Navigant Research Blog

A Solar Coaster Ride for UK Prosumers

— July 19, 2018

The summer heatwave of 2018 has led to exciting benchmarks in the UK’s energy markets. According to National Grid, solar was the primary energy source across the UK with more than 27% of electricity generated in June 2018. Solar generated 533 GWh of electricity between June 21 and June 28 when it produced 9.38 GW of power, which is close to a record-breaking 9.42 GW on a single day on May 6, 2018. Almost one-fifth of the country’s electricity can be attributed to solar installations.

Effects of Austerity Measures

Sunny days have raised optimism across solar prosumers. However, despite this power generation surge solar deployments are on a shaky ground. Low cost modules and an explosive rise in battery storage technologies have not compensated for the role of governmental incentives that were cut in 2015 and 2016. Indecisiveness regarding feed-in tariffs and government rollback on subsidies have led to excessive boom and bust cycles, especially across residential customers. Numerous changes to business rates for buildings with rooftop solar continue to cause frustration across household segments. Since 2016, solar installations have declined by almost 50%, negatively affecting the overall attractive market for European solar. By 2022, SolarPower Europe forecast the UK will add just 2.1 GW of solar, while Germany, France, and Spain are projected to add 20 GW, 11.7 GW, and 8.8 GW, respectively.

The UK’s solar growth will continue to dip as the market is in dire need of a more forward-thinking political outlook. Gas-fired plants usually supply close to 50% of power in the UK, followed by nuclear and wind power. The government is keen to retain the UK’s position as a nuclear energy leader. A few days ago, it signed a £200 million Nuclear Sector Deal and aims to reduce the cost of new nuclear build projects by 30% and cut the cost of decommissioning old nuclear sites by 20% by 2030.

In the first quarter of 2018, wind generation was at its peak with reports of the country’s windfarms supplying more electricity than eight of its nuclear power stations put together. Wind generation soared up to a comfortable 43% on a few cold days this year while nuclear plants were shut down for maintenance and repairs. At one point, wind power was providing up to 50% of UK’s electricity in March 2018. However, the seasonality of wind power can hardly be ruled out. During the sunny spell, wind has averaged only 3.4 GW of output, or about 11% of power demand, even though the total capacity of wind installation has increased by almost 13% in 2018 to reach 20 GW. Cyclical seasonal variations in wind generation has created a need for more diverse generation sources in the UK power supply markets.

Cloudy Skies Ahead?

Solar power is a great alternative to offset wind’s shortfalls. However, the longer-term outlook for post-Brexit solar is riddled with uncertainty as energy suppliers seek more legislative reassurances and clarity on minimum import price and demand aggregation models. Though the UK is not best placed for the most decentralized renewable solar technology, the electricity system needs to be decarbonized by 2030 (by at least 80%) if the country is to cost-effectively meet its greenhouse gas emissions reduction target for 2050. Advances in panel technologies, hybrid solutions, and new methods of installing panels, energy storage, and grid integration will help to meet emission reduction targets and pave the way for a low cost resilient solar power sector in the UK.


The Spanish Energy Transition Might Speed Up, but Where Should It Go Now?

— July 5, 2018

Just a couple of months ago, I wrote a series of blog posts (Part 1 and Part 2) about how the Spanish distributed energy resources (DER) market was gathering momentum as technology costs come down. While energy markets move slowly, the political situation in Europe can change fast.

Shakeup in Spain

In an unexpected change of events, the conservative government led by Mariano Rajoy—the one that introduced the so called “Sun Tax”—was ousted by a successful no-confidence motion, and with it, a government that supports a faster energy transition took the helms of the country.

With power in their hands and with a pledge to fight the Sun Tax, the new government could simply scrap the tariff and move to the next thing. But if they do this, they will fail to put the distributed energy industry on a sustainable path.

Past Renewables Integration Is Not Enough

While Red Electrica De Espana (REE) did a good job at integrating renewables build in the late 2000s, Spain’s energy regulatory model is still geared toward a world in which centralized generation is dominant and electricity demand is considered inelastic. If Spain wants to put its DER industry on a sustainable path, it needs to unlock the value of all the energy assets connected to the grid.

The Sun Tax was an attempt of fitting distributed generation (DG) into the old mold, by charging DG for using the grid. While it is true that using the grid has a cost, having DG in the distribution grid also has benefits that were not accounted into the Sun Tax.

Aggregation Access Is an Obstacle

Currently, Spain has one of the poorest regulatory regimes regarding demand response (DR) and asset aggregation. Aggregated DR does not have access to the balancing market, nor to ancillary services. Spain does have a program for interruptible contracts, but it is open only to consumers with contracted power above 5 MW.

The only asset group in which aggregation is permitted is generation. Since 2016, DG and renewable energy resources have been able to prequalify and participate in the tertiary reserve. Another issue in Spain is that its capacity market is only open to generation assets, while excludes energy storage (and with it solar and wind + storage) from this market.

To successfully launch its distributed energy segment, Spain needs to restructure its markets to introduce the aggregator figure into its market and treat DR and storage as equals to generation. These changes have been implemented in several European markets; there is no technical reason why they can’t be implemented in Spain.

A First Step for DER

Addressing these issues and not scrapping the Sun Tax will empower the DER sector in Spain. Hopefully the new government will have the vision (and time) to overhaul its electricity market regulatory framework (not just patch it) to satisfy their supporters.


Latest California Projects Are a Landmark for Energy Storage

— July 3, 2018

On June 29, Pacific Gas & Electric (PG&E)—one of the country’s largest utilities—announced its latest round of new energy storage projects, dwarfing all previous procurements in the state. PG&E will see four new projects built in its territory, with three interconnected at the transmission level, and one representing a network of aggregated behind-the-meter systems. When completed in late 2020, this round will account for the two largest battery energy storage projects in North America, and the largest battery energy storage project anywhere in the world. Details on the four projects are provided in the table below.


PG&E Project Details

(Source: Navigant Research)

With these new projects, PG&E will far exceed the total storage capacity the utility was required to procure through the state’s energy storage mandate. In fact, this procurement of 567 MW would nearly meet the utility’s entire mandated total of 580 MW. In addition to the massive size of these projects, there are several noteworthy aspects to this announcement.

Storage Beats Gas

The latest projects for PG&E come in response to a January 2018 ruling that rejected the “reliability must-run” designation for three gas plants by the California Public Utilities Commission (CPUC). With that ruling, CPUC directed PG&E to explore opportunities to use energy storage and other preferred resources to meet its needs if those resources are deemed cost-effective. This procurement highlights the increasing competitiveness of energy storage to provide peak capacity and resource adequacy services compared to conventional generation resources.

The approval of such a large capacity of energy storage is also an indication that the utility anticipates it will continue to have a surplus of generation capacity after the projects come online. The excessive surplus generation in the state has been exacerbated by the growth of variable renewable generation, which further erodes the business case for conventional plants that are only needed during certain times of the year.

Taming the Duck

With a total energy capacity of 2,270 MWh, these new projects will provide a critical tool for making the most of the over-generation of solar during the middle of the day, and the challenging duck-curve ramp in the evening. The rapid growth of solar generation in recent years has resulted in excess generation and negative wholesale pricing during the middle of sunny days in California. The introduction of this massive new storage resource should allow PG&E to store excess energy for use during peak periods, reducing the need for conventional plants to remain online and ramp up during the evening.

One of the most noteworthy aspects of this new announcement is that PG&E itself will own one of the projects (Tesla’s 182.5 MW Moss Landing Project). Previous procurements of storage in California have relied on third-party owned projects that provide services to utilities on a contractual basis. This is a major validation for storage technology. One of the country’s largest utilities now confirms that the technology risk of battery storage is minimal, and that it can deliver the promised benefits at a competitive cost.


New Solar Records Bring the Real Energy Transformation into the Light

— June 19, 2018

Not long ago, utilities fought the introduction of renewables into their markets. Then, they didn’t really understand that the real energy transformation we are seeing today is consumer choice, including the potential of full individual energy independence in some markets driven by technology innovation.

Now utilities are exploiting the falling costs of solar to fend off the upcoming competition.

PPA Prices Are Crashing, despite New Tariffs

Despite all the talk about the new import tariffs and their effect on the installed cost of new PV installations, it appears that developers have squeezed procurement costs to continue breaking records for the lowest cost projects in the country. On June 11, Central Arizona Project (CAP), a local utility, signed a 20-year public-private agreement (PPA) with Origis Energy’s subsidiary AZ Solar 1 for a record low $0.0249/kWh.

A new record came only a day later. On June 12, NV Energy managed to break the $0.024/kWh floor, with a 25-year PPA signed for $0.0237/kWh. The Eagle Shadow Mountain solar project will have a total capacity of 300 MW and is being developed by 8minutenergy. This project is part of a 1 GW solar PV procurement process run by NV Energy as part of its strategy to become the first 100% renewable utility in the US. The procurement process also called for 100 MW/400 MWh of battery storage.

Saving the Monopoly

NV Energy’s push for 100% renewables does come with a caveat. The final green light to invest in these projects depends on the result of an energy choice initiative that will be voted on Nevada this year. If it is accepted, the project could be cancelled. NV Energy was also behind another controversial law, which eliminated net metering in the state in 2015.

This is part of a wider trend, where US utilities are increasingly deliberating not between new conventional generation or renewables, but between central or distributed resources. Behind this issue, utilities are also examining control of the end consumers relationship.

Maintaining control of the end user is key as the industry transitions from one in which the value was in the generation and transmission of electricity, to one in which the value will lie on the services that can be provided in addition to electricity.

Central Renewables versus Distributed Renewables

NV Energy understands that—at least in a resource-rich state like Nevada—the future is solar. Consequently, it wants to position itself as a clean and potentially cheap provider of electricity in the state in the eyes of the ballot voters this year. If it succeeds, it might dodge what is the most dangerous bullet for a utility—the opening of the retail market to competition and the potential race to the bottom that could spark. But even if NV Energy succeeds in maintaining its monopoly status, consumers will retain some choice—installing their own solar and producing their own electricity.


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