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US Solar Installs Fall to Their Lowest Level Since 2015, as Uncertainty Swirls and Prices Rise

America's solar industry had its toughest quarter in two years. 

Faced with political uncertainty, rising equipment prices, a slowdown in maturing markets, and a churn within residential installer rankings, deployments in the third quarter of the year are down on both a quarterly and annual basis. 

According to GTM Research and the Solar Energy Industries Association’s latest U.S. Solar Market Insight report, 2,031 megawatts of PV were installed in the U.S. in the third quarter of the year, resulting in the market’s smallest quarter in two years. (For historical context -- Q3 deployments were still 100 megawatts more than the entire year of installations in 2011.)

And even with the slowdown, solar PV added 25 percent of new capacity additions to America's grid in the first three quarters of the year -- coming in second to natural gas.

U.S. Quarterly PV Installations, Q1 2012-Q3 2017

Quarterly U.S. Solar PV Installations

Source: GTM Research / SEIA U.S. Solar Market Insight, Q4 2017

Two of the three market segments tracked by GTM Research and SEIA were down on the quarter and on the year; however, the non-residential segment was the lone standout.

The U.S. installed 481 megawatts of non-residential PV in the third quarter, representing growth of 22 percent year-over-year.

According to GTM Research solar analyst Austin Perea: “Regulatory demand pull-in was the primary market mover in Q3, as developers in California, Massachusetts and New York rushed to install projects to qualify for more favorable time-of-use periods, expiring incentive programs and grandfathering provisions. Meanwhile, non-residential solar in Minnesota experienced its largest quarter ever as the build-out of Xcel Energy’s robust community solar pipeline comes on-line.” 

With an unpredictable administration, a sweeping tax bill, and the threat of tariffs, it's been one of the busiest years in recent memory. These factors are all swirling around the industry, causing some doubts about the future.

Notable trends from the report include:

  • In Q3 2017, the U.S. market installed 2,031 megawatts of solar PV, a 51 percent decrease year-over-year.
     
  • Through the first three quarters of 2017, 25 percent of all new electric generating capacity brought on-line in the U.S. has come from solar, ranking second only to natural gas.
     
  • The U.S. International Trade Commission has voted to impose trade remedies on foreign-manufactured cells and modules, though it has suggested levels well below what Suniva and SolarWorld initially requested. The U.S. ITC sent recommendations to President Trump, and he now has until January 26 to decide the outcome of the case.
     
  • The residential PV sector fell 10 percent quarter-over-quarter. Declining growth is driven by weakness in California and major Northeast markets, which continue to feel the impact of pull-back from national providers.
     
  • The non-residential sector grew 22 percent year-over-year, primarily driven by regulatory demand pull-in from looming policy deadlines in California and the Northeast, in addition to the continued build-out of a robust community solar pipeline in Minnesota.
     
  • Voluntary procurement continues to be the primary driver of new utility PV procurement, accounting for 57 percent of new procurement through Q3.
     
  • Q3 2017 saw price increases across all market segments for the first time since this report series’ inception, stemming from increases in module costs due to a global shortage of Tier 1 module supply and the Section 201 petition.
     
  • GTM Research forecasts that 11.8 gigawatts of new PV installations will come on-line in 2017.
     
  • Total installed U.S. solar PV capacity is expected to double over the next five years. By 2022, nearly 15 gigawatts of solar PV capacity will be installed annually.

Want to read the full report? Access it here.

Tokyo’s Tepco to Test Stem and Sunverge Behind-the-Meter Batteries as Virtual Power Plants

Sunverge and Stem, two California-based behind-the-meter battery startups, have landed their first international projects in Japan, joining mutual investor Mitsui in a series of virtual power plant projects for massive utility Tokyo Electric Power Co.

The projects, announced Monday, are relatively small-scale, considering Tepco's scale as Japan’s biggest utility. Stem’s Tepco project will involve three commercial-industrial building sites with about 750 kilowatt-hours of battery capacity, one of which, a recycling center in the Tokyo suburb of Yoshikawa, started operations two weeks ago, Stem CEO John Carrington said in a Tuesday interview. 

Sunverge CEO Martin Milani declined to give details on the scale of its work with Tepco in a Monday interview. But he did say that several of the company’s “dozens” of 19.6 kilowatt-hour battery-inverter units have been deployed in C&I locations owned for about a year, based on work with Mitsui that started in early 2016

Still, the two projects mark the first announced international projects for Stem, and an important new market for Sunverge, which is also operating in Australia. And with Tepco facing a future that’s much less reliant on nuclear power, and much more renewable and distributed in nature, with more competition for big energy customers, both companies are hoping these small-scale experiments will be the start of something much bigger.

“We think it’s the beginning of a variety of opportunities out there,” Carrington said. “We’ve talked about getting into new markets for some time,” he said, adding, “This will be a very compelling market. It will be evolving over the next 12 to 24 months.” 

Japan’s energy sector has been evolving, and struggling, since the 2011 Fukushima Daiichi nuclear power plant disaster and the subsequent closure of much of the country’s nuclear reactor fleet, which caused major energy shortages and forced the country into emergency efficiency measures. 

Since then, the situation has stabilized, thanks largely to cheap imported natural gas, and several reactors have since reopened under pressure from the country’s largest utilities. Still, public opinion remains opposed to nuclear power, which makes up only about 2 percent of the country’s energy supply, compared to 30 percent before Fukushima. 

Meanwhile, Japan is still adding renewables at a rapid pace, despite the government’s scaling back its renewables goals and slower-than-expected growth and cutbacks from its wind and solar feed-in tariff program. 

Finally, Japan is undergoing a reform of its energy regulations, meant to open the vertically integrated system to more competition among energy providers. These combined factors are pushing the country’s biggest utilities to invest in distributed energy technologies, including batteries. 

Mitsui, which has invested in Stem and Sunverge alongside a range of renewable and distributed energy companies, will be the lead on the two projects. That makes it the owner and financier of Stem’s battery systems in this case, Carrington said. 

But Stem will operate the lithium-ion battery units, individually and in aggregate, from the same software platform, dubbed Athena, that runs its fleets in California, New York and Hawaii. “Our platform can aggregate that network -- now small, but we expect it will grow -- and provide a flexible demand resource for the utility, particularly as they add more renewables on the grid,” he said. 

Sunverge CEO Milani said the company is being asked to test three use cases. The first is fairly straightforward -- dispatching or importing power from the batteries to prove they’re tightly controlled enough to maintain a target wattage reading at each site. (Milani will speak today on a panel at Greentech Media’s Energy Storage Summit 2017 conference in San Francisco.) 

The second is to reduce demand charges, or extra costs imposed on buildings that exceed certain limits on how much power they can draw from the grid at any one point in time. That’s the core value proposition for most of the systems deployed by Stem, Green Charge Networks and other behind-the-meter battery players in the C&I space. 

While this business case is limited to markets like California or New York where demand charges are high enough to justify the cost, that’s certainly the case in Japan, where demand charges can add up to more than $10 per kilowatt, compared to an average electricity price of 30 cents per kilowatt-hour, he noted. 

The third use case is where the virtual power plant controls come in, Milani said. Many of its deployments in Tokyo are owned by the same company, he noted, and that company wants to “maintain them as a logical node -- a nanogrid if you will -- so if the total aggregate is supposed to have a load of x, and a certain site cannot meet its goals, we can use available capacity from a sister site and level them off.” 

In that way, “We can balance the load and reduce bills, even if one site is overcharging,” both from an electrical and a financial perspective, he said. “It’s basically treating an organization as a single organization, no matter how many sites it has. For Tepco, it could involve a specific contract with a specific tariff for a customer with multiple sites, that says, ‘Hey, if I want to ask you to reduce something, you can figure out which sites to reduce from, and as long as I get that capacity, I’m happy.’” 

Stem’s Tepco deployment is also based around demand-charge reduction, Carrington said. “The prosumers in Japan are ready for that,” he said, noting the rapid increase in demand response -- technology to reduce power use in response to grid needs or price signals -- in the country since Fukushima. “It’s pretty well known that they’re very energy-conscious, and that’s had an impact." 

But Stem is also testing some as-yet unspecified virtual power plant capabilities with Mitsui and Tepco, he said. “It allows them to leverage the real-time balancing and intelligence offered by our system and our software.” 

Both companies said that the data they’re collecting from the sites as they run through their VPP paces will be examined by Mitsui, Tepco and Japan’s Ministry of Economy, Trade and Industry, or METI, as part of the project. METI designated a total of 7 billion yen ($59.4 million) in subsidies for VPP development in fiscal years 2016 to 2017, Sunverge noted. 

Tepco is in the midst of a massive smart meter deployment, and been investing in renewable energy both at home and abroad. It’s also investing in startups on the grid edge, such as its £500,000 equity investment in Moixa Energy, and its €3 million ($3.5 million) investment in blockchain-based peer-to-peer energy trading startup Conjoule

Mexico Emerges as a Leader for Distributed Solar in Latin America

A favorable regulatory environment is positioning Mexico as the top market for distributed solar in Latin America.

The country is set to double its distributed generation capacity this year, with more than 300 megawatts of new installations, after Mexico’s regulatory commission increased the upper limit for net metering plants to 500 kilowatts, according to GTM Research solar analyst Manan Parikh.

Meanwhile, a report from the Mexican Banks Association (Asociación de Bancos de México, or ABM) projected the market for on-site, distributed energy technologies will see a compound annual growth rate of 121 percent, and is set to exceed 8 gigawatts and $13 billion by 2025. Growth will be led by solar.

That compares to the $110 billion going into Mexican energy-related infrastructure projects in the next 15 years, according to an EY note on Mexico’s National Electric System Development Program.

Mexican authorities are working to foster distributed generation as a slice of its 40 percent renewable energy target by 2035. For this to happen, the country will need to get around 18 percent of its generation from solar, compared to less than 1 percent at present.

Net metering will help. “There are several ways in which distributed generation projects can slot in,” said Parikh, including net metering itself, where excess solar energy is credited against future consumption, or net billing, where excesses are sold to the utility.

Net metering has already stimulated sales of sub-20-kilowatt residential solar systems, which this year could make up around 18 percent of all solar capacity in Mexico, based on GTM Research data.

Commercial-scale systems, of up to 1 megawatt, could represent another 10 percent. So far, the residential solar sector in Mexico has mostly been based on homeowners buying PV systems for their own use.

But companies are starting to offer financing packages as demand expands. In 2017, said Parikh, “several larger installers in Mexico, such as Galt, Enlight and Bright, formed partnerships or received financing for portfolios of systems.”

Up to 4.6 million customers could benefit from below-500-kilowatt net metering arrangements, the Mexican Banks Association said. Of these, most would be commercial or industrial users, but more than 431,000 could be on residential tariffs, the association said.

ABM said Mexican distributed solar customers are benefiting from the cost of PV systems, which fell 11.2 percent a year between 2013 and 2016, and rising electricity prices, with a compound annual growth rate of 3.8 percent between 2005 and 2015.  

Residential customers can usually recoup their distributed solar investment within three years, enjoying an internal rate of return of up to 35 percent, said the association.

For commercial users, the payback period is up to seven years and the internal rate of return could be up to 25 percent. “In both cases, the recovery period coincides with the financing terms offered by commercial banks,” said the ABM.

With such a favorable policy and economic environment, Mexico’s distributed generation market will be hard for other Latin American countries to beat. There are a couple of minor clouds on the horizon, though.

There is a spat between Mexico’s Energy Regulatory Commission (Comisión Reguladora de Energía or CRE) and Federal Electricity Commission (Comision Federal de Electricidad or CFE) over the net metering law.

“Some of the 2017 installations were in peril of not being interconnected by CFE because of a blocking of the new net metering limits set by CRE,” according to GTM Research.

“CFE was selling electricity in the industrial segment for $13 per kilowatt-hour in Merida and Baja California. Under the nodal scheme, customers would get back $4 per kilowatt-hour in those locations. CFE was concerned that it would have to pay for the difference.”

Longer term, Parikh said it's unclear whether tariff prices, some of which have been on the rise in recent years, will be affected by the outcome of national elections in 2018.

The constitution bars current president Enrique Peña Nieto from running for a second term, and recent polls hint at a possible shift in power from Nieto’s centrist Institutional Revolutionary Party to the left-leaning National Regeneration Movement.

Nevertheless, the Movement, formed in 2014 by former two-time presidential candidate Andrés Manuel López Obrador, claims to support scientific and technological progress in renewable energy.

If so, Mexico’s full-throttle progress on distributed generation would not seem to be under any serious threat just yet.

Interested in Latin America's solar market? Join GTM February 13-14 in Mexico City for an in-depth look at the country's rapidly expanding solar market.

Solar Summit Mexico will leverage GTM Research’s expertise in Mexico to ensure your company is uniquely positioned to capture specific opportunities while appropriately managing regulatory, political and market risks. Find out more here.

Solar PV O&M Landscapes Consolidate Globally

When it comes to operations and maintenance, one might expect the oldest and most mature PV markets to be the most consolidated, but the latest report from GTM Research and SOLICHAMBA indicates the opposite.

According to Global Solar PV O&M 2017-2022: Markets, Services and Competitors, Germany and Japan are the most fragmented of the top O&M markets, while Chile is by far the most consolidated. In fact, the top 10 O&M players in Chile maintain close to 100 percent of the PV installed base (residential systems excluded), as shown in the chart below.

In all O&M markets, the broader trend is toward consolidation, but the pace is notably different. 

 

Plant and portfolio size drive O&M consolidation

The Chilean market is characterized by very large plant sizes (above 50 megawatts) so the gigawatt-scale installed base consists of a limited number of assets owned by a small group of investors. This situation leads to a natural state of consolidation in the O&M market. As new capacity continues to get built in Chile in the years to come, with smaller plant sizes and a more diverse investor population, we are likely to see an uptick in O&M fragmentation as well.

Typical PV plants in the U.K. are much smaller than in Chile, but investor portfolios are very large. As more plants pass the two-year final acceptance certificate milestone and get sold on the secondary market, ownership consolidation in the U.K. continues to increase to levels unparalleled in Europe. Final acceptance also gives owners the opportunity to transfer O&M activities away from the original engineering, procurement and construction (EPC) firm to another provider (or to an in-house team), so O&M consolidation is progressing even beyond ownership consolidation. Because new construction activity stopped after the end of the U.K.'s Renewables Obligation incentive program in the first quarter, some EPC firms are exiting the market and selling their O&M business (or simply disappearing), which results in even more consolidation.

If large plants and investor portfolios drive O&M consolidation, the reverse trend holds true as well: smaller plants and portfolios lead to greater O&M fragmentation. That's the case in Germany, Italy and Spain, as well as Japan's large commercial and industrial PV segments, where system capacity ranges between 20 kilowatts and 5 megawatts and a typical investor may only own one to a handful of assets. EPC markets are also fragmented in these markets, and logically O&M markets follow suit.

Long-term O&M contracts freeze the market landscape

As markets mature and plants age out of warranty periods, investors commonly transfer contracts from the original O&M provider (usually the EPC or development firm) to a service provider or an in-house team. This consolidation process gets accelerated when the original contract holder disappears or goes bankrupt (like SunEdison and many others).

In Germany, however, transferring O&M services to a different provider remains a rare phenomenon because of long-term contracts that prove very difficult to terminate (unless the provider undergoes a change in ownership or fails to deliver the services). As a result, the main driver for O&M consolidation in Germany has been mergers and acquisitions; a few large players like Enovos Renewables O&M, ENcome and greentech grew their O&M portfolios by acquiring the service businesses of troubled EPC and development firms.

Ownership fragmentation drives up the cost of sales

Even in Italy where investors have more flexibility to exit contracts, consolidation has been relatively slow. A few large players are battling for O&M contracts with large asset owners, but portfolio size drops precipitously past the top 10 or 20 investors. During the interviews conducted by SOLICHAMBA to prepare the new GTM Research report, several Italian O&M vendors reported that their average customer owns between 1 and 2 megawatts. With such small portfolios, vendors face challenges and high costs to acquire new customers, and the market consolidates at a slower pace.

Investors don’t like change

Here is the scenario that drives O&M vendors crazy: An investor issues a competitive tender for an O&M provider to take over their portfolio. Then, instead of transferring the contract to the best bidder, the investor asks her current provider to match the price and terms of the best offer. From the investor’s perspective, this makes perfect sense -- she gets the benefit of the best market price and service terms, while avoiding the cost and effort of switching to a new vendor. From a vendor’s perspective, however, this means spending time and resources responding to tenders with very little payback.

Despite challenges, consolidation is happening

While we have been discussing a lot of obstacles to consolidation, the long-term trend is clear: O&M markets are consolidating. The factors above only impact the pace at which this consolidation occurs, which is extremely fast in markets like the U.K, slower in Italy, and slower still in Germany.

Some markets are moving in the opposite direction, typically those where construction activity draws new players into the fray. Australia exemplifies this scenario with its utility-scale PV boom that broadens the market for EPC and consequently for O&M as well.

What about the U.S.?

The O&M consolidation level is high in the U.S., especially for a market that continues to add new capacity at a fast clip. This situation stems from the dominance of a few large firms in each part of the value chain in the utility-scale segment: development, EPC and ownership. Secondary market activity has increased ownership consolidation, but the potential Section 201 trade case remedies and inclusion of the BEAT provision in the new tax code are causing uncertainty and could lead to changes in market dynamics.

***

For more details about O&M markets, trends, and detailed competitive landscape analysis by country and segment (including 128 vendors), as well as market forecasts to 2022 and more than 70 detailed vendor profiles, refer to the latest GTM Research and SOLICHAMBA report: Global Solar PV O&M 2017-2022: Markets, Services and Competitors.

The Top 10 Utility Regulation Trends of 2017

In July, Advanced Energy Economy published a list of the top utility regulation trends of 2017 -- so far. With 2017 almost in the rearview mirror, we check in on the top public utility commission actions of the year.

Not surprisingly, the challenges public utilities commissions are grappling with are wide-ranging and diverse: utility business model reforms, distribution system planning, grid modernization, rate-design changes, large investments in renewables, transportation electrification, energy storage, wholesale market changes, and data access, to name a few. Here is a roundup of the top 10 matters before PUCs in 2017.

1. Rewarding utilities for performance against policy objectives

In 2017, we have seen an uptick in conversations about the suitability of the traditional cost-of-service regulatory model as the energy landscape changes. Many states have already begun to move toward a system that better reflects new market conditions, allows utilities to take advantage of the growing service economy, and rewards for performance against established goals. At AEE, we have been a part of the conversation (see our 21st century electricity system issue briefs on performance-based regulation and optimizing capital and service expenditures for more information) to develop new utility business models that better meet the changing expectations of consumers and society.

In January, after a seven-month investigation, the Public Utility Commission of Texas issued a report to the state legislature on alternative ratemaking mechanisms which, among other things, recommended the adoption of performance-based regulation (PBR). In March, the New Mexico Public Regulation Commission initiated an investigation into its ratemaking policies, considering new financial incentives and re-examining how regulated assets should be defined and their costs recovered. Also in March, the Pennsylvania Public Utility Commission pushed forward in its alternative ratemaking investigation, asking for feedback on experiences with different methodologies, including PBR (AEE Institute filed comments here).

In April, staff of the Illinois Commerce Commission filed a report recommending that the commission initiate a rulemaking (which opened in December) to clarify the accounting rules around cloud-based solutions, particularly around whether utilities can earn a return on them. New York and the joint utilities have been engrossed in a process to implement their earning adjustment mechanisms (EAMs), with the utilities proposing a framework in May.

Over the past year, the New Hampshire Public Utilities Commission has been investigating utility cost recovery and financial incentives, and in March, a working group submitted its final report to the commission, recommending, among other things, implementation of PBR. In June, the Vermont Public Utility Commission opened an investigation and has held three workshops to review emerging trends in the utility sector and to examine alternative regulation approaches.

In August, staff of the Michigan Public Service Commission issued a report with recommendations on a new regulatory framework that allows demand response (DR) investments to be recoverable with a rate of return. In addition, the MPSC held a kickoff meeting on July 24 to begin a broader PBR study, with a report due to the state legislature in April 2018. In September, the Minnesota Public Utilities Commission opened an investigation to identify and develop performance metrics and potentially financial incentives for the largest utility in Minnesota, Xcel Energy.

In November, National Grid filed a rate case in Rhode Island on the heels of the state’s Power Sector Transformation Process (AEE Institute and NECEC submitted joint comments), which included a suite of performance incentive mechanisms and plans to fully deploy advanced metering infrastructure (AMI). Also in November, the California Public Utilities Commission issued a draft resolution (final decision expected before the end of the year) beginning the competitive solicitation process for utilities to start former Commission Florio’s regulatory incentive pilot.

2. Reconsidering how utilities undertake distribution system planning

Several states in 2017 have started to expand their distribution planning, which has traditionally focused on just poles and wires investments, to more fully consider new advanced energy technologies and DERs that can provide similar (or even better) performance, potentially at lower cost.

The New York Public Service Commission has been busy refining the state’s utilities’ distributed system implementation plans (DSIPs), which were filed last summer (by Con Edison, Central Hudson, National Grid, Orange and Rockland, and New York State Electric and Gas and Rochester Gas and Electric). In March, the utilities jointly filed a report and in May jointly filed a supplement on the identification and sourcing process for non-wires alternative projects.

In late September and early October, the utilities filed status reports (by New York State Electric & Gas Corporation and the Rochester Gas and Electric Corporation, Central Hudson Gas and Electric, Con Edison, Orange and Rockland, and Niagara Mohawk Power) on progress so far on hosting capacity analyses (i.e., estimating the load that the grid can accommodate without requiring grid upgrades) and implementation of interconnection portals (i.e., automating the application management process) -- both key steps to integrating a higher share of DERs on the grid.

In April, the Rhode Island Public Utilities Commission, Division of Public Utilities, and the Office of Energy Resources started a modernization initiative called Power Sector Transformation, with a workstream focused on distribution system planning (AEE Institute and NECEC submitted joint comments). In November, the agencies issued a joint phase 1 report to the governor with recommendations on key steps Rhode Island should undertake to modernize its electricity system, including improving distribution system planning.

In April, the Minnesota Public Utilities Commission issued a distribution system planning questionnaire in its grid modernization proceeding. The questionnaire sought input from stakeholders (AEE Institute submitted comments) to identify potential improvements in utility planning processes, especially with regard to the growth of DERs.

In Michigan, the two largest utilities -- DTE Electric Company and Consumers Energy -- filed draft five-year distribution system maintenance and investment plans. Keep an eye out for their final distribution system plans emphasizing near-term priorities and investments, which are due by the end of January 2018. The commission staff is also ordered to begin a stakeholder process after the final plans are filed and develop a report by September 2018 on future iterations of the distribution planning process (AEE Institute held a forum in Michigan in August to discuss best practices).

In June, the main Connecticut utilities -- United Illuminating Co. (approved on December 7) and Connecticut Light and Power Co. (approved on October 4) -- submitted DER integration pilot plans that include hosting capacity analysis maps to provide customers and third parties more transparency into their distribution systems. They also both included DERs and load forecasting to inform distribution system planning, and a DER portal and management system to facilitate the two-way sharing of information between customers and the utility (see trend 10 for more on data access).

The California Public Utilities Commission has also made significant progress in its Distribution Resource Plan (DRP) proceeding. In September, the Commission issued a final decision on demonstration projects for an integration capacity analysis (similar to the hosting capacity analyses described earlier) and locational net benefits analysis and directed the states’ utilities to implement the approved methodologies across their service territories. Most recently, in October the Colorado Public Utilities Commission opened a proceeding to consider various rule changes including potential new rules around distribution system planning.

3. Investments to enable a dynamic and flexible grid

A key first step to realizing a 21st century electricity system is making foundational investments in technologies that can facilitate the seamless integration of distributed assets into the grid. In 2017, many utilities have proposed broad grid modernization plans or advanced metering roll-outs to set the foundation for a modern grid (see our recent post on the leaders and laggards). The graph below shows the most recent data on residential smart meters installed by state.

In February, the Public Utilities Commission of Ohio (PUCO) approved AEP Ohio’s Phase 2 gridSMART project, which among other things includes the installation of almost 900,000 smart meters by 2021 and a $20 million investment in voltage optimization technology. In April, PUCO also opened an initiative called PowerForward to review potential regulatory policies and technological innovations that could modernize the grid and enhance the customer electricity experience. Also in February, Orange and Rockland Utilities in New York filed an application that included an expansion of its existing AMI roll-out to a full deployment for an additional $98 million.

In April, the Missouri Public Service Commission opened an investigation into emerging issues in the electricity sector including the installation of advanced metering infrastructure (AMI) and a review of what new customer-sited technology and distribution system upgrades are needed to facilitate DER integration. In Colorado, the Public Utilities Commission approved a settlement agreement in July that, among other things, initiates full AMI roll-out in Xcel Energy’s service territory commencing in 2020. And Entergy -- one of the largest utility holding companies in the South -- has been seeking approval for AMI roll-outs in several jurisdictions in 2017, including recent affirmative decisions in Louisiana, Mississippi and Arkansas, and a pending application in Texas.

In August, Hawaiian Electric Co. filed a revised $205 million grid modernization plan that includes a targeted smart meter deployment, investments in a wireless communications network and enhanced distribution technology, and the installation of advanced inverters to enable private rooftop solar adoption. In September, Vectren in Indiana received approval for a $446 million, seven-year grid modernization plan that includes investments in distribution automation technology, AMI, and an advanced distribution management system. And most recently, Duke Energy Florida received approval in November for a settlement agreement, resolving issues with its Levy Nuclear Project tat included the installation of AMI, a new Shared Solar program, and the installation of 500 electric-vehicle (EV) charging stations.

4. Successors to retail net energy metering

Net energy metering (NEM) has been widely successful in spurring the adoption of distributed solar across the country. However, as the number of NEM customers increases, pressure has been building in various jurisdictions to consider alternative rate designs and successor tariffs for NEM customers. Over the past 12 months, we have seen a flurry of activity.

The Maine Public Utilities Commission kicked off the changes in January by approving revisions to its NEM rules, grandfathering in existing customers under current rates for 15 years and establishing a 10-year transition period, with new DG customers in each subsequent year compensated slightly less than those who signed up the year before.

March was also a very busy month. Arizona Public Service filed a settlement agreement that follows the same general principle, grandfathering existing NEM customers for 20 years and establishing a transitional step-down rate for new customers. Arkansas adopted changes to its net metering rules, adding a 25-kilowatt cap for residential customers and a 300-kilowatt cap for non-residential customers, with longer-term changes to net metering still to come. And the New York Public Service Commission adopted an interim methodology for valuing DERs (AEE Institute filed comments). Specifically, the order maintains net metering for existing solar customers until January 2020, and then slowly reduces the compensation for new solar users from the retail rate toward a "value stack" methodology that is based on the utility's avoided costs and other DER values.

In June, the New Hampshire Public Utilities Commission lifted its 100-megawatt NEM cap, grandfathered existing customers through 2040, and reduced the NEM credit for new customers to full retail energy and transmission rates but just 25 percent of the distribution rate. In May, Indiana passed a bill reducing its NEM rate for new customers over the next five years until it is close to the utility avoided-cost rate. And in June, Nevada passed a net metering bill (AB 405) that immediately restored net metering, albeit at a slightly lower rate (and with compensation declining, ultimately to 75 percent of the retail price, as adoption increases). The decision finally put to rest a contentious debate that raged throughout 2016. In July, Idaho Power jumped into the mix when the utility filed a petition to close its net metering tariff for new residential and small general service customers beginning January 1, 2018 (grandfathering customers on their existing rates).

This fall, we continued to see significant revisions to existing rates. In September, the Utah Public Service Commission approved a stipulation filed by PacifiCorp and Vivint Solar that grandfathered existing net metering customers on their current rates through 2035 and set a three-year transition period when net metering customers would receive export credits slightly below the existing retail rate until the completion of a final order in a new proceeding to investigate a long-term export credit.

In November, the Public Utilities Commission of Ohio amended its net metering rules, reducing the excess generation rate utilities are required to offer net metering customers from the unbundled generation rate (which includes some capacity-related riders) to the energy-only rate, ultimately reducing the credit by about 30 percent. Most recently, the Louisiana Public Service Commission proposed modified net metering rules compensating new DG customers at the avoided-cost rate, which includes the commodity rate plus any locational, capacity-related, or environmental benefits.

5. Electric-vehicle integration

EV adoption and integration have risen to the fore in many jurisdictions, as states are looking to electrification to reduce carbon emissions and utilities are looking for new ways to increase electricity sales. Actions have included widespread electrification programs, statewide EV investigations, and targeted pilots or demonstration projects.

In January, the three big investor-owned utilities in California (San Diego Gas & Electric, Pacific Gas & Electric, and Southern California Edison) filed transportation electrification proposals with the California Public Utilities Commission (CPUC) totaling over $1 billion in investments. At the end of November, the CPUC issued a proposed decision approving $43 million in funding for pilots in phase 1 of the plans (a final decision on phase 1 is expected December 14 and on phase 2 in Q2 2018).

In Oregon, PacifiCorp and Portland General Electric have been negotiating settlement agreements in their 2016 transportation electrification proposals. In August, PacifiCorp filed a joint settlement agreement in its application and Portland General Electric in June filed a non-unanimous settlement in its application.

In April, the Michigan Public Service Commission began a collaborative to address plug-in EV issues (AEE submitted comments). In May, the Pennsylvania Public Utility Commission initiated an investigation to review the statewide rules and utility tariffs pertaining to third-party EV charging stations (AEE submitted comments). In September, Nevada opened a rulemaking to implement SB 145 which, among other things, created an Electric Vehicle Infrastructure Demonstration Program. In November, the Colorado Public Utilities Commission opened a proceeding to investigate electrification of its transportation sector.

Several other utilities have also proposed pilots. In April, Pepco, in the District of Columbia, proposed a $1.6 million EV pilot program through 2019 to test incentives and evaluate and obtain information on potential EV impacts on the distribution system. In April, Gulf Power Co. in Florida received approval in its recent rate case for a revenue-neutral EV pilot program. In June, the Utah Public Service Commission authorized an EV incentive and time-of-use pilot program for Rocky Mountain Power. In November, Eversource received approval in its Massachusetts rate case for a $45 million EV infrastructure program to increase the availability of charging stations and lower the barriers to EV adoption in the state.

6. Investment in renewables goes big

As in previous years, 2017 continued to see large investments in renewable energy, with over $30 billion through the first three quarters, according to Bloomberg New Energy Finance. Large investments have largely been driven by the falling cost of renewables and increased appetite from residential and corporate customers for 100 percent renewable energy offerings.

Several utilities have proposed building or procuring ambitious amounts of renewables this year. In March, Southwestern Public Service Co. filed an application to build a 522-megawatt wind plant in New Mexico and a 478-megawatt wind plant in Texas for $1.63 billion and to enter into a 30-year power-purchase agreement for an additional 230 megawatts of wind. In April, PacifiCorp in Oregon filed its 2017 integrated resource plan (IRP), which called for the retirement of 3,650 megawatts of coal-fired plants by 2036 and the addition of 1,959 megawatts of new wind (1,100 by 2020), 905 megawatts of repowered wind (i.e., upgrading aging turbines with modern units, by 2020), and 1,040 megawatts of new solar.

In May, Dominion Energy in Virginia filed its 2017 IRP, which included the closure of a 790-megawatt oil-fired facility by 2022 and a 261-megawatt coal-fired facility by 2022, along with the development of at least 3,200 megawatts of solar by 2032 (including 990 megawatts owned by non-utility generators by 2022) and 12 megawatts of offshore wind by 2021. In August, Interstate Power and Light in Iowa filed an application for 500 megawatts of new wind generation on top of the 500 megawatts that were approved in October 2016.

In July, Public Service Company of Oklahoma (PSO) requested approval to enter into an agreement with Invenergy Wind Development and its $4.5 billion, 2,000-megawatt wind facility (with an expected 51 percent capacity factor) in Oklahoma. If approved, PSO would own 30 percent of the project (with Southwestern Public Service Co. in Arkansas and Texas owning the other 70 percent). In August, Xcel Energy in Colorado, in phase II of its 2016 IRP, filed a settlement agreement that included the retirement of two coal plants (totaling 660 megawatts) by 2025 and the addition of 1 gigawatt of wind and 700 megawatts of solar by 2023.

Utilities in vertically integrated markets have increasingly turned to renewable energy tariffs to give customers more choice over their energy sources. In February, Xcel Energy in Minnesota received approval for two pilot programs -- Renewable*Connect and Renewable*Connect Government -- aimed at large businesses and government entities, respectively. In May, Dominion in Virginia filed an application for six voluntary renewable energy tariffs, collectively called Schedule Continuous Renewable Generation (AEE has been a party to this proceeding), and in October Dominion proposed an additional experimental and voluntary companion tariff (Schedule RF).

In June, Alliant Energy in Iowa petitioned for a voluntary renewable energy tariff, giving customers three subscription options: 1) a 100 percent solar option; 2) a 50 percent solar and 50 percent wind option; and 3) a 25 percent solar and 75 percent wind option. In August, Consumers Energy Co. in Michigan received approval for a three-year, voluntary large-customer renewable energy pilot program. In November, Westar Energy and Kansas Gas and Electric Co. (jointly known as Westar) filed an application for a Direct Renewable Participation Service tariff and Ameren Missouri filed an application for a new Renewable Choice Program, both targeted at large commercial and industrial customers.

7. New opportunities for energy storage

The energy storage market has continued its recent momentum into 2017. Driven by improving economics, a changing grid, and business model and rate design changes, energy storage is increasingly being recognized as a valuable and necessary asset for a 21st century grid.

More and more states are requiring energy storage to be evaluated in their IRPs. In August, the New Mexico Public Regulation Commission amended its IRP rules to include energy storage as a commercially feasible alternative supply and demand-side resource and requiring utilities to consider them in their planning. In October, the Washington Utilities and Transportation Commission laid out a framework for utilities to consider energy storage on a more level footing with other resources in future planning and procurement proceedings. The UTC will further develop specific rules around evaluating storage investments in its ongoing integrated resource planning proceeding.

A few other states have opened broader rulemakings to refine their energy storage frameworks or policies. Oregon continued progress in meeting its legislative requirements to consider utility energy storage project proposals submitted by January 2018, and to implement an energy storage procurement program by January 2020. In July, the Public Utilities Commission of Nevada opened a rulemaking to investigate setting energy storage procurement targets. Meanwhile, the California Public Utilities Commission released a decision in April to fine-tune its storage framework and policies, which the three large IOUs must use when filing their storage procurement applications in March 2018.

We have also continued to see utilities propose new energy storage projects. In July, the Kauai Island Utility Cooperative received approval for a power-purchase agreement with AES Lawai Solar for the largest combined solar and storage facility in Hawaii -- a combined 28-megawatt solar PV plant and 100 megawatt-hour battery storage system to help with ramping toward the afternoon/evening peak, shaving the evening peak, offsetting nighttime oil-fired generation, and assisting in grid stabilization.

In October, Duke Energy Indiana filed a petition for a new 2-megawatt solar and 5-megawatt/5-megawatt-hour storage microgrid (Camp Atterbury Microgrid) and a 5-megawatt/5-megawatt-hour energy storage facility (Naab Battery). And in October, the Public Utility Commission of Texas issued a proposed decision approving AEP Texas North Co.’s proposed installation of two utility-scale lithium-ion batteries on its distribution system (one would cost $700,000 in lieu of a $5.3 million traditional investment and one would cost $1.6 million in lieu of a $6 million to $17.2 million traditional investment).

8. Rate design for a DER future

New technologies, especially the rise in customer-sited distributed generation such as rooftop solar, have led many utilities to propose new rate designs and many PUCs to initiate alternative rate design investigations.

Back in January, the Public Utility Commission of Texas issued a final report to the state legislature on new rate designs and recommended phasing in alternative ratemaking mechanisms over three to five years. In April, the Missouri Public Service Commission began to explore and gather information on five emerging issues in the utility sector, including the implementation of alternative rate designs, the installation of AMI, and establishing a competitive EV market. And in October, New York Public Service Commission staff issued a scope-of-study report to examine bill impacts of a range of mass-market rate reform scenarios.

A few other states have begun the move toward time-varying rates. The big three California utilities have been conducting time-of-use (TOU) pilots throughout 2017 in order to gather information and aid in their transition to default TOU rates in 2019. In February, Tucson Electric Power in Arizona received approval for a new optional TOU rate with a plan to make the rates default for new customers starting in January 2018.

In November, Xcel Energy in Minnesota filed a petition for an innovative two-year opt-out residential TOU rate design pilot. If approved, the pilot would include three different rates, an on-peak rate (average of 23.82 cents per kilowatt-hour), a mid-peak rate (average of 11.07 cents per kilowatt-hour), and an off-peak rate (average of 5.68 cents per kilowatt-hour). At the end of November, National Grid in Rhode Island filed a grid modernization plan as a supplement to its rate case that included full advanced metering roll-out to all of its 790,000 customers, coupled with an opt-out time-varying rates program by 2022.

9. Wholesale market issues and changes

The last few months have been overshadowed by Energy Secretary Rick Perry’s grid review study and the Department of Energy’s subsequent proposed bailout of uneconomic coal and nuclear plants now pending before the Federal Energy Regulatory Commission. PUCs across the country have certainly taken notice, with NARUC commenting: “This proposal contravenes the States’ authority.” At least one state has opened its own inquiry. In September, Commissioner Andy Tobin of the Arizona Corporation Commission requested an investigation into Arizona's changing energy mix and to identify considerations that should be made to maintain a reliable and secure baseload energy portfolio in the future.

A few other states have opened slightly different investigations into their wholesale market rules. In August, Connecticut’s Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority opened a proceeding to examine the role of existing nuclear, large-scale hydro, demand-reduction measures, energy storage, and renewable energy in helping the state meet its carbon emissions targets; the best mechanisms to ensure progress toward those targets; and the compatibility of such mechanisms with competitive wholesale and retail electricity markets.

Also in August, the New York Independent System Operator and the Department of Public Service initiated a process to examine the potential for carbon pricing in New York's wholesale energy market in order to align New York state policy and wholesale electricity market rules.

Texas and its exclusive wholesale market operator the Electric Reliability Council of Texas (ERCOT) -- have been engaged in several different wholesale market rule changes in 2017. In May, the Public Utility Commission of Texas staff filed a report presenting possible changes to its operating reserve demand curve, which was created to ensure reliability and promote scarcity pricing in ERCOT's energy-only market design. And in March, the PUCT adopted an amendment allowing Emergency Response Service resources such as demand response to participate as alternatives to reliability must-run contracts, which traditionally have relied on coal plants to ensure the grid stays operational during emergency events.

10. Unlocking access to customer and system data

The rapid deployment of smart meters -- and the granular customer and electricity system data they provide -- has led many states to revisit their data access rules in the past year. Timely and convenient access to energy data can help customers track and manage their energy use, empower third-party companies to animate the market for DERs, and enable utilities to transition to a more customer-focused culture and business model.

Over the past year, the Public Utility Commission of Texas has been investigating changes to Smart Meter Texas (SMT) -- a web portal that provides data access to customers and authorized competitive service providers -- through several dockets (42786, 46204 and 46206). Most recently, commission staff filed a formal petition on August 16 to open a new docket (47472) to determine what changes, if any, should be made to existing SMT requirements. In July, the Illinois Commerce Commission issued an order encouraging utilities to consider adopting an Open Data Access Framework to enable a marketplace for new products and services and utilize investments made in AMI.

In an August resolution (E-4868), the California Public Utilities Commission approved a new click-through authorization processes that streamlines, simplifies and automates the process for customers to authorize their utility to share their energy-related data with third-party demand response providers. The Minnesota Public Utilities Commission has also been refining its data-access rules, particularly related to customer privacy. In June, the PUC approved a model form for utilities to use for obtaining customers’ consent to release their energy usage data to third parties.

Utility commissions across the country have been busy this year adjusting regulatory frameworks to a changing electricity marketplace. To advance the conversation, AEE has prepared a series of seven issue briefs that address how the power sector can successfully transition to a 21st-century electricity system. Also, to keep up to date on energy policy developments across the country, check out AEE’s PowerSuite and start a free trial.

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This post originally appeared on blog.aee.net and was republished with permission from Advanced Energy Economy.

Watch the Live Broadcast From US Energy Storage Summit 2017 [GTM Squared]

Group of Energy Heavyweights Unveils Plan for Puerto Rico’s Future Grid

In a 63-page report released Monday, a working group of electric experts detailed a plan for $17.6 billion in updates meant to revitalize Puerto Rico’s devastated grid

The suggested measures come from the Puerto Rico Energy Resiliency Working Group, a collaboration forged by New York Governor Andrew Cuomo’s office between New York Power Authority and the Puerto Rico Electric Power Authority (PREPA), electric trade organizations, and the U.S. Department of Energy.

The resulting document sets out an ambitious overhaul of the island’s electric system. The “build back better” strategy considers immediate restoration efforts, but stretches hardening and resilience measures into the next decade. Renewable energy technologies play a central role. 

“The magnitude of devastation to the Puerto Rico electric power system presents an unprecedented opportunity to rebuild and transform the system to one that is hardened, smarter, more efficient, cleaner, and less dependent on fossil fuel imports,” the report reads. “This system will deliver increased renewable energy resources, such as wind and solar; incorporate new distributed energy resource technologies, such as energy storage and microgrids; reduce the dependency on fossil fuels; and enable energy to become abundant, affordable, and sustainable.”

High-level rebuilding recommendations include six measures that together should prepare Puerto Rico for an upper Category 4 disaster. Many of the recommendations echo what has already been suggested for the island -- including undergrounding specific lines, instituting modern grid control systems and automated distribution systems, investing in distributed resources, and replacing infrastructure with hardier materials -- but the report also offers thorough details on damage when available and cost estimates. 

The changes come with a hefty price tag. The group estimates the island needs over $5 billion in distribution system updates, nearly $5 billion in transmission updates, and $1.45 billion in distributed energy resources (DERs).
 

Puerto Rico built much of its transmission system over five decades ago. Disrepair plagues the system. And crews have difficulty accessing systems installed before the island’s major highway network was rolled out. 

The group recommends abandoning many of the existing transmission lines, of which only 15 percent are built to Category 4 standards, and starting from scratch with lines along highways. Under the group’s scenario, crews would relocate and upgrade 350 out of 2,478 miles using high-strength insulators, monopole steel poles, and conductor spacing that prevents toppling in wind. 

Up to 75 percent of the distribution system’s 1,200 circuits also need repairs. Only 6 percent of distribution lines are underground, and the group suggests crews underground more lines in select areas. Crews would also install lines on the opposite side of the street from transmission lines to keep single events from causing double failures. Automated switching and sectionalizing devices would protect overhead wires. 

The report recommends crews rebuild both the distribution and transmission system to incorporate more DERs and renewables. 

The working group suggests concentrating onsite solar arrays, storage and microgrids at critical infrastructure sites: 26 hospitals, 20 police departments and 20 fire stations, along with 75 microgrids at emergency shelters, and at 10 percent of wastewater and water treatment facilities. Because 470,000 homes need repair or reconstruction, workers could incorporate solar there, too. 

The report’s substation hardening segment borrows the Post-Sandy “defense in-depth” concept used by New York and New Jersey utilities such as Con Ed. The group, which includes Con Ed and the Long Island Power Authority, recommendeds the island harden at least 90 percent of its 334 substations. Those measures include relocating significant equipment and structures to higher ground, installing pumps, and using heavy-duty sandbags wrapped in metal mesh as barriers to protect buildings. 

The group’s implementation roadmap shows restoration and initial rebuild of the system continuing into 2020. The highest investment will come post-2022, as distribution substation upgrades, transmission hardening, and generation hardening continue.  

For now, these plans are a long way off. Meanwhile, day-to-day rebuilding trudges on.

Fluor Corp., a contractor already at work on the island, last week received a three-month rebuild contract for $831 million. That's a paltry sum compared to what the Resilience Working Group says the island needs, but large compared to contracts such as the one awarded to Whitefish Energy. Approval for additional aid will likely have to wait for Congress to sort through its ongoing work on tax legislation. 

Still, more workers arrive every day. Over the weekend, seven “incident manager teams” from electric companies and utilities deployed to the island to assist PREPA and the U.S. Army Corps of Engineers in coordinating restoration. Over two months after Hurricane Maria, that brings the total number of workers in Puerto Rico to over 3,000. 

The island is now at just over 63 percent generating capacity, down from 68 percent last week. 

Why Trackers Are Essential to Profitable Utility-Scale Solar Projects

Watching the prices recently for utility-scale solar power-purchase agreements has felt a bit like being a spectator at an ultra-competitive Olympic event, where each successive race delivers a new world record.

The headline-grabbing 1.79 cents per kilowatt-hour tender announced in Saudi Arabia this past October is just one indicator of a global trend, in which PPA prices have been steadily dropping. Mexico’s new record-low solar bid for Latin America is another example.

This is a mixed blessing for the solar industry. Price declines are making solar highly competitive with all other forms of generation, which is undeniably good news. However, low and still-falling PPA prices make it increasingly challenging for solar project owners to develop utility-scale power plants that achieve a viable return on investment (ROI).

“We are seeing falling PPA prices, and what that creates with the customer is a desire to reduce overall costs of the system, whether it’s through capital expenditures or operating and maintenance expenses on the projects, or through increased power production,” said John Williamson, executive chief engineer for the tracker manufacturer Array Technologies, Inc. “If they can increase power production without increasing those other two variables, that seems like free money.”

Using trackers to maximize ROI

It’s widely acknowledged that solar trackers are an essential tool for achieving higher energy production -- as a rule, trackers increase energy production by between 15 and 25 percent compared to fixed-tilt racking systems. But while selecting solar trackers alone is an important first step, there are additional steps that should be taken to produce the most kilowatt-hours possible from a utility-scale solar power plant. It’s also vital for the designers of solar projects to carefully consider optimal tracker layouts and site designs, as this can boost energy production by an additional 5 or 6 percent.

Employing optimal design strategies to maximize energy production is especially important in northern areas of the United States, where steeply declining system prices have made solar financially viable despite the fact that solar insolation is so much lower than in places like California and Arizona.

“If you were to look solar availability or solar potential in some of the newer northern markets, you would find that the solar resource is a lot less [than in the Southwest]. Developers need to squeeze every kilowatt-hour out of every project, and they are doing that by utilizing trackers and optimizing their layouts,” said Stephen Smith, principal at Solvida Energy Group, a technical consulting firm that is currently engaged in 1.5 gigawatts of projects around the world.

Smith believes that the particular interest utility-scale solar project developers and owners in northern areas have in utilizing optimal tracker layouts will soon be the norm regardless of geography. Looming tariffs from the Section 201 trade case are part of the reason, though the eventual end of the federal Investment Tax Credit makes it a necessity.

“As the ITC fades away, we are going to be looking at getting more kilowatt-hours out of our systems because the tax piece of a project’s ROI is going to decrease and the production piece is going to get bigger,” he said. “The basic idea behind trackers is you get more production by exposing the modules to more sun.”

The importance of power density

The obvious question for utility-scale solar designers and owners is this: What are the best strategies for harnessing trackers to maximize energy production? A new study, Solar Tracker Site Design: How to Maximize Energy Production While Maintaining the Lowest Cost of Ownership, by Solvida Energy Group uses project performance data gleaned from simulations in three diverse geographic and climactic locations (Arizona, North Carolina and Oregon) to assess these three common tracker optimization strategies:

  • Power Density: Increasing the number of modules per land unit in a single tracker row or site.
  • Ground Coverage Ratio: Refining the east to west distance between module rows within a specified plot of land.
  • Range of Motion: Extending the angle that modules can be rotated in order to track the sun.

According to the report, increasing power density is by far the most effective strategy for optimizing energy production, boosting the kilowatt-hours generated by as much as 6 percent.

Increasing power density can be achieved in two very different ways. One is by simply adding more modules to a plot of land by eliminating access roads used to maintain a solar power plant. “That’s easy. Anybody can say, ‘Let’s get rid of a road,’” said Smith.

“But it also comes at a cost,” he added. “You increase your time getting from one point to another, and you have to balance that access with local permitting and fire department requirements.”

Improved tracker design, improved energy production

What’s harder, but ultimately more effective, is using trackers that are designed to improve power density. Array’s latest tracker does that by eliminating what are known as “dead spaces.”

“Those are any linear areas on the tracker that don’t have a solar panel. Many of our competitors have spaces for motors and bearings, but we have panels on top of all of that, which minimizes the gaps between panels so that we can increase the area where you can mount panels by 5 to 10 percent,” said Williamson.

Making use of trackers to improve power density is also a compelling strategy because it allows for the higher energy production that makes low PPA prices viable in markets where large, flat expanses of land are not available.

“We are working on a few projects where a developer has a piece of land that they want to put solar and use trackers on, but it’s full of these hilly areas with ravines running through them, and it’s hard to lay it out in such a way that you avoid doing major grading of the slopes,” said Williamson. “It becomes important to be able to look at that site in terms of the densest form factor possible, because if you have a product that takes up more land, then you may have to do much more grading to fit the same amount of power on the site.”

Array makes a tracker with a linked articulating driveline, which Williamson says is like the driveline under a car. “It has two joints on either end, and a telescoping driveline in the middle, so if you move it, it can accommodate different property slopes by moving that driveline north-south, or up-down, at different angles,” he said.

In its research, Solvida found that while there are certain instances when increasing ground coverage ratios and expanding a tracker’s range of motion can provide a boost to energy production, the improvements can often be limited to very specific sites and conditions.

But Williamson said he’s already seeing more instances where a mix of tracking configurations and optimization strategies are employed on a single project -- an understandable development if utility-scale solar is to be financially viable in any geography or climate.

“One of the innovations that we are working on is some different flavors of the same product. If you have some aspects of your site that don’t fit our larger footprint system, we will have a smaller footprint system to fit in those areas,” he said. “Other parts of the site may have a north-facing slope where it gets so steep that you don’t want a tracker on it at all, so you might have half tracker and half fixed-rack. I think that is how things are going to develop.” 

How California’s New Time-of-Use Rates Will Affect C&I Customers Considering Solar PV

On December 1, San Diego Gas & Electric became the first of California’s investor-owned utilities to implement a new time-of-use period that shifts the peak period later into the evening, to align with the "head" of the duck curve.

Commercial, institutional and industrial customers in SDG&E territory are subject to some of the most expensive demand charges in the country, making it an attractive market for demand-charge management. Unlike residential customers, many non-residential customers are subject to demand charges that are billed based on the facility’s highest monthly demand (measured in kilowatts), which can often exceed half of their total monthly utility bill. An energy storage system optimized for demand-charge management can reduce demand charges by forecasting when the load will spike and then discharging the energy storage system to mitigate the peaks measured by the utility meter. 

Many customers on the General Service tariff (Schedule AL-TOU) have been able to bypass these expensive demand charges by installing solar PV and switching to an alternative distributed generation tariff (Schedule DG-R). DG-R’s less expensive demand charges are offset by more expensive energy charges during the peak period, which has, up until now, coincided with peak solar production hours. With net metering, excess solar production has been credited back at the peak energy rate, which made the tariff switch to DG-R a win-win proposition for the solar customer. But now that's changing.

Tariff comparison: New versus old

SDG&E’s new tariffs shift the summer peak period to later in the evening, shorten the summer season, expand winter peak hours, and extend the time-of-use (TOU) periods to include weekends. "Part-Peak" and "Off-Peak" have been renamed "Off-Peak" and "Super Off-Peak" respectively, with an additional "Super Off-Peak" period introduced in March and April. 

Comparison of SDG&E TOU Periods

 

Energy, demand and fixed charges have gone up almost entirely across the board for both AL-TOU and DG-R. For customers on AL-TOU, demand charges during peak time have increased 26 percent in the summer and 109 percent in the winter, while maximum demand charges have gone down by 16 percent.

The difference between Peak and Off-Peak energy charges has narrowed, reducing the potential for energy arbitrage. On DG-R, peak energy charges have jumped up 38 percent in the summer to $0.5242 per kilowatt-hour and 80 percent in the winter to $0.2834 per kilowatt-hour. These tariff changes will most significantly impact recent and prospective solar customers, as TOU grandfathering only applies to ratepayers that filed an interconnection application prior to January 31, 2017. 

Comparison of SDG&E Rates

Impact on solar savings

Geli compared the impact of the new rates and TOU periods across 15 different facilities, including big-box stores, hotels, grocery stores, office buildings and schools. Solar savings decreased for all 15 sites, with an average decrease of 26.2 percent on DG-R and 5.7 percent on AL-TOU.

This steep decrease in DG-R solar savings is illustrated in the example site analysis below, with nearly 40 percent of peak period solar production shifted to off-peak under the new TOU periods. Given that, peak energy credits are significantly more valuable than off-peak credits.

The case for solar-plus-storage

Although SDG&E’s new tariffs will negatively impact the economics of most standalone solar PV projects, they strengthen the economics for solar-plus-storage systems. Between the peak period shifting later to line up with evening demand and the increase in peak demand charges, the value of demand-charge management has increased significantly.

Contrary to the traditional strategy of switching to DG-R, most sites in our analysis saw an overall lower utility bill by staying on AL-TOU. This can be attributed to the following reasons:

  1. The DG-R baseline bill is substantially higher than that of AL-TOU
  2. AL-TOU solar savings decreased less dramatically
  3. Demand-charge management savings are much higher on AL-TOU

Within the portfolio of sites we analyzed, solar-plus-storage systems produced a median bill decrease of 23 percent with the switch to DG-R, and a decrease of 31 percent by remaining on AL-TOU. For the example below, this translates to roughly $50,000 per year more in savings and total bill savings of nearly $79,000 per year. Even when considering the potential added value of TOU arbitrage present on DG-R, solar-plus-storage on AL-TOU still provides the best outcome for the customer.

For the purposes of this article, solar-plus-storage systems were sized to 25 percent of max load and solar sized to 90 percent of annual consumption. Note also that Geli’s analytics software does not size systems as a percentage of load, but rather for maximum economic benefit.

What does this mean for energy customers in California?

If you or your customer is considering installing an on-site solar PV system, not adding energy storage leaves significant additional bill savings on the table, especially now that solar PV is worth far less during peak production hours.

If you want to know exactly what solar-plus-storage is worth, sign up for Geli ESyst, Geli’s free-to-use solar-plus-storage site analysis tool, which already has SDG&E’s new TOU rates integrated. Geli will also be exhibiting at GTM's U.S. Energy Storage Summit 2017, to be held December 12-13 in San Francisco.

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Kevin Diau is a sales engineer at Geli. Kevin joined Geli after completing a BS/MS in renewable energy systems at Stanford University. Kevin is also the writer and director of Pacific Powerhouses, a documentary that details the opportunity and challenges in deploying renewable energy systems on Pacific islands.

Geli, which stands for Growing Energy Labs, Inc., provides the energy storage industry’s only design-to-automation platform, linking site analytics with the real-world operations. Founded in 2010, Geli software automates large-scale demand-charge management systems in the United States, resilient microgrids on remote islands, and virtual power plants for utilities.

One of California’s Biggest Solar Projects Will Be Located at an Oil Field

A newly announced project at California’s Belridge oil field will bring solar and fossil fuels together at one of the state’s biggest solar deployments.

The partnership, between Belridge field operator Aera Energy and solar thermal power company GlassPoint, will feature a 26.5-megawatt photovoltaic array and 850 megawatts-thermal of solar collectors for steam generation. It's slated to come on-line in 2020.

Aera, which is jointly owned by majors Shell and Exxon, produces almost a quarter of California’s oil and gas. GlassPoint currently has two running projects in Oman that are tied to oil extraction operations.

Aera monitored GlassPoint for years after attending the 2011 launch of a pilot plant at the Berry Petroleum Company field, also in Kern County. But GlassPoint’s COO and acting CEO, Ben Bierman, said “the stars aligned” only recently to make a project viable for Aera.

“At first it didn’t make economic sense to deploy solar at our operations,” said Aera CEO Christina Sistrunk, in an email. “But over the years GlassPoint has made advancements in their technology to reduce costs and has proven the viability of their solar technology in Oman.”

When water is separated from oil in the extraction process, GlassPoint’s thermal enhanced oil recovery (EOR) system turns it into steam using curved mirrors inside greenhouse-like structures. The high-pressure steam is pushed back into the earth to help pump more oil.

Oil producers invented thermal EOR in Kern County in the 1960s to release “heavy oil” from wells that could no longer produce. Oil from the fields originally powered the boilers. Natural gas became the fuel of choice in the 1980s. Now GlassPoint’s model clears the way for extraction companies to integrate renewables instead. 

A recent analysis found that solar steam generators are often lower-cost than natural-gas generators, when gas costs $6 mmbtu.  

“Our company is maniacally driven to reduce the cost of solar thermal energy,” said Bierman. “This analysis by Aera shows other producers in the Valley that the economics must work.”

GlassPoint uses greenhouses to protect its mirrors from wind and other elements, allowing the company to cut down on mirror material by 18 percent. A washing robot cleans the glass every night to restore performance. The company also reduced the weight of the structure that supports the mirrors by 30 percent and reduced the number of motors it uses by a third -- all in the name of cost-cutting. 

Now that Aera is on board, GlassPoint is eyeing other producers in the Valley and beyond. Most active thermal EOR fields are in the Middle East (where GlassPoint has two projects) and California. But as costs continue to decline, the technology will likely become viable in countries such as India, Indonesia and China, according to Bierman. 

As more countries introduce carbon-reduction targets, solar systems will likely entice more producers. Sistrunk said California’s extension of its cap-and-trade law in July provided the regulatory and political stability to ensure investments in emissions reductions would still make economic sense in the coming decades.

Thermal EOR uses 1.7 trillion cubic feet of natural gas a year to produce steam. Every year the Belridge project will offset 404,000 tons of carbon dioxide, equal to 85,000 cars. The site's solar PV installation will help power equipment and building operations.

“We’ve had something of a false dichotomy for the last decade, where it was envisioned as some kind of competition between renewable energy and conventional energy forces,” said Bierman. “We see this as an energy convergence.”