a windfall of cheaper gas imports. Importers locked into long-term contracts at higher prices may well take the opportunity to push for downward price renegotiations from suppliers, and in some cases possibly even walking away from contracts: when the contracts were entered into, accessing natural gas supplies looked difficult, in the future this is unlikely to become the case again anytime soon. The decades-long seller’s market is now a buyer’s market, for the foreseeable future. Good for users, but making it even worse for producers. Policy concerns in Europe and the US on emissions will likely keep dampening demand in a way that previous projections had not captured. This will leave Asia as increasingly the only attractive market for sellers. For the power sector, “peak gas” may arrive very soon, at least outside of Asia. In turn, expect natural gas suppliers to become more dependent on non-power demand, where electrification will take longer to materialize. That 100% increase in global LNG demand over the next two decades forecast at the end of 2019? It may have a hard time reaching 50%.

Silver Linings

Silver Linings: the COVID-19 crisis and infrastructure
May 2020

The COVID-19 epidemic has transformed pretty much all aspects of life over the past three months. Our previous Infrastructure Ideas column, written in the early days of the pandemic, outlined some of the possible effects of COVID-19 on the world of infrastructure. As is the case in so many areas, the implications were depressing. It is also apparent that positive news are in great need – and not based on distorted data and magical thinking, as can be seen coming from some quarters. Today’s column looks then at some silver linings for infrastructure in the pandemic era – and there are some!

We’ll start with the two most obvious “winners” from the crisis: logistics, and emissions reductions.

1) New and expanded logistics opportunities. As can be readily seen on any highway or city street, the amount of goods being delivered to homes through (generally) online orders has skyrocketed in 2020. The world’s biggest retailer, Walmart, has reported a 74% increase in e-commerce sales for the last quarter. Volumes have grown so sharply that even logistics giants are having difficulties keeping up: FedEx has asked several of its major store clients to slow or limit home delivery sales in order for FedEx to be able to manage shipping logistics. Amazon, possibly the biggest winner of all, announced back in March that it would be hiring for as many as 100,000 new positions, mainly in warehouse handling, and reported a 26% increase in quarterly sales – an impressive feat for a company with already over $200 billion annual revenue. And providers of logistics software and supporting services are also thriving.

The jump in demand for infrastructure logistics driven by e-commerce and home delivery services is broad-based and likely to remain with us. As Coronavirus infections continue to spread into new areas, demand is growing in virtually all geographies. An example is the three-year old Colombian company Liftit, recipient of an investment from the IFC. Liftit provides a technological platform that connects truck drivers with companies that need cargo delivered (similar to a ride-hailing app), and has already expanded beyond Colombia. The matching of large customers with truck fleets is a crucial link in the supply chains, especially in regions where the majority of drivers are independents (See more on Liftit here). In Pakistan, a similar app-based service connecting people and goods via motorbikes in major cities, Bykea, is getting a far-higher profile through the delivery of food parcels for thousands of people during the crisis. Bykea uses smartphones, a call center comprised mostly of women working from home, and a network of 30,000 motorbike driver-partners. In Africa, the use of drones for logistics has gotten a major COVID-related boost from the demand for transporting test samples to labs. US startup Zipline has launched operations for its pilotless flying vehicles in Ghana and Rwanda, also using them to ship protective equipment, vaccines, drugs and other supplies. These kind of advances, combined with changes in consumer demand (buyers who discover convenience which they had not tested previously, and/or those who remain wary of crowded retail shopping situations in the future for health reasons), will continue to fuel logistics growth well into the future. And an analysis by the Brookings Institute (Could COVID-19 help logistics?) shows some of the labor-related benefits of logistics jobs indicates that these jobs often carry good training opportunities with transferrable skillsets, and potentially higher pay relative to low formal educational barriers to entry.

2) Emissions reductions. An international study of global carbon emissions found that daily emissions declined 17% between January and early April, over 1,000 metric tons compared to average levels in 2019, and could decline anywhere between 4.4% to 8% by end 2020. That would mark the largest annual decrease in carbon emissions since WW II. Carbon reductions are primarily driven by fewer people driving — surface transport activity levels dropped 50% by the end of April. This was equal to (50%) the fall in the amount of gasoline supplied in the US—a close measurement of direct consumption— over the two-week period ending April 3.  With all those cars now sequestered in garages, air quality around the world has gone through the roof. As reported in Wired, researchers at Columbia University calculated that carbon monoxide emissions in New York City, mostly coming from vehicles, fell by 50% in March. Another positive side effect of this is on public health: research from the Harvard School of Public Health has shown that air pollution is associated with higher Covid-19 death rates, even small increases in long-term exposure to fine particulate matter leads to significantly higher mortality. Chances are not great that emissions will stay on this path post-crisis, but for now this piece of news is good for the climate.

3) Acceleration of the energy transition. Aside from the two obvious winners above, there are other interesting trends flowing more under the radar. One is on energy transition. While it is likely that energy use will rebound sharply after the pandemic, its carbon intensity should be lower. Of particular interest is that while the coronavirus lockdown will cause the biggest drop in energy demand in history, it looks like renewables will manage to increase output through the crisis. The International Energy Agency (IEA) says that demand is likely to fall 6% in 2020, with rich countries showing a steeper decline, the U.S. falling 9% and the European Union losing 11%. Global oil demand is poised to slump by about 9%, coal demand is falling about 8%, and natural gas about 5%. Yet the IEA expects production of wind and solar to grow in 2020. In the first week of April, it was widely reported that wind and solar had produced more electricity in the US than coal did for two months in a row, for the first time on record. A Wood Mackenzie analyst, Matthew Preston, notes that coal is now more expensive in most of the US than natural gas, wind or solar energy: “Just about everything that can go wrong, has gone wrong for the coal industry.” More banks, including HSBC in April, have announced the cessation of coal financing; HSBC’s announcement closed previous loopholes for coal plants in Bangladesh, Indonesia and Vietnam, and included a Vietnamese project for which it was the global coordinator. HSBC had reportedly financed $8 billion of new coal plants over the past three years. While oil and gas prices have fallen sharply in 2020 to date, there are signs of supply reductions and cost increases on the post-crisis horizon. Moody’s had announced already in late 2019 that 91% of all US third-quarter defaulted corporate debt was due to oil and gas companies. As wind and solar prices continue to fall (see below), coal’s lack of competitiveness will grow, while gas will also have an increasingly harder time competing on costs against renewables. Expect that projections for renewables’ share of the energy mix in future years begin to tick up.

4) Technology continues to move forward. The single brightest development in infrastructure for the past decade has been that energy has been getting cheaper around the world, driven initially by the increased supply of natural gas enabled by new imaging and drilling technology, and in more recent years by the continued technology-led plunge in wind and solar costs. While these gains have fallen out of the headlines during the COVID-19 pandemic, they have been continuing.

In late April, yet another global record-low solar price was achieved. And it was achieved for the world’s largest solar project. Abu Dhabi announced that the winning bid for its Al Dhafra project – which at 2 Gigawatts will be the largest single-site solar energy project in the world – came in at a stunning 1.35 US cents per kilowatt-hour. A consortium of EDF and JinkoSolar was the winner. This breaks the previous record of 1.6 cents/Kwh from January in Qatar, and 1.7 cents/Kwh from November 2019 in Dubai. An even larger project, on multiple sites within one solar park, Bhadla solar power park in Rajasthan, India, became fully operational in March. The park has 2.25 GW of now operating solar capacity. The solar park saw multiple record-low tariffs (down to US 3.8 cents/Kwh) during some highly competitive auctions. More and more wind and solar capacity is also being developed in “hybrid” projects including battery storage. According to the US Energy Information Administration there are already 4.6 GW of wind, gas, oil and photovoltaic power plants co-located with batteries in the U.S., with another 14.7 GW in the immediate development pipeline and 69 GW in the longer-term interconnection queues of regional power markets. In the interconnection queues, a quarter of all proposed solar projects are combined with batteries, and in bellwether California, almost two-thirds of solar projects are proposed as hybrids. Power-purchase agreement prices for hybrid power plants are continuing to plummet, with declining costs for wind, solar and batteries as these technologies mature. And on the newer-technology end, in early May Minnesota utility Great River Energy confirmed it will deploy a one MW battery with 150 hours capacity – completed unprecedented for the energy industry. The battery, an “aqueous air” battery system from Form Energy, is due online late 2023, and increases contracted battery storage records by more than 20 times. This is the first announced deal that will take the technology out of the lab and deploy it in a full-scale power plant context. In conjunction with this, Great River Energy, the second-largest power supplier in Minnesota, announced plans to phase out coal power. The arrival of long-duration storage will be another major turning point for energy systems worldwide.

5) And some miscellany. While not rising to the level of the previous four positives for infrastructure, there are a handful of other interesting developments for infrastructure investors and users to keep an eye on during the pandemic. One is around highly depressed air travel: while airlines seem to be doing a reasonably good job keeping flying as virus-free as possible, conditions at airports have potential travelers very concerned about returning to flying. This may well lead to a push for building new airport terminals of very different designs than current terminals; “Future-proofing” has become an “in” term for airport designers, with both health screening facilities and more spaces to enable social distancing than today’s terminals, which often seek to maximize density. This may entail terminals built with steel instead of concrete to increase flexibility, as well as very different uses of space. Investors may see an unexpected area to put capital into infrastructure here. A second area is expanded broadband access. As more schools across more jurisdictions try to implement distance learning, the importance of accessible internet where it is today not available has shot up the list of political priorities. Close to 200 countries have announced or implemented school closures in 2020, with the majority seeking to implement online courses, and quality of internet access has become a major issue. We can expect this area to draw on a far greater portion of public infrastructure spending – possibly as Public-Private Partnerships – as a result of the crisis. A third and related area stems from the exponential increase in online courses driven by the crisis and school closures. This, combined with improved rural broadband access, could become a major factor in expanded technical training in developing countries. Lack of trained staff is a significant bottleneck for rail, logistics, and other infrastructure services in many countries. Fourth, bicycle-sharing and e-bike programs look like they may gain from the crisis. While initially bike-sharing plunged from concerns over potential virus spread, they have strongly rebounded in many places. Bicycle ridership has soared generally, as public transit is viewed as a source of virus exposure risk and some cities close streets to cars to enable more socially-distanced walking (and biking), and sterilizing equipment has emerged as easier for shared bicycles than for shared cars. Miami is one place that has also launched expanded e-bike delivery services during the pandemic. And fifth, the virus may stimulate greater attention to urban sanitation generally, as urban areas have been disproportionately affected by COVID-19. Perhaps we may at long last see an uptick in public infrastructure spending in sanitation, or greater willingness to consider Public-Private-Partnerships in the area.

These are trying times for everyone, including in infrastructure. But at least there are silver linings. We all need positives some of the time. And at some stage, the crisis will be over!

Money for Coal

March 2020

At least in Germany.

In October 2019, Infrastructure Ideas flagged a coming decommissioning wave for coal plants, and projected a future where coal-fired power plants are paid not to generate electricity, but to stop doing so. In January, that future arrived. As reported by the New York Times and others (How Hard Is It to Quit Coal? For Germany, 18 Years and $44 Billion), Germany approved on January 29 a plan to pay coal workers, companies, and producing states $44 Billion to close producing plants before the end of their technical life. Producing companies will receive $4.8 billion over the course of the next 15 years in compensation for shuttering their coal-burning plants, some of which will be replaced by natural gas-burning generators. The plan foresees taking 19 coal-burning power plants offline in the coming decade, beginning with the dirtiest plants later this year.

coal-exit-path-capacity-closures-felixmatthes1

This plan goes far beyond the one floated in Germany in the Fall of 2019 to use auctions to fix costs for early coal plant retirements. That plan had some attractive features, including the use of market mechanisms to reduce the cost of the program, but was judged to still leave too large a residual problem. In other words, Germany concluded that a voluntary program would leave too many coal-fired plants still operating, and they were willing to pay the cost of a mandatory one. That same dynamic is likely to play out at the larger global scale: market-based incentives, such as Germany’s reverse auctions, may well be a useful tool to begin the process of early coal-plant retirements; but mandatory, and negotiated, closures will be necessary – and probably on a much-larger scale than voluntary closures.

What can we learn from Germany’s experiment?

1. There is a lot of pressure from climate and environmental groups to take action against coal-fired electricity generation. Germany arguably has one of the largest concentrations of such groups, and it is not surprising that the first concrete plan should be found here. But that pressure can be expected to intensify and broaden geographically. German pressure was fueled in part by signs that the country was falling well short of its announced emission reduction targets (see McKinsey’s analysis on this topic). The same signs are apparent in much of the world.
2. Voluntary plans – the centerpiece of global climate negotiations to date, including the Paris Agreement – only take you so far. Mandatory plans for energy transition are needed to create impacts in line with climate objectives.
3. A forum that allows multiple voices to be heard – in this case the “German Coal Commission,” which worked for two years on crafting and negotiating an outcome that could be as widely supported as possible – plays a major role in crafting any “mandatory” agreement.
4. The technical costs involved with fast-tracking coal plant shutdowns are high, but not nearly as high as the costs of adjustment for workers and regions that have come to depend on coal for their livelihoods. In the case of Germany, a whopping 90% of the $44 billion plan is headed elsewhere than the generation companies who will be shuttering their plants.
5. The bill is high for putting in place a mandatory plan in a fair and consensual way. The German plan puts a price tag of around $1B per GW of coal-fired power retired.
6. For all its ambition and its hard-won consensus, the German plan may still wind up reopened. There are provisions for periodic domestic review of the plan and its execution. And there may well be international calls for speeding up the timetable, if global emission and warming projections worsen – which we believe they will. Either of these two could lead to higher costs than now contemplated for the plan.

Today Germany, tomorrow the world?

Aside from the German plan, there was related news in January that the European Union aims to create a €100 billion fund to aid the transition of Eastern European countries to cleaner fuels. This was a centerpiece of the much-discussed “European Green Deal.” The EU’s “Platform for Coal Regions in Transition” works similarly to the German Coal Commission, as a forum for working out details of transition and compensation for affected parties, to be embedded in a “Just Transition Mechanism”.

The details of the proposed EU plan illustrate an important additional lesson beyond that of Germany. Finding the money to finance this type of climate change-driven transition will be enormously complicated. While the overall envelope for funding envisaged is roughly in line with that of the German plan – about $1B per Gigawatt of generation capacity to be retired – the funding mechanics are very different. Whereas the $44B German plan simply call for payments from the state budget, the €100B EU plan calls for only €7.5 of direct EU funding, to be leveraged by loans (some from the EIB), national budgets, and funds from yet-to-be-found investors. The basic principle of leverage is generally a good one – an early US state plan for retiring coal capacity, in Colorado, aims to manage associated costs by de-facto borrowing from ratepayers — but in this case sounds highly aspirational, and conveys a sense of considerable fragility in the future implementation of the EU plan. Just yesterday, the EU admitted it would take a “herculean effort” to make the plan work.

South Africa has also floated a “green plan” to shut down coal-generating capacity – if other countries will pay it to do so, as previously flagged by Infrastructure Ideas. However, the Government backed away from this idea in the October 2019 release of its next electricity “integrated resource plan,” keeping earlier blueprints for continued adding of coal-fired generation capacity. The dropping – for now – of the idea to sell Eskom’s loss-making coal fleet to “climate investors” has been ascribed to the inability to find a domestic political consensus, with Eskom’s unions reportedly leading the opposition. The plan now on the table leaves unaddressed the issue of Eskom’s near-bankrupt financial state and some $30B in debts, and so shares a high degree of aspirational thinking with the EU’s plan for Eastern Europe.

The pressure underlying these first “pay for coal” plans is going to increase, and increase rapidly. Coal-fired power generation continues to be the single largest emitter of greenhouse gases, accounting for 30% of all energy-related carbon dioxide emissions. In all climate models, phasing out coal from the electricity sector is the single most important step to get in line with holding global warming to 1.5 or even 2 degrees, and as time passes it is increasingly clear that canceling potential new coal plants will not be enough. The late 2019 report from Climate Analytics shows 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 1,600 GW of generation capacity. Applying the cost of the German plan, $1B/GW, would imply costs on the order of $1.6 trillion to shut down this much global capacity.

We would expect such plans for fast-tracking of coal plant retirements – now that at least Germany there is a tangible model — to become the centerpiece of climate change discussions at the next COP summit, and to rapidly rise to the top of the agenda for multilaterals such as the World Bank. The experience of Germany, the EU, and South Africa points to a number of things we can expect for these discussions:

1. Forums that include bottom-up elements, and not just top-down planning, will be essential to the crafting of workable plans.
2. The bulk of any financing associated with these plans will be not for technical closing costs, but for worker and regional adjustment plans.
3. The financing amounts involved will be enormous. The $44B price tag for Germany’s plan is roughly equal to 4-5 years total generation sector investment, while the broad global estimated $1.6T price tag would be around 3 times annual global power generation investment.
4. Financing mechanics will be very complicated and contentious to devise. Germany’s financing approach – we’ll pay for it out of our own budget – is likely to be rare, if not unique. We can expect many false starts, and far more dead-end ideas than ones that get a serious hearing. Cross-regional and cross-country aspects will increase complexities (who will want to pay to retire China’s coal plants?). It may be a very long time before a workable solution for most, if not all, of the targeted retirement amounts is found – if it is found. The passage of time in finding viable financing mechanisms will mean emissions staying well-above aspirational climate targets, and in turn lead to a feedback loop where political pressure continues to build.
5. Financing for this energy transition ultimately will involve massive amounts of public financing, and that will mean a lot less public money available to invest in other infrastructure. Decommissioning coal-fired plants will become a massive competitor for infrastructure-related financing in the coming two decades.

Money for coal. It’s coming, and it won’t be easy. Stay tuned.

Offshore Wind: The Next Big Thing

Offshore wind: The Next Big Thing
January 2020

Offshore wind has been beyond the horizon for energy planners everywhere but the North Sea, until the last few years. That’s no longer the case: offshore wind is becoming a major piece of the energy future for multiple countries and jurisdictions. Bloomberg reports offshore wind financings in 2019 came close to a whopping $30 billion, and in September 2019, the UK saw bids for offshore generation at under $0.05/KwH, cheaper than coal and natural gas alternatives. It’s a whole new water world out there.

Among the offshore wind projects reaching financial close in Q4 of 2019 alone were the 432MW Neart na Gaoithe array off the Scottish coast at $3.4 billion, the 376MW Formosa II Miaoli project off Taiwan at $2 billion and the 500MW Fuzhou Changle C installation in the East China Sea, at $1.5 billion. And in November Vattenfall was announced the winner of the Holland South Coast Phase II project, having already won Phase I; the 1.5 Gigawatt project will be Europe’s first subsidy-free offshore wind farm.

What happened? Only five years ago, offered prices for offshore wind tended around $0.15-0.20 a kilowatt-hour, well-above the price for competing sources and requiring government subsidies to proceed. Now larger and more efficient turbines, bigger projects, access to better offshore wind resources, and more developed supply chains have been driving prices down rapidly. Capex per MW of offshore wind capacity dropped from 4.5 Euros in 2015 to 2.5 Euros in 2018, a decline in costs of over 20% a year, according to Wind Europe. This has enabled the advantages of offshore turbines to come through: wind is much stronger off the coasts, and unlike wind over the continent, offshore breezes can be strong in the afternoon, matching the time when people are using the most electricity. Offshore turbines can also be located close to urban demand centers along the coasts, eliminating the need for new long-distance transmission lines

Offshore wind has already become the next big thing on the US East Coast. In November, New Jersey Governor Phil Murphy signed an executive order backing a goal of 7.5 GW of offshore wind by 2035, and said he expects that offshore wind could provide New Jersey with half of its electricity. Those figures would probably represent $15 billion of investment in New Jersey alone. In December, Connecticut awarded an 804 MW project with an (undisclosed) offset price “lower than any other publicly announced offshore wind project in North America,” expected to generate the equivalent of 14 percent of Connecticut’s total electricity supply. New York state announced in early January a 1 GW procurement of offshore wind in 2020, after 2019’s award of 1.7 GW of capacity, and announced a 9 GW offshore capacity target for 2035. And in early January Virginia’s Dominion Energy awarded a $7.8 billion, 2.64 GW offshore project – the largest currently on the drawing board in the US — to Siemens Gamesa.

The Land of Giants. With the average capital costs of offshore wind projects now easily in the $3-7 billion each range, the competitive landscape in the industry has evolved very differently than for the solar and onshore wind sectors. Solar in particular was characterized in its early days by many dozens of developers, at times trying to launch projects with capital costs of less than $50 million on a shoestring and selling them on to raise funding for their next investment. Not only are offshore wind turbines far larger than their onshore counterparts, but offshore wind players are far larger as well. The biggest current developers are Dong Energy in China, Scandinavians Ørsted (today’s market leader) and Vattenfall, and Iberdrola. All these have Balance Sheets with equity in the $100 billion-plus category. Vestas, Siemens Gamesa, and General Electric lead among turbine suppliers. An interesting sign of the times was the recent announcement from EDP of Portugal (itself partly owned by Three Gorges of China) and Engie that they would join forces in developing offshore wind projects, in order to gain the scale needed to compete.

Financing amounts are sufficiently forbidding that most developers have been financing projects on Balance Sheet, and until recently little commercial project finance debt has been available, outside of the policy banks in China for Chinese projects. The bulk of third-party financing for offshore wind has largely been in the form of ownership syndications and post-construction refinancing. The large scale of projects, while a major hurdle for many banks and smaller developers, is conversely an advantage for institutional investors such as pension funds and insurance companies, who have large minimum investment thresholds. These institutional investors have more typically invested in wind and solar through portfolio purchases rather than single project financing, as for example this week’s purchase of 50% of Total’s wind and solar portfolio by Caisse des Depots in France. From late 2018 European banks began to enter the UK offshore market with large amounts of non-recourse debt; as this model gains traction, it may allow smaller developers to become more active. As the sector is becoming more established, one can also expect the gradual development of a merchant risk-based financing model.

Offtake models have also been affected by the large scale of offshore wind developments. Corporate renewables, an increasingly big – and often well-priced – source of demand for solar and onshore wind projects, has not been a factor yet for offshore. In December, Ørsted announced the largest-ever corporate offshore wind deal, with German chemical company Covestro, for 100 MW.

What’s next? Tenders are planned in many countries, and are spreading beyond initial markets of Europe, the US and China. Vietnam, already with 99MW of offshore wind in place, is looking at what could become the world’s largest offshore wind farm with a capacity of 3,400 MW. ESMAP, a unit of the World Bank Group, published a study in October 2019 looking at eight non-OECD markets: Brazil, India, Morocco, the Philippines, South Africa, Sri Lanka, Turkey, and Vietnam. The ESMAP study estimated these eight markets alone have a technical capacity of over 3 Terrawatts – that’s 3,000 Gigawatts – for offshore wind. Globally, Wood Mackenzie expects 128 GW of offshore wind capacity to be built between 2020 and 2028, while Bloomberg New Energy Finance forecasts 188 GW of capacity to be installed by 2030. Those projections would imply capital investment in the sector in the range of $300 billion over the next decade. China is forecast to remain the largest country market, but with about half the global share that it has seen in solar (25% vs 50%).

Nonetheless, it may be difficult for offshore wind to gain more than a fraction of the geographic diversification that onshore wind, and particularly solar, have achieved. Many emerging markets are too small to consume the output of even a single offshore wind farm – at least in offshore’s current form. Construction timelines will also be an issue: an attraction of solar for lower-income, electricity-deficient countries is that solar farms can be financed and built fairly quickly, bringing new generation capacity on stream in a year or less after a country’s decision to proceed. An offshore wind farm typically takes five to ten years to develop. One possible model for smaller markets, for instance West Africa, might be multiple country offtakes.

A big factor in the longer-term development of offshore wind will be the feasibility – and cost – of floating wind farms. 99% of offshore wind farms to date are bottom-anchored, a big factor in the cost and scale of projects, and a limit on geographic deployment. Floating wind farms can in principle be deployed across many more areas, and could be built at a smaller scale. Indeed, the ESMAP emerging markets study puts 2/3 of identified potential offshore wind technical capacity in the floating, rather than fixed, category. IRENA’s late 2019 “Future of Wind” study forecasts floating platforms to make up a more modest 5-15% of total offshore capacity. Yet to date less than 50 MW of floating capacity is operational, so time will have to tell on this part of the technology. We’ll have to see how the winds blow…

 

Blue Coal ?

Blue Coal?
October 2019

In the first two parts of this series, Infrastructure Ideas reviewed prospects for the coal industry, and forecast that the decommissioning of coal-fired generating plants would become a major destination of infrastructure (and climate-related) investment before long. In this third and last piece of the series, we focus on some possible unexpected political fallout from coal’s situation.

The central development to consider, in understanding how the sunset of coal is likely to affect politics, is its lack of economic competitiveness. In past decades, with coal cheaper s a source of electricity than other alternatives, the logic to politics was to be anti-government: the biggest threat to coal economics, and to coal jobs, was seen as government regulations. Not surprisingly, the stronger climate and pollution concerns became, the more strident the anti-government intervention politics of coal became. But economics are a wholly different threat. Coal-fired generation in the US is shrinking rapidly. In Europe, a recent report claims 4 out of every 5 coal-fired plants is losing money (Apocalypse Now, by Carbon Tracker). With the change in economics, the politics will change too. In the US, the beginning of this change became visible in the first two years of the Trump administration, with the odd couple of a conservative White House – elsewhere completely focused on dismantling government regulations — advocating in this case for government intervention, in the form of price supports for coal-fired electricity. Again not surprisingly, this strange strategy was dead on arrival – it went against the grain of both strong economic trends and the rest of the Republican agenda.

As coal becomes both uneconomic and a growing target for climate change concerns, we are likely to see political realignment. Coal will receive public funding, as in the US the current Republican administration has sought. But it will receive it for different reasons, and driven by different politics. What we will increasingly see is a drive for the use of public funding not to keep coal going, but to shut it down. And, crucially for the politics, for using the public funding also to help adjustment of the workforce in the coal industry. For Democrats, using public funds to intervene in the economy has long been a staple of policy, and now counteracting climate change is as well. With the likely acceleration of public concerns over climate change (see part I of this series), decommissioning coal is also likely to become a top policy priority for Democrats. Which implies that both owners of coal plants, and workers in the industry – now facing large-scale closures and loss of jobs — will in the future look for support not to their traditional republican allies but to democrats. Money makes for strange bedfellows…

One of the western US states with many coal plants both coming to the end of their life and/or becoming uneconomic is Colorado, and the state has shown one replicable way forward in managing associated tensions that could work for other coal-intensive locations (see Colorado May Have a Winning Formula on Early Coal Plant Retirements). While coal has been a key source of both energy and employment for decades, Colorado has been seeing wind power purchase contracts coming in at extraordinarily low levels, between $0.015-0.025 per kilowatt-hour, and even bids to provide a combination of solar power plus storage at under 4 cents/Kwh – almost half the cost of what electricity from new coal-fired plants would be. Colorado’s new plan is to use securitization from ratepayer-backed bonds to pay out decommissioning plants, and then to reserve some of the bond income for helping workers in affected areas. The bonds pay out the equity base of old plants from the utilities. While this piece of the mechanism has been tested before, the important complementary part of Colorado’s approach is the creation of something called the “Colorado Energy Impact Assistance Authority,” which will focus on helping workers displaced by the decommissioning.

Another example of changing political discussions around coal can be found in Arizona. There one of the largest coal-fired plants in the US, the Navajo Generating Station, is closing due to the loss of customers. Utilities in the region have shifted to wind and solar to save money. A bill introduced last month in the US House of Representatives (see the IEEFA’s Bill to Spark Federal Post-Coal Reinvestment in Arizona Tribal Communities Is a Good Beginning) calls for federal economic development and revenue replacement in the wake of the collapse of the coal industry in northern Arizona. The bill would fund large-scale clean-up and remediation around both the plant and its associated mine, Kayenta, continuing employment for many of the current workers (the power plant and mine are by a wide margin the largest employers of Navajo, with about 750 workers between them). It would also retool the existing transmission infrastructure towards solar power generation. Funding would go to tribal and local governments to compensate for losses due to decommissioning under a schedule that would replace 80 % of lost revenue initially, reducing by 10% annually. The IEEFA review of the bill notes it “could very well serve as a template for broader bipartisan legislation supporting federal reinvestment in coalfield communities nationally, including in Kentucky and West Virginia and the Powder River Basin of Montana and Wyoming, regions that are taking disproportionately heavy casualties as power-generation demand for coal recedes and local coal-based economies adjust to new market realities.”

Of particular note is that the Arizona bill was introduced by congressman Tom O’Halleran – who began his career as a Republican, and switched to the Democratic party.

It is way too early to tell whether either the Colorado or Arizona approaches will be a model for other regions. But what is clear is that the issues the two states are addressing are going to become very widespread – and faster than most people realize. It is also clear that similar approaches – with public intervention to accelerate and smooth the transition away from coal – will be the only alternative to bankruptcy for plant owners and unmitigated layoffs for workers. And it is clear that the amount of public resources needed to help both owners and workers will be very large. Not something a party bent on shrinking government is likely to manage. Look for coal country to start turning… Blue.

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.