Total Gets Deeper Into Renewables With Investment in EREN. Is Offshore Wind Next?

French oil giant Total is moving further into renewable energy, and may target the offshore wind market next, after this week’s investment in cleantech developer EREN Renewable Energy.

On Tuesday, Total said it took a 23 percent share in the company for €237.5 million ($284.9 million), with an option to buy the rest after five years. This week, Total also bought GreenFlex, a French energy efficiency player, for an undisclosed sum.

“Total integrates climate challenge into its strategy and is pursuing steady growth in low-carbon businesses, in particular in renewable energy,” said Patrick Pouyanné, chairman and CEO of Total, in a press release.

Philippe Sauquet, Total’s president of gas, renewables and power, added that “EREN RE’s momentum will allow us to accelerate our growth in solar energy and move us into the wind power market.”

According to one analyst, offshore wind is likely where Total will invest next.

“When we looked into renewable projects and compared them to oil and gas, it was offshore wind that was providing the scale and scalability on a par with upstream mega-projects,” said Valentina Kretzschmar, director of corporate research at GTM’s parent company, Wood Mackenzie.

“Offshore wind could be the next target for Total, simply because it is really the most attractive in terms of returns and the scale it offers," she said. "It’s very comparable to the oil and gas projects that they have in their portfolio.”

So far, offshore wind remains absent from Total’s asset sheet, even though the company has perhaps gone further than any other oil major in its commitment to renewables, Kretzschmar said. Last year, the Paris-based company committed to have a fifth of its assets invested in low-carbon business ventures by 2035.

The company took an important stake in the solar sector in 2011, when it paid $1.4 billion for U.S. PV giant SunPower. In 2016, it acquired the French battery maker Saft, for $1.1 billion.

Earlier this year, the oil and gas giant set up a subsidiary, Total Solar, to develop commercial and industrial-scale PV plants. But this week’s investment in EREN Renewable Energy (EREN RE) signaled that Total mostly plans to achieve its 20 percent target through mergers and acquisitions.

EREN RE, which is due to be renamed Total Eren, has developed 650 megawatts of wind, solar and hydropower generation around the world, and is planning on a 3-gigawatt portfolio within half a decade.

Sources at EREN said that the developer is not active in the offshore wind market, but that Total’s investment will at least give the oil major more exposure to onshore projects.

In 2016, Total Energy Ventures acquired an interest in the U.S. small wind turbine leasing firm United Wind, but other than that its experience in the wind sector has been limited.

Getting to grips with onshore wind through EREN may be a precursor to a move into the riskier, but potentially more rewarding, offshore market, said Kretzschem said.

“I think all the majors are just finding their feet in this area,” she said. “It’s still very much a learning process for them. They are investing in different technologies because, ultimately, they do not know which technology is going to win."

"Even though Total is committed to solar, now they are making a big point of diversifying into wind," she added.

In offshore wind, the oil company to watch is Statoil, which has not only kick-started the floating foundation market with its Hywind project in Scotland but is also planning to add battery storage to the mix next year. 

Other European oil majors are jumping on the renewables bandwagon too. Shell, for example, owns 400 megawatts of wind generation and was said to be pondering a bid for Asian solar giant Equis Energy in July.  

Over the summer, Shell's CEO said the company plans to spend up to $1 billion per year on its New Energies division by 2020. BP, meanwhile, owns almost 1.5 gigawatts of U.S. wind capacity. 

There is no indication that the oil firms will abandon their core business any time soon, though. Total’s biggest transaction in recent months, for example, was a $7.5 billion buyout of Maersk Oil & Gas.

The transaction will make Total the second-largest operator in northwest European waters, which make up the seventh-largest oil and gas-producing region in the world.

Foreign Solar Manufacturers Weigh Opening US Facilities as Tariff Decision Looms

The pending U.S. solar trade case is about to hit a major crossroad.

On Friday, September 22, the U.S. International Trade Commission will determine whether or not the few remaining domestic solar manufacturers have sustained “serious injury” from imported solar products. If the answer is no, the case brought by petitioners Suniva and SolarWorld will be dismissed. If the answer is yes, the governing body will work on a proposed remedy. Ultimately, President Donald Trump will have the ability to accept, reject or reform the ITC’s recommended solution.

The Solar Energy Industries Association (SEIA), in partnership with utilities, solar supply-chain companies and free-market advocates, has been urging commissioners to oppose new trade barriers. Earlier this week, SEIA filed a letter with the ITC criticizing Sunvia and SolarWorld for not submitting a plan for how they'll function as viable U.S. solar cell and panel manufacturers in the event they are granted trade relief.

Meanwhile, companies outside of the U.S. have been quietly making their own arrangements.

Several foreign solar cell and module makers said they’re exploring options to avoid potential trade restrictions by opening new solar manufacturing facilities in the U.S. -- something President Trump would very likely want to see.

“It makes sense, right?” said Tom Zhao, managing director for global sales in BYD’s solar and energy storage division, in an interview last week at Solar Power International (SPI). “We follow Mr. Trump's requirement about 'Made in U.S.' Win the jobs back for the U.S. Because the demand is here, our customer is here, our friend is here.”

According to Gagan Pal, chief marketing officer of Adani Solar, a fast-growing solar PV manufacturing business based in Ahmedabad, India, new tariffs aren’t necessarily a bad thing. While trade cases don’t align with free market principles, a policy that “puts everyone at par … is helpful,” he said. For Adani and others, the Suniva/SolarWorld trade case could help justify opening a new U.S.-based solar manufacturing facility. 

"If [new tariffs] come into effect, I think the clear direction that will emerge from this is that manufacturing in the U.S. will be incentivized, or supported by direct or indirect means," Pal said.

The smartest or the dumbest guy in the room?

Adani Solar, a subsidiary of the Indian conglomerate Adani Group, could be well positioned to take advantage of tariffs on imported solar cells and a floor price on modules -- should they be approved.

Two years ago, Adani Solar established an office in Florida and hired a small team to study the potential for expanding into the U.S. solar market. The effort initially focused on co-development, joint ventures and other opportunities, said Pal. Now, Adani is looking at whether or not to launch a full-fledged production facility for solar cells and modules.

The decision isn’t only tied to the Suniva/SolarWorld petition, "but truly related to the overall perspective within the Adani group to expand in global markets," Pal said.

Expanding to the U.S. would fit into Adani’s broader business plan. The company recently built a 1.2 gigawatt solar cell and module factory in India and is in the process of expanding that plant to 1.5 gigawatts over the next three months. Pal noted that Adani was interested in expanding operations in the U.S. before the trade case emerged.

Still, Pal said his company is waiting for the final outcome of the ITC case to see if a U.S. factory would make commercial sense.

GTM spoke with several solar manufacturers and their partners at SPI who gave similar responses: they’re waiting on Friday’s ITC decision before making any big decisions. One major solar project developer indicated that a supply deal is already the works. Separately, a solar panel manufacturer said plans to open a U.S. factory are already underway. But in both cases, details could not be confirmed.

Companies were hesitant to address their plans on the record due to the sensitivity of the pending case. The overwhelming response among panel suppliers that did comment is that they’re keeping all options on the table.

“We’re being a prudent business and evaluating all options,” said a representative from Canadian Solar on the sidelines of SPI.

"We’re preparing for the contingencies and we will react, but you can’t take the first step because you don’t know what the tariff is going to be,” echoed John Dallapiazza, senior sales manager for the Rocky Mountain Region at Trina Solar, in an interview. “You would either be the smartest guy in the room for having reacted before the announcement or the dumbest guy in the room, but it’s a coin toss to know which one it would be."

If the ITC finds injury, the next step is to hold a hearing on trade remedies on October 3. Suniva has requested a four-year tariff of 40 cents per watt on imported solar cells and 78 cents per watt floor price on imported modules. The ITC may come up with a different solution, which could also include quotas on solar products from other countries. Free trade countries may or may not receive favorable treatment.

While companies won't know what the proposed remedies are until October, an injury finding on Friday may be enough of a signal for some players to publicize their U.S. manufacturing plans.

“Different companies and different management styles will definitely show themselves," said Rhone Resch, former president and CEO of SEIA.

Trump campaigned on prioritizing U.S. manufacturing, and signed an executive order on the topic in April. (Image credit: The White House)

BYD: “Made in the U.S. may be a good solution”

China-headquartered BYD is among the companies considering a U.S. solar manufacturing plant -- depending on the remedy. 

The industry might be able to absorb a small tariff without huge disruption, but Suniva’s proposed 78-cent floor price would be “real crazy,” said Zhao.

“Then the solar developers have no modules in the next two years in the U.S.,” he said.

Some clients have said they would have to suspend projects until the local supply chain is ready, should that level of obstacle arise, he added.

BYD, though, wouldn’t stand on the sidelines waiting for prices to come down.

“We are also thinking about putting a factory in the U.S. if the 201 case comes into place,” Zhao said. “'Made in U.S.' may be a good solution to try to help our customers here. They have a very long pipeline of solar projects for the next few years, and they cannot really afford to pay the higher cost of modules.”

Exact locations are still in discussion, but the company already has a 1,000-person electric bus factory in Lancaster, California, so it could try to expand operations in that area.

Building a module factory would take about one year, Zhao said, whereas a cell factory, which requires more extensive environmental impact compliance, might take two years.

Recent statements from at least one major solar project developer show that there’s demand for a domestic manufacturing solution, even if it takes some time to set up. On NextEra Energy Partners’ most recent earnings call, management said they don’t see manufacturers giving up on the U.S. market.

“We'll see what happens,” said James Robo, CEO, president and chairman of NextEra’s parent company Florida Power & Light Company. “Obviously, we're following closely.”

“My own view on this is that markets adjust,” he continued. “This is a very competitive market out there for manufacturing panels that the panel manufacturers are not going to abandon .… They'll figure out a way to compete. And it may take a little bit but, fundamentally, I'm not worried about the long term implications of whatever happens with the ITC.”

Robo’s comments suggest there could be a deal in the works. Could NextEra’s major module suppliers JinkoSolar or Hanwha Q CELLS -- neither of which would comment on the record at SPI -- be considering a new U.S. facility to avoid trade restrictions? Could Adani’s Florida-based team be positioning the company to meet the needs of Florida-based NextEra?

The “5D calculus”

If injury is determined, there's a “5D calculus” that foreign manufacturers will have to work through, said GTM Research solar analyst MJ Shiao. The variables are the type of remedy (i.e. tariff, quota, etc.), the geographic scope (e.g., will free trade agreement countries be exempt?), the severity of the remedy (e.g., how high will a tariff be?), the length of the remedy (e.g., how many years?) and what other suppliers might do.

The type of remedy will determine a lot. For instance, if there are strict caps on how many solar modules can come from other countries, it could bolster the case for U.S. manufacturing. The tariff design will also affect where potential new U.S. factories get built. If a tariff makes importing modules untenable, but doesn’t address cells, then suppliers may quickly erect module assembly factories with easy access to international ports.

If the remedy addresses cells and modules, or specifies a certain amount of the finished product that needs to be made in the U.S., foreign manufacturers instead may need to invest in cell production, which is much more resource intensive.

The power and water requirements of such a facility would drive companies to build somewhere that has those resources in relatively cheap and abundant quantities. The Pacific Northwest fits the bill, and parts of the northeast.

The status of free trade partners in the tariffs would dictate other choices. If NAFTA partners escape a tariff, solar producers could flock to Mexico for cheaper labor, easy access to the eastern and western U.S. and proximity to the growing Latin American market.

The challenge doesn’t end when construction wraps up. It takes more work to ramp up to efficient, profitable production.

“Operational is one thing; scale and efficiency is another,” said Trina’s Dallapiazza. “The first modules out will be pricier than what scale can produce.”

Delays at Tesla’s highly anticipated solar cell and module manufacturing facility in Buffalo, New York are a testament to how difficult it is to launch such an operation in the U.S. SolarCity officially began construction of the plant in 2014 and anticipated starting production in early 2016. The facility finally produced it first PV cells at the end of August. Production is now expected to begin ramping by the end of the year.

Since the Buffalo plant broke ground, Tesla completed the acquisition of SolarCity, and the company decided to shift from Silevo’s “Triex” heterojunction cell technology to partner Panasonic’s Heterojunction Intrinsic Thin Film (HIT) solar cell solution. These developments likely caused some of the delay.

An established company that is already planning a to scale up production somewhere else in the world, and could pivot to the U.S. market, might have an easier time.

Meanwhile, at least one foreign manufacturer is already in the midst of setting up U.S. manufacturing facility. In February, China Sunergy, or CSUN, announced plans to build a 400-megawatt high efficiency PV module factory near Sacramento in response to earlier trade measures. While the plant features fully automatic production lines, it’s still expected to create more than 200 local job opportunities.

The timeline issue

For any company looking at U.S. manufacturing as a way to avoid trade penalties, understanding the timeline is key.

“At best, suppliers can speed through the manufacturing setup process within 18-24 months -- but by then, you're halfway through the four-year remedy period,” said Shiao, referring to the typical four-year duration of a Section 201 trade case. The president has the authority to extend the remedy for up to eight years, however.

“Worst case is that the supplier makes the investment and a World Trade Organization challenge or a change within the administration pulls the tariffs back before the end of the period,” he added.

If President Trump approves a new trade remedy for “injury” from imported solar products, it will likely take effect in January 2018. The solar industry is then expected to file a complaint with the WTO -- which is what opponents did when the American steel industry brought a Section 201 nearly 17 years ago. The WTO could take another two years to rule on the case. And if the Suniva/SolarWorld 201 petition is found to be in conflict with the WTO -- like in the steel case  -- the WTO will reject it. 

The problem is, this two-and-a-half-year period probably doesn’t provide enough runway to make a U.S. facility feasible. A company that invests considerable capital in a U.S. factory, only to find the country re-opened to imports by the time it's finished, would be at a disadvantage compared to others that don't bother.

And then there’s the possibility that the Trump administration will choose to reject the WTO decision and keep the trade remedies in place. If that happens, it could spark an all-out trade war as countries start implementing tariffs on U.S. products in retaliation.

“It's difficult to imagine that any supplier makes the plunge [in the U.S. market] until there's a clear recommendation from the ITC and even more importantly, clear guidance from the Trump administration on what it wants," said Shiao.

Thin-film solar manufacturers like Stion and First Solar were not included in Suniva's request for tariffs.

“Buy American” could also be a factor

Despite the risks, the first mover to launch U.S. manufacturing would likely receive an enormous amount of publicity -- and possibly win favor with the Trump administration.

Once the first mover acts, it’s likely to validate the tariffs in the eyes of the Trump team -- to the dismay of tens of thousands of U.S. solar workers who would like to see the trade drama simply go away. The problem for solar panel manufacturers is that a PR boost doesn’t make opening a factory a wise long-term decision. No doubt some CEOs are going to want more market certainty than the first mover boost can provide.

One way the Trump team might seek to ensure that new tariffs are effective at bringing international manufacturers to the U.S. is to tie the 30 percent solar investment tax credit to the Buy America Act.

“You could easily see in a tax bill an effort to attach the ITC to the Buy American Act to make it more strict," said Resch. In this hypothetical scenario, only panels made in the U.S. would benefit from the federal incentive -- which offers tax breaks for solar projects placed in service before 2023.

“If you’re a Chinese manufacturer, between Solar One and Solar Two (nicknames for anti-dumping tariffs the U.S. previously put in place against China), Section 201, and a Buy American Act provision, it’s pretty difficult to see how you can fit into the U.S.," Resch said. The combination of these forces and potentially other protectionist measures the Trump administration puts in place could be sufficient to justify an investment in U.S. manufacturing.

Trump talked a lot about the Buy American Act on the campaign trail and it continues to be a focus of his presidency. He signed the “Buy American, Hire American” executive order in April. Whether or not the administration can get a domestic product requirement for solar panels passed through Congress, though, is another matter.

Another solution: sell thin-film

Suniva claimed it was suffering from cheap solar imports from all over the world, but, curiously, it only requested protection against crystalline silicon products. That means the ITC could set back mainstream silicon pricing by a few years, but leave alternative solar technologies like thin-film untouched.

“Suniva and SolarWorld don't really compete with thin-film, since their bread and butter is mostly commercial and residential, while thin-film is largely procured for utility scale,” said Jade Jones, an upstream solar analyst at GTM Research.

This is one of the ironies of this saga: two small-time producers could destabilize the market for the largest utility-scale projects, which they couldn't compete for in the first place. It’s no surprise that several utilities with robust solar pipelines have come out against the trade case

If that happens, thin-film manufacturers who already produce at scale stand to benefit: theoretically, they could sell up to whatever the new minimum price is and keep that margin for themselves. Market leader First Solar is in the best position to expand market share in this scenario, as could Solar Frontier and (American made) Stion.

“Suppliers that have had a presence in the U.S. market will find it easier to access a potential uptick in thin-film demand,” Jones said.

As for the silicon manufacturers, they almost certainly wouldn not be able to pivot to thin-film production as a profitable workaround. Doing so would probably require buying a company that has developed the technology.

“Those are completely different technologies,” Jones said. “Most manufacturers want to focus on their core manufacturing business. To invest in a unique technology just for the U.S. market seems like pretty expensive gesture.”

Utilities: Solar Trade Protections Do More Harm Than Good

Over the past several years, utilities and public power producers have increasingly diversified their portfolios for a variety of strategic reasons in a dynamic that echoes the U.S. government’s own “all of the above” energy strategy. Diversity in generation sources can enhance energy security, reliability and consumer protection, and it can improve the environmental profile of the fleet. 

As part of the effort to diversify, many power companies have developed solar projects or have purchased solar-generated power, or both. As a rule, power companies plan on a 20-year cycle and depend on predictable cost structures, particularly for their solar projects.

The strategic assessments of renewable projects are based, in part, on the continued viability of the US solar industry -- a prospect that has looked increasingly sound over the past several years as U.S. solar has experienced tremendous growth. Solar today employs over 260,000 American workers, and was responsible for 1 out of every 50 new jobs created in the U.S. in 2016. Most importantly, solar is increasingly cost-competitive with wind and even natural gas. This achievement is not just good for solar; it’s a welcome development for our nation’s energy security as a whole.

Yet the imposition of trade remedies on solar technology sought by the two petitioners in this case, Suniva and SolarWorld, could fundamentally change those carefully calibrated assessments of grid stability -- and do so without any consequent societal benefits.

Duke Energy commented before the International Trade Commission that if such a remedial floor price or tariff is imposed, it expects the installed cost of solar projects to increase 30 percent or more and that demand for modules would contract, perhaps even precipitously. “As solar energy is just approaching parity with the traditional grid resources in a number of states, a significant reduction in demand for new solar projects could deliver a serious blow to continuing development and evolution of this market,” Duke argued.

For utilities like Duke Energy, which must select cost-competitive resources (whether they be fuel-based or renewable) when selecting new generation resources to meet customer demand requirements, such cost increases may eliminate solar generation from its evaluation processes entirely.

Obviously, this cost spike in the price of key components in solar manufacturing would quickly ripple throughout the supply chain. As these price increases slash the growing demand for solar, they likewise disrupt the carefully planned investment decisions of this nation’s power providers. Conversely, the development of a reliable consumer base is critical for solar’s continued expansion in the years to come.

Determining that the solar company trade petitioners were harmed, and issuing protective remedies as a result, could lead to higher electricity prices and a disruption in the nation’s generation mix. Neither of these are acceptable outcomes for American electricity consumers. Modern electric markets work by combining a diverse array of generating resources, each with its own strength. Upsetting that balance through the imposition of unnecessary trade barriers not only puts the solar success story at risk, but also undercuts the strength of the entire electricity delivery system.

Appropriate planning and coordinating to maximize bulk reliability and resilience on the grid, all with an eye to dominance in energy production, consumer protection and security, are laudable goals. Ill-conceived energy protectionism in the guise of a trade remedy, on the other hand, will only do more harm than good. We would all do well to take heed of recent events and remember to prioritize the importance of maintaining a diverse and resilient electric grid. The government should say no to the Section 201 trade petition for solar.


Scott Segal is Director of the Electric Reliability Coordinating Council. ERCC is a coalition of utilities providing power to millions of consumers across the nation and is a part of the Energy Trade Action Council. ETAC comprises a group of utilities, retailers, cooperatives, manufacturers, developers, financial investors and free-trade proponents that oppose the Section 201 trade petition.

Why Solar Advocates Are Crying Foul Over New York’s Latest REV Order

New York’s Reforming the Energy Vision initiative just took a wrong turn, according to solar groups. 

Last week, the New York Public Service Commission approved an order for setting the Value of Distributed Energy Resources, or VDER -- the complex metric that the state wants to use to replace net metering for larger-scale community solar projects in the short term, and eventually, for all distributed energy resources across the grid. 

But last week’s order is drawing fire from solar groups, including the Natural Resources Defense Council, the Solar Energy Industries Association, Vote Solar and the Acadia Center. According the NRDC, the PSC’s order could allow “flawed utility proposals that undercount the value of solar resources” to become part of the record and “make it impossible for many solar projects to predict part of their revenues from the policy and obtain financing on that basis.” 

That’s frustrating, these groups say, because they jointly filed comments with the PSC in July that laid out the specific flaws within each utility’s proposal in fine detail and suggested ways to fix the discrepancies. But these suggestions were made on a compressed timeline, after  difficulty getting discovery responses from the utilities on a timely basis, they noted. 

We’ll be covering the ins and outs of New York’s REV implementation at next week’s New York REV Future 2017 conference in Brooklyn, where and the PSC’s latest order will likely be a major topic of discussion. 

The reaction this week has been markedly different from the cautious support given by solar groups to the PSC’s first big ruling on valuing DERs back in March -- largely because it allowed most classes of solar to remain grandfathered in under current net metering rules.

But the March order also put community solar -- one of the state’s fastest-growing solar segments -- on notice that they should expect to earn money based on an emerging VDER value, and not on net metering. 

The problems with calculating VDER in the PSC's new order are multiple, these groups say, but can generally be separated into two classes: the issue of wildly different utility values for DERs on the grid and the issue of long-term financial certainty. 

On the first, the order has allowed utilities to move forward with plans that have wildly different calculations for Utility Marginal Cost of Service, or MCOS -- the base measure of what it costs for utilities to serve customers at different points on the grid. 

MCOS figures are meant to be used to derive two key values for VDER. The first is demand reduction value (DRV), or the averaged-out value for reduced energy delivery costs that come from DERs on a system-wide basis. The second is locational system relief value (LSRV) -- the value tied to specific locations where DERs could help utilities avoid forecasted distribution system investments. 

But according to a filing from solar groups, “utilities take varying approaches to interpreting their MCOS studies to determine DRV/LSRV. This results in wildly varying estimates of the delivery value provided by DERs,” as evidenced by this chart below, which shows that the state’s utilities have come up with kilowatt-hour values ranging from $226 for Con Edison to $15 for Central Hudson. 

Not surprisingly, the solar groups are most critical of the utilities whose methodologies have yielded the lowest MCOS rates. Both New York State Electric & Gas Corporation and Rochester Gas & Electric, for example, limit their analysis to “growth-related network investments primarily involving expansion or reinforcement of upstream distribution, distribution substation and trunkline feeders in growth areas," according to solar groups. "This method ignores several other system needs, most notably in areas not undergoing growth, and those below trunkline feeders. This also arbitrarily excludes the ability of DERs to extend equipment life, increase reliability and resiliency, and improve power quality.” 

The second big problem that solar advocates have with the PSC’s order is its lack of long-term certainty for rates that solar projects can receive under the emerging regime. In simple terms, financial backers are looking for proof that solar projects can earn a steady and predictable set of revenues over the long term, for 10 years or more. But the PSC’s order would allow at least some of these calculations to be revisited every three years, leaving open the possibility that future revenues could be drastically changed three times within that 10-year window. 

According to the solar groups’ July filing, “the VDER Order provides that DRV and LSRV rates/values shall be determined every three years. Any project that receives LSRV compensation shall receive the specific compensation rate for a period of 10 years. The DRV rate/value, however, is only fixed for the three-year period prior to the time at which it is reset.” 

“We cannot emphasize enough the reality that lenders and other financial parties that are essential to the functioning of the DER market will heavily discount or assign no value to components of the value stack that cannot be forecasted or predicted. Predictability and consistency in calculation methodology must be a touchstone of the VDER DRV and LSRV methodologies. Without it, these portions of the value stack will not be viewed as bankable sources of value and will not meaningfully contribute to the construction of new projects,” the groups wrote. 

With last week’s order set, solar advocates are now turning their attention to Phase 2 of the REV proceeding, in which the PSC will fine-tune its VDER methods as it seeks to extend them to smaller rooftop projects on homes and small businesses, as well as technologies such as stand-alone energy storage and, potentially, combined heat and power systems.

Many of these smaller projects will be cushioned from the most drastic changes through a predetermined "market transition credit" set out in the March order. But, as the Natural Resources Defense Council's Miles Farmer wrote, “if the utility methodologies are used as a basis for Phase 2, that would create a bigger problem.” 


Building on last year’s sold-out conference, NY REV Future 2017 will bring together key stakeholders, technology providers, utilities and state policymakers to discuss actionable business strategies to operationalize the ongoing initiative for a clean, resilient and affordable system in New York. We're asking the tough questions, recognizing the advances in New York's energy future to date and advancing the conversation into how REV becomes second nature for the business of energy. Join us.

How Deregulation Could Improve Reliability for Cash-Strapped African Utilities

Sub-Saharan African utilities are caught in a complex interplay between centralized grid-extension costs and the decentralized off-grid generation boom. Liberalizing their electricity markets may be a partial solution.

While high demand growth and the need for investment drove dramatic electricity sector reform in low- and middle-income countries in the 1990s and early 2000s, Power for All and GTM Research find that 71 percent of sub-Saharan African countries currently rely on vertically integrated utility structures, although the proportion is steadily declining.

Source: Power for All, GTM Research (Key: Light Blue: Privatized, Medium Blue: Mix of Public and Private Ownership, Dark Blue: Public Ownership)

Electricity market liberalization means more than unbundling

Pioneering reform programs have generally included corporatization; vertical and horizontal restructuring of generation, transmission, distribution and retail functionalities; and unbundling of tariffs; as well as the introduction of independent performance-based regulatory mechanisms.

With the aim of segmenting the cost of generation, transmission and distribution, empirical evidence shows that such liberalization reforms lead to increased operational efficiency, reduced pricing distortions and increased electricity access for poor consumers.

In sub-Saharan Africa, reforms are slowly being implemented. Unbundled utilities on the continent tend toward segmented -- and to some extent, privatized -- generation, transmission and distribution. In most cases, however, public control is maintained over the grid. Electricity continues to be sold at rates below cost recovery and infrastructure is not well maintained.

While this has led to an investment surge into private generation assets, leaving transmission and distribution infrastructure behind hurts the financial solvency and expansion plans of these utilities.

In fact, from 1995-2015, independent power producer (IPP) capacity in sub-Saharan Africa doubled every five years, primarily in countries with attractive credit ratings and stable investment climates, while investment in transmission and distribution infrastructure lagged significantly in the same period, falling well short of the $435 billion estimated necessary for universal access by 2040.

IPPs operating in Africa have pointed to a looming crisis in generation, as almost all countries are expecting generation surpluses in the not-too-distant future. Increasingly, the trend is to see national governments operate as a majority stakeholder alongside a number of provincial agents and private IPPs, as the requisite policy for full private ownership often does not accompany liberalization.

But reforms are slow going

Developing such effective regulation has proven one of the most challenging aspects of the restructuring process in sub-Saharan Africa.

As such, despite the push toward liberalization, chronically undercapitalized African utilities have historically been unable to recover operational and capital costs.

Last year, the World Bank found that of 39 sub-Saharan countries surveyed, only the Seychelles’ and Uganda’s national utilities were fully recovering both operational and capital costs, and only 19 of the 39 collected enough cash to cover operational expenditures only, hampering their ability to meet demand reliably and keep up with population growth and rising incomes. Financial difficulties in recently reformed electricity markets in Mali and Senegal even caused the power sector to revert to state ownership.

Source: Power for All, GTM Research

So how can liberalization boost reliability and electrification rates?

Unbundling reforms have major implications on the financial health and capacity expansion outlook of struggling public utilities.

As more utilities begin to seriously prioritize universal energy access within their service territories, ensuring their own financial health as a public service provider and as an offtaker for IPPs must be the first course of action. Additionally, regional cooperation in the form of cross-border energy trading could be a powerful incentive for private investment in high-voltage transmission projects.

A 2015 McKinsey study suggests that regional integration could save over $40 billion in capital expenditures and $10 billion annually for African consumers by 2040, though less than 8 percent of power generated in Africa is currently traded across borders. On the national level, tendering transmission and distribution capacity and leapfrogging the West on advanced metering infrastructure and collection will significantly improve operational efficiency and reduce technical and non-technical losses.

Liberalization can have major implications for new technologies and distributed renewable energy (DRE) solutions. Unbundling opens up markets for behind-the-meter generation across the various tiers of energy solutions that DRE provides, from solar home systems to grid-integrated mini-grids. Separating the cost of service and the cost of infrastructure also allows the opportunity for exercising tariffs that truly reflect the cost of electricity generation, particularly critical as part of an enabling environment for mini- and microgrid developers.

Also important for mini-grids, regulation and the establishment of integration standards often means more efficient access to transmission networks. Furthermore, electricity policy reform and a competitive grid also bring increased transparency around grid extension plans, a huge risk for mini-grid developers, and the opportunity to develop a conducive regulatory environment for decentralized renewable energy applications and coordinate with off-grid developers and installers.

For instance, the 2013 unbundling of the Ethiopia Electric Power Corporation into the Ethiopian Electric Services and Ethiopian Electric Power (EEP) in response to the country’s energy shortage in the 2000s allowed private investment into generation, transmission and distribution assets, as well as allowing for the import and export of IPP-generated power.

In order to meet a huge gap in capital investment, the Ethiopian central government also created the Ethiopian Energy Agency to foster both wholesale and retail price competition between IPPs and EEP, improving the operational efficiency of EEP, but raising tariffs for end-use consumers. As a result, a slew of financing vehicles for DRE solutions were mobilized, making Ethiopia one of the top three markets for solar home systems and pico solar adoption in sub-Saharan Africa.

While U.S. and European utilities hold their own regulatory debates about cost-of-service ratemaking and why volumetric tariffs no longer capture the emerging value proposition offered by the grid, steps toward competition and increased efficiency on the grid taken in sub-Saharan Africa suggest that African utilities are moving in the right direction.

Indeed, a recent PwC survey of African utility executives finds that 70 percent agree that the opening up of markets, in the form of unbundling and liberalization, would have a high or very high impact on electrification and supply reliability.

However, survey participants also agree that modernization of regulation to keep up with and encourage the potential of off-grid and mini-grid solutions is critical. This includes fast and low-cost licensing and permitting for mini-grids, technical regulation and quality standards, tariff and VAT exemptions for DRE components, and transparent protocols for distribution companies on mini-grid operator rights if the grid arrives.

If universal energy access is to be achieved by 2030 across the continent, sub-Saharan Africa’s moves toward liberalization will need to be faster, with greater attention to regulatory reform that encourages the inclusion of off-grid solutions while simultaneously creating effective regional power markets to improve cross-border trade.

African electricity sector leaders recognize the critical role that off-grid solutions have to play, and are beginning to engage with last-mile and under-the-grid consumers in creative ways to fill those gaps served most reliably and at least cost by centralized infrastructure.


This is the first installment in a joint series between GTM Research and Power for All exploring the dynamics of energy access issues in emerging markets. Power for All is a global coalition of 200 private and public organizations campaigning to deliver universal energy access before 2030 through the power of decentralized, renewable electricity.

As a pillar of Wood Mackenzies redefined focus on studying global trends in the transformation of power, GTM Research is studying the energy transformation occurring Beyond the Grid Edge in the off-grid rural energy access space.

A Top CEO Brings Us Inside India’s Fast-Changing Renewables Market

India has blossomed into one of the most important renewable energy markets in the world.

It currently has the fourth-most cumulative wind capacity installed, and will become the third-biggest solar market globally by 2022. The country also has plans to sell only electric vehicles by 2030.

With immense growth comes new businesses and economic opportunity -- but also political and economic risk.

This week, we'll talk with the CEO of India's top independent renewable energy developers about navigating that risk.

Sumant Sinha is the founder and CEO of ReNew Power. He's overseen 2 gigawatts' worth of completed wind and solar projects, and has plans to build 10 gigawatts more in the coming years.

In this show, we interview Sinha about the many forces that are changing India’s energy markets. We address:

  • The solar boom: Can India meet its 100-gigawatt solar target?
  • Grid planning: Can central and state governments better coordinate market expansion?
  • Quality: The importance of maintaining quality standards for projects
  • The rise of auctions: Are record-low prices sustainable?
  • India's EV target: Will it tangentially help?
  • ReNew Power's expansion: What will it take to hit 10 gigawatts of projects?

This podcast is sponsored by Mission Solar Energy, a solar module manufacturer based in San Antonio, Texas. You can find out more about Mission’s American-made, high-power modules at

Recommended reading:

  • Quartz: A Former Wall Street Banker Is Building India's Largest Clean Energy Company
  • GTM: India Already Has a Problem With Wasting Renewable Energy on the Grid
  • GTM: The Overlooked Solar Opportunity in India

What’s Impacting Consumers’ Community Solar Investment Decisions?

Potential solar customers are certainly window shopping. But in today’s market, interest doesn’t always equate to sales.

The latest Solar Marketplace Intel report from EnergySage shows increasing interest in solar from consumers. But the current array of options aren’t always enough to convince shoppers to buy -- especially for community solar.

In all six of the utility service areas EnergySage analyzed in its latest report, the levelized cost of energy (LCOE) for solar bested this year’s rates from residential electricity providers. And based on an analysis of traffic to its Solar Marketplace site, EnergySage found that solar interest surged in every state in the nation, with the most marked gains in “emerging markets” where the baseline is lower.

The gross costs of solar per watt also continued to steadily drop in the 35 states analyzed, from $3.36 in the second half of 2016 to $3.17 in the first half of 2017, with a standard deviation of $0.47. 

So what’s keeping community solar customers from making the jump? EnergySage cites two top reasons for the hesitation: Customers feel there is a lack of options where they live, and the financial benefits aren’t drastic enough to be persuasive. 

The top reason community solar customers did choose to invest was an inability to install rooftop panels. The potential for electric-bill reductions came in second. Of the 80 percent of potential customers EnergySage surveyed, many cited the need for stronger financial incentives. The 12 percent of customers who decided not to invest in community solar projects said cost was a factor, or they simply installed their own panels.

While prices are falling to levels competitive with traditional energy sources, monetary hurdles to solar -- perceived or real -- certainly persist. 

EnergySage’s analysis also assesses individual customers. And in some cases, those customers don't mind paying a bit more for premium products.

Customers who received quotes through EnergySage's platform were 19.6 percent more likely to choose premium panels over the baseline type, and 59 percent were more likely to choose the even more expensive Premium+ panels. Homeowners with a direct financial stake in the performance of the system want better-quality products.

Consistent with past trends, residential solar customers also continue to heavily prefer ownership of their system, with over 98 percent choosing to buy a system outright or using a loan over third-party financing such as leasing.

Although most installers only offer loans from a couple of providers, there are now more regional lenders that are active, offering greater selection among loan providers. More installers are also offering a bevy of panel brands. Just 6 percent offered five or more options in 2014. Today, 19 percent offer five or more options.

So will community solar break through? The near-term prospects may be stronger on the non-residential side. According to GTM Research, community solar projects should account for up to a quarter of non-residential installs starting this year, with over 600 megawatts of installations projected by the end of 2021. 

PURPA: A Quiet Death or Longer Life After 40 Years of Wholesale Electricity Competition?

In the first week of September, a U.S. House Energy and Commerce subcommittee held hearings questioning a 40-year-old law that forms the bedrock of competition in the electricity market.

Before the law took effect, electric utilities had a complete monopoly over electricity generation. In 1978, after some spectacular cost overruns by incumbent utilities, the passage of Public Utility Regulatory Policies Act (PURPA) introduced competition. 

Is a law passed in the era of shag carpeting and monster sideburns just as unfashionable in 2017?

If the list of testifiers was representative of utility customer interests, you might think so. But electricity markets are no less in need of competition in 2017 than they were in 1978. In fact, customers may pay a big price without it.

A bit of background

There’s much more detail in the Institute for Local Self-Reliance’s recent overview of PURPA, but the law’s basic concept is that utilities must buy power from renewable energy sources or “co-generation” facilities (that produce both electricity and heat for sale) if it’s competitive with their own supplies. Think of it as the utility planning to buy a burger and fries for $5.00. If someone else can offer the utility the same lunch for less, then PURPA requires that they buy it, because it saves everyone money. 

PURPA was designed to avoid utility cost overruns, particularly at nuclear power plants, if they built too much at too big a scale. It targeted market opportunities for medium-scale power generation -- projects 80 megawatts or smaller (most full-scale power plants are 500 megawatts or more).  

PURPA still serves a purpose

In the 1990s, Congress passed additional legislation to open the transmission system, allowing non-utilities to build power plants and sell that power elsewhere. Further changes created regional “balancing” markets run by independent system operators that allow for even more robust competition. A map of existing operators is shown below.

In these more competitive regions, PURPA only applies to projects 20 megawatts and smaller, under the theory that larger developers have market access. Smaller projects still need PURPA because the overhead costs of entering the market are prohibitive for the smallest power generators. In either event, the competitive market or the limitations of PURPA (to buy only cost-competitive power) protects customers.

Addressing critiques of PURPA

There’s no question that 40-year-old laws should be measured against changing market conditions. But to hear utilities talk, competition itself has gone out of vogue. Of the several critiques leveled at PURPA during the hearings, none undermined the fundamental advantage of the law: It requires utilities to procure cost-effective resources. 

One issue worth addressing is the habit of developers to take very large renewable energy projects and subdivide them to be eligible for PURPA contracts. For a 2016 wind project proposal in Idaho, for example, “A developer attempted to site 11 solar and eight wind facilities under the law, separating them so the combined 1,520 MW of capacity was portioned into chunks of 80 MW or less.”

Currently, a 1-mile separation between projects is required for them to be distinct, according to the federal law. An Idaho state regulator asked the congressional subcommittee for the ability to review “whether adjacent facilities truly constitute separate projects, looking at factors such as common ownership, interconnection points, operations [and] financing.” 

This is important, because diversity of market participants is a key element of distributing the economic rewards of renewable energy development. It’s also important because the size limitations of PURPA (80 megawatts in states with vertically integrated monopolies and 20 megawatts in states with competitive markets) is sufficient to capture most of the economies of scale in wind and solar production, as the Institute for Local Self-Reliance reported in 2016.

The following chart shows the economies of scale in solar energy generation, with projects near 20 megawatts hitting a sweet spot between the cost of project construction and the cost of transmission access (the latter is key for the largest projects).

In wind power, economies of scale don’t reverse at larger project sizes, but they certainly shrink, with the largest projects only 10-15 percent cheaper per kilowatt-hour. 

In other words, ensuring that “qualifying facilities” under PURPA stay within size limits seems entirely reasonable.

An overlooked opportunity to improve PURPA

Testifiers in the subcommittee hearing also noted that splitting up projects could allow them to interconnect on the lower-voltage distribution lines serving communities, rather than the high-powered ones used for long-distance transmission. Instead of treating this as a problem, Congress, the Federal Energy Regulatory Commission, and state regulators should look at the opportunity. 

First, when projects interconnect on the distribution system, they may be able to avoid the cost of new transmission infrastructure, as well as utilize existing capacity on the distribution system to provide local power for local loads. With its focus on wholesale power, PURPA -- as implemented today -- has sidestepped the opportunity to allow for competition closer to the retail level.

This issue has come up recently in Minnesota, where a developer proposed a 5-megawatt “wind-solar hybrid” with two wind turbines and a solar array, which can plug into open capacity near a utility substation (the connection point between the transmission and distribution systems).

The project would struggle to compete on price with a several-hundred-megawatt wind project, but it offers some unique values. One is that it avoids transmission costs, as shown in the graphic below (and in the slideshow version of this post).

A second advantage is that the power provided from a wind-solar hybrid (or even from a solar project versus a wind project) may uniquely benefit utility customers by providing more power during times of peak energy use. In Minnesota, these relative advantages are measured for rooftop solar through a “value of solar” methodology.

Federal lawmakers and regulators, as well as state public utility commissions, should start asking what components of the avoided-cost calculation may be missing from the existing calculus, and how they may offer further customer savings by favoring projects with particular characteristics. Storage, for example, could be another valuable element that provides peak power or grid support services.

Fair contract terms

While location and peak capacity are key components of any methodology for calculating avoided cost (the lunch price, if you will), the other central element is contract term. A PURPA rule rewrite in Michigan recently concluded that contract terms of less than 15 years are inadequate, because projects simply cannot secure financing and come to market with short contracts.

The Idaho commissioner testifying at the House hearing knows this full well, since that state responded to an upswell in developer interest not by addressing the issue of project splitting, but instead by shortening PURPA contracts to just two years (from 20). The move choked off development. If the only tool that state commissions have is a hammer (contract length), then all the problems (fair pricing, project size, project interconnection point) will look like nails.

Wrap: Improve PURPA, don’t kill competition

The House hearing echoed complaints from utilities in several states that share one common feature: lots of recent renewable energy development due to high utility avoided costs.

North Carolina, for example, saw over 2,000 megawatts of solar development when Duke Energy had high-cost power and the state enforced a long-term purchase contract. But the explosion of solar meant a better priced “meal” for the state’s electricity customers, much like how Xcel Energy CEO keeps saying that wind power is the cheapest electricity resource in many parts of the country.

It’s crucial to understand that utilities are not disinterested parties to this discussion. Particularly in regulated markets -- like Idaho and North Carolina -- the dominant investor-owned utilities make money for their shareholders by building power plants, paid for by captive customers. PURPA is one of the few tools state regulators have to ensure that monopoly incumbents provide the best deal for their state’s residents and businesses.

Congress should certainly look for ways to ensure diversity among market participants and that PURPA isn’t an end-around for savvy developers who should be participating in competitive markets. But states already have the power to protect fairness in PURPA contract terms and avoided costs. There’s no reason to roll back competition when clean energy can provide utility customers a better deal.


John Farrell directs the Energy Democracy Initiative at the Institute for Local Self-Reliance.

California’s Plan for 100% Renewables Falls Flat in the 11th Hour

California’s pitch for 100 percent renewable energy is dead -- for now.

In the last week of its legislative session, California bills that laid out plans for a 100 percent renewable grid by 2045 and a remake of the state’s grid into a regional system foundered.

Legislators’ failure to move the bills through could add fuel to the larger 100 percent renewable energy debate, in which a variety of stakeholders have questioned the speed, pathway, feasibility and, ultimately, the need for converting to 100 percent. The struggle raises an important question: If California can’t make 100 percent a reality, can other large economies?

The downfall of California’s 100 percent renewables bill, SB 100, came shortly after unions representing about 120,000 electric and utility workers, which had previously supported the bill, turned their backs on the legislation amid worries over job loss and grid security.  

“There’s a lot in all the bills that we like,” said Tom Dalzell, business manager at the International Brotherhood of Electrical Workers Local 1245, based outside of Sacramento. “Our interest was protecting the distribution system and the jobs of our members that work on the distribution system.”

Before the Brotherhood came out against the bill, California lawmakers had already shifted the initiative from 100 percent renewables to a "100 percent greenhouse-gas-free" energy goal, with a mandate to reach a lower 60 percent renewables target instead. Even with the added flexibility, SB 100 failed to advance and has been tabled until next year. 

Among the bills that slipped through the cracks this session was a proposal from Assemblymember Chris Holden to revamp California’s grid by regionalizing the authority of the California Independent System Operator (CAISO). The proposal, introduced just last week, was meant to allow California to more easily coordinate transfers of renewable energy across state lines in the West when the state has excess supply or not enough.

Groups like Dalzell’s worry that changes to the grid could mean fewer jobs. Many groups, like the Sierra Club and the Utility Reform Network, also joined unions in expressing concern that regionalizing CAISO would loosen California’s grip on its grid. Environmentalists were especially concerned that it may allow other states to send coal- and natural-gas-fired power to the state. Governor Jerry Brown supported Holden’s plan.

The complications that brought down the 100 percent bill in the eleventh hour are demonstrative of larger questions swirling around the possibility of a 100% renewable energy scenario.

Many cities have already committed to all renewables. Hawaii has approved the same goal California was considering -- 100 renewables by 2045 -- and has plans to get there early. But the state consumes much less energy and has a smaller footprint.

In May, questions about how an economy as large as the entire United States can get to 100 percent renewables became the source of an unusually heated academic debate when colleagues called out the research of Mark Jacobson, a Stanford professor who argued that reaching full renewables is entirely feasible with a World War II-style mobilization of mostly wind and solar. 

“Policymakers should treat with caution any visions of a rapid, reliable, and low-cost transition to entire energy systems that relies almost exclusively on wind, solar, and hydroelectric power,” wrote the authors of a paper rebutting Jacobson’s findings.  

The academic debate broke out as state Senate President Pro Tem Kevin de León sought to advance SB 100, making a big splash over California’s renewable ambitions.

For now, the debate over 100 percent renewable energy wages on. And though the delay on the energy bills does look like a setback, environmentalists say they’re not fretting. “We’re going to be back next year,” said Peter Miller, Western energy project director at the Natural Resources Defense Council. 

“I don’t want to underestimate the challenges to moving to a fully zero-carbon grid, but we can get there, and we will," he said. "It’s going to take some time.”

Back in California’s capital, it wasn’t all letdowns for clean energy advocates in the last week of the session. On Thursday, the legislature did pass Assembly Bill 797, an extension on incentives for solar thermal technologies that have offset 31,000 metric tons of carbon dioxide a year. That bill now heads to Governor Brown’s desk.

What’s Generated in Vegas Is Stored in Vegas [GTM Squared]