Engie Will Pay Storage Developers for Wholesale Market Dispatch Rights

“Everybody’s been talking about this, but this is it,” Engie Storage CEO Christopher Tilley tells GTM.

Storage developers can get paid for letting Engie bid their batteries into New England's wholesale market.

Storage developers can get paid for letting Engie bid their batteries into New England’s wholesale market.

Engie Storage has formalized a much-discussed but little-practiced revenue stream for energy storage projects: wholesale market value-stacking

Under a new product offering, Engie won’t just design, supply and operate energy storage plants for customers. The company will also pay developers upfront for dispatch rights to use their batteries in the ISO New England wholesale markets.

This gives storage developers and their financiers an additional source of secure revenue, while shifting the tricky merchant risk onto Engie, which feels confident in handling it.

This is not the first time energy storage has entered wholesale markets. Utility-scale batteries piled into PJM’s frequency regulation market years ago, and at least one storage facility is diving into Texas’ competitive ERCOT market. (Some storage technically participates in CAISO via California’s Demand Response Auction Mechanism pilot, but that is, in fact, a pilot).

What’s different here is the containment of merchant risk, which scares off those financiers who are otherwise comfortable with storage investments at this point.

In the past, developers built merchant battery plants, but that all but dried up when PJM’s storage market cooled off. Major battery plants these days need solid, contracted revenue streams to line up financing; if they can sprinkle in a little merchant activity, that’s great, but it’s gravy.

This means that the famous ability of storage to perform multiple tasks has not extended as far into the wholesale markets as is technically feasible.

“Everybody’s been talking about this, but this is it,” Engie Storage CEO Christopher Tilley told GTM. “This is real, and there’s real value-stacking that can significantly improve the economics of projects.”

Unpacking merchant risk requires certain competencies that Tilley’s team has access to as part of French energy conglomerate Engie, with a trading desk and experience managing the full range of energy assets. Its recent acquisition of Genbright, which aggregates distributed energy devices for wholesale market participation, further expands the tool belt.

Using those internal resources, Engie will take on the risk of projecting years’ worth of future market earnings, then cut a check to the developer based on those calculations. For the developer — Engie’s customer — this turns merchant risk into contracted revenue.

The developer gets paid upfront, financiers don’t have to worry about merchant risk messing with their payback, and Engie takes responsibility for dispatching the plant to make good on its predictions.

This isn’t just a theoretical announcement. Engie has a first customer in private equity firm Syncarpha Capital, which signed up for the full offering for six community solar plants paired with energy storage, totaling 19 megawatts/38 megawatt-hours. Those projects, expected online this year or next, will claim the Solar Massachusetts Renewable Target incentive and the federal Investment Tax Credit.

On top of those two incentives, Engie is paying Syncarpha to use the batteries for the ISO New England markets for capacity, reserves and frequency regulation. Tilley declined to specify how lucrative the wholesale payments are, but said they represent “a substantial amount of money.”

In practice, this requires balancing several sets of compliance requirements and then pushing for additional revenue.

DOE begins development of North American ‘energy resilience model’

Dive Brief:

  • The U.S. Department of Energy (DOE) will spearhead the development of a North American Energy Resilience Model (NAERM), designed to “proactively anticipate damage to energy system equipment,” predict associated blackouts and help with recovery.
  • DOE’s Office of Electricity (OE) will coordinate its efforts with the national laboratories and the energy sector, and said next steps include “extensive industry engagement” to ensure best practices are included in the model.
  • OE issued a report on its plans to develop the NAERM earlier this month, citing growing threats to the nation’s grid and the range of critical infrastructure that relies on electricity, from banking and water distribution to telecommunications.

Dive Insight:

OE Assistant Secretary Bruce Walker has prioritized the development of NAERM, which he describes as a “first-of-its-kind tool” to improve energy resilience and national security.

“The ultimate goal of the project is to provide real-time situational awareness and analysis capabilities for emergency events and optimal operations and recovery, enabling the federal government and industry to quickly and effectively prepare and respond,”  Walker wrote in a July 24 blog post.

In April, Walker wrote that the resilience model will provide “enhanced real-time situational awareness and analysis capabilities for emergency events,” which would allow the federal government to prepare and respond more quickly and effectively.

“The United States is increasingly experiencing threats, natural and man-made,” according to the report, including hurricanes, flooding, cyberattacks and electromagnetic pulses. The model will “enable prediction of the impact of threats, evaluation and identification of effective mitigation strategies, and support for black start planning, benefiting the United States by enhancing energy and economic security.”

OE’s report on the development of a model includes the United States and interconnected portions of Canada and Mexico.

The NAERM will be developed in two phases, with the first focused on long-term energy planning.

By the end of the first phase, OE’s report says the NAERM should be able to assess the expected consequences from a range of scenarios. By the end of the second phase, the NAERM will be a “situational awareness model capable of analyzing the power system, predicting potential threat consequences, and providing recommended mitigating actions.”

OE said timelines for each of the phases will be defined through “additional planning and technical progress,” and that next steps include engaging with industry experts to better understand issues and practices on a regional basis.

DOE has been expanding its efforts on energy resilience. Earlier this month, the department began seeking public comment on how the electric grid and oil and gas pipelines can be made more resilient to severe weather events like windstorms, floods, wildfires and other disasters.

Recommended Reading:

Senate committee unanimously approves $1 billion for EV, natural gas and hydrogen fuel infrastructure

Author: Max Witynski                    Published       July 31, 2019  Utility Dive

Dive Brief:

  • The Senate Environment and Public Works Committee voted unanimously Tuesday morning to advance a broad bipartisan infrastructure bill that includes funding for electric vehicle (EV) charging stations. Chairman John Barrasso, R-Wyo., is working to bring it before the full Senate this fall.
  • S. 2302, the America’s Transportation Infrastructure Act, earmarks $1 billion in funding for competitive grants to support the development of fueling infrastructure for electric, natural gas and hydrogen-powered vehicles. The bill also directs federal agencies to transition their vehicle fleets to hybrid-electric, electric and alternative fuels within a year of enactment.
  • Sponsors are optimistic about passage, and President Donald Trump also tweeted in support of the bill on Tuesday morning. However, the bill faces more deliberation over expected amendments, such as expanding ‘alternative fuels’ to include biofuel-powered vehicles.

Dive Insight:

The bill aims to establish a grant program that would be available to states, counties, municipalities, tribes and agencies working to make public charging infrastructure more widely accessible. It also seeks “to foster enhanced, coordinated, public-private or private investment in [alternative fuel] infrastructure.”

EV industry stakeholders welcomed the prospects for collaboration between the public and private sector.

“We see this as a major step forward in America’s global leadership in transportation electrification,” David Schatz, director of public policy at Chargepoint, told Utility Dive. Schatz said Chargepoint, one of the country’s largest EV infrastructure companies, “absolutely” foresees potential partnerships between grantees and industry.

“We already see a lot of private investment activated today in the market: this would only accelerate it,” Schatz said, “by allowing there to be natural partnerships that form around these funds and allow for the build-out nationwide of EV charging stations.”

Other stakeholders were more cautious in their response to bill.

“We’re pleased the alternative fuel grants look to spur private sector investment, but we want to be sure that it doesn’t allow abuses by electric utilities,” Doug Kantor of Steptoe & Johnson, counsel to both the National Association of Convenience Stores (NACS) and the Society of Independent Gasoline Marketers of America (SIGMA) said in a statement.

NACS and SIGMA are concerned that utilities could “double-dip” on infrastructure projects by charging customers for electric vehicle chargers while also qualifying for taxpayer-funded grants to support the buildout of that infrastructure.

Midwestern Sens. Joni Ernst, R-Iowa, and Mike Rounds, R-S.D., also said the section on charging and fueling infrastructure unfairly leaves out advanced biofuels as alternative fuel sources, and said they would introduce amendments to have them included.

At Tuesday’s hearing, Ernst stressed that she has “no problem” with the technologies and fuels already supported by the bill. However, “If all emissions-reducing fuels aren’t going to be treated equally by this program, then my preference is to do away with the program entirely,” she said.

Still, the bill has been touted by both the committee leadership and the president as a good example of bipartisan transportation legislation.

We had a 21-0 vote today in the Senate. We don’t get a lot of coverage of the fact that we do things bipartisan,” Chairman Barrasso told reporters after the hearing.

“And there is the will to get it done. I’m visiting with Senator McConnell to get it floor time in the fall,” he said.

Round 2 of the Solar Energy Innovation Network

Author: DOE_Solar_Energy_Technologies   July 29, 2019

ENERGY.GOV - Office of Energy Efficiency and Renewable Energy

Dear Solar Supporter,

The Solar Energy Innovation Network program is seeking applications for collaborative research projects to address challenges related to solar adoption in rural communities, multifamily housing, and commercial buildings. The program, managed by the National Renewable Energy Laboratory, is in its second round and will accept applications through September 4, 2019.

The Innovation Network assembles teams of diverse solar stakeholders to research solutions using real-world data, and facilitate sharing and replicating those solutions. Teams are encouraged to include state and local governments, utilities, industry, regulators, nonprofits, and academics and address topics in the following areas:

  • Solar in Rural Communities – Analysis and testing to help cooperative utilities, counties, and other rural community stakeholders understand the potential for solar energy to improve energy affordability and resilience.
  • Commercial-Scale Solar – Research and analysis to address market barriers and reduce the costs of solar energy for multifamily housing, community solar projects, and commercial buildings, such as offices, warehouses, hospitals, retail stores, and college campuses. This market segment has been slower to adopt solar energy than others.

Both topics will also include solar combined with other technologies, such as storage, and in microgrids.

The selected project teams will work to address barriers to solar adoption through in-person meetings and targeted research and analysis over 15 months. These teams will be grouped based on common solar market challenges so they can exchange ideas and address similar questions. Teams will receive funding and access to technical expertise from the National Laboratories and other experts.

Round 1 topics focused on grid integration, resiliency, and reliability. See the results of Round 1 here.

Apply now!

Regards,

The Solar Team

Apple leads second-biggest year for commercial solar installations: SEIA

Dive Brief:

  • 2018 was the second-biggest year for commercial solar installations, with 1,144 MW installed, according to the Solar Energy Industries Association’s (SEIA) 2018 ‘Solar Means Business’ Report.
  • There are currently 7 GW of capacity in place across 35,000 installations. Apple is the top corporate solar user, with 393 MW installed, while Amazon and Target are second and third. And corporate interest is not restricted to tech and retail — manufacturing and real-estate companies Solvay and Prologis ranked in the top ten as well.
  • The report highlights that more than 50% of all installations have occurred since 2016, in spite of challenges from solar cell tariffs and changing incentives.

Dive Insight:

As interest in solar from companies continues to grow, one of the most significant takeaways from the report is the sheer volume of commercial procurements, which SEIA says totaled nearly 4 GW over just the last 18 months.

“About 15% going forward of utility-scale development will have a corporate off-taker,” Abigail Ross Hopper, SEIA President and CEO, told Utility Dive. “That is a significant shift in the marketplace. It’s obviously usually big utilities that are off-takers for those projects.”

Small businesses have also increasingly begun to install solar as costs have come down and financing has become more feasible, said Hopper. Companies with smaller energy needs have aggregated their power purchase agreements (PPAs) and others are developing renewable energy portfoliosthat function similarly to mutual funds.

“I think as procurement options have broadened, as bankers get more comfortable with the product, and as loans and PPAs become more standardized, it’s easier for a smaller business to really navigate that contracting space,” Hopper said.

Solar procurement is increasingly done offsite and through PPAs, the report said.

“[T]he low upfront investment, limited risk and predictable long-term electricity rates offered by PPAs” can be attractive to businesses, it read. Last year, 47% of new onsite commercial capacity used a PPA — the highest ever.

LevelTen, which has created a marketplace that aggregates PPA buyers and sellers, expects solar offer prices to remain low for the next few years andinterest from buyers to remain high, in spite of federal tax credit roll-offs.

However, the policy environment for PPAs varies by state, with some more favorable than others.

California leads among states in terms of installed commercial capacity, followed by New Jersey, New York and Massachusetts. All of these states have favorable policies, although California and Massachusetts are transitioning “to new rate designs and incentive structures,” which may contribute to a decline in the non-residential solar market in 2019 relative to 2018.

Companies “wishing to retain the [Solar Renewable Energy Credits] from their system to meet internal environmental goals likely sets a ceiling on the growth of PPAs in the commercial market,” the report said. Even so, PPAs will continue to play an important role going forward.

Growth in offsite solar is expected to continue — 3.3 GW were procured in 2018. SEIA forecasts offsite solar procurements of 2 GW annually for the next several years, and deployments to hit 1 GW in 2020 “and increase in proportion to future procurement expectations.”

The advantages of offsite projects include economies of scale and the potential for multiple companies to own stakes in large projects.

SEIA expects 2019 may be a slower (but still top three) year for deployment.

“Growth is expected to resume in 2020 as module tariff reductions and [investment tax credit (ITC)] demand pull-in help to boost growth,” the report said. SEIA has been advocating for an extension of the ITC.

“If the investment tax credit were to be extended, the 30% credit would be available at the same time that the tariffs that have been imposed on our product are also coming down,” Hopper said.

In spite of the looming roll-offs, commercial solar has momentum: Corporate solar deployments have increased 23-fold over the last ten years.

 

PG&E bankruptcy timeline extended, creditors worry delay may block wildfire fund access

Dive Brief:

  • A U.S. Bankruptcy Court judge on Wednesday delayed consideration of a bid to end Pacific Gas & Electric’s (PG&E) period of exclusivity, when only the company is able submit a reorganization plan, and instead set a hearing for Aug. 13 on the bondholders’ motion.
  • PG&E has until Sept. 29 to submit a plan to exit bankruptcy, but according to Bloomberg its creditors are worried that would not leave sufficient time to access a new $21 billion wildfire assistance fund.
  • The fund, approved by lawmakers just this month, would help utilities cover wildfire damage liabilities. PG&E filed for bankruptcy in January after facing up to $30 billion in wildfire liabilities.

Dive Insight:

PG&E bondholders and insurers have each developed plans that could leave them owning a substantial portion of the company, according to Associated Press. But following Judge Dennis Montali’s decision, they will have to continue waiting before those can be presented.

The judge’s decision followed calls by California Gov. Gavin Newsom, D, to allow PG&E time to submit a plan.

Last month, major PG&E investors filed a proposed reorganization plan that offered $30 billion in capital including $16 billion to $18 billion earmarked for 2017 and 2018 wildfire claims. Insurers say they are owed $20 billion and propose some of those claims be converted to stock.

The plan would also rename the utility “Golden State Power Light & Gas Co.,” while the parent corporation would be known as “GSPL&G Corp.”

Each plan could result in the creditors taking a majority stake in the company, AP reports.

A group of investors represented by PJT Partners said the bankruptcy court judge made the correct decision, which would allow PG&E and its stakeholders to “work towards the development of a framework through which PG&E will determine the most appropriate plan sponsorship and financing proposal.”

“This is an important step towards allowing PG&E to conduct a transparent, fair and equitable financing process to help it emerge from Chapter 11,” Steve Zelin, a partner with PJT, said in a statement.

California’s new liquidity fund for wildfire claims will be funded half by utility shareholders and half by customers through a $2.50 monthly charge on bills that has been in place since the state’s energy crisis, and was originally scheduled to expire.

Why Did Solar United Neighbors of D.C Loses Solar For All Funding as Grantee For FY 19-20?

51st State Solar Co-op Round 3LaToya Smith, a Solar for All recipient in Ward 7, stands in front of her new solar system during the installation.

LaToya Smith, a Solar for All recipient in Ward 7, stands in front of her new solar system during the installation. The 51st State Solar Co-op is open to all District residents.

WHAT IS A SOLAR CO-OP?

We bring homeowners together into a group, or co-op. We provide unbiased, installer-neutral support through each stage of the process of going solar. Our experienced team ensures you understand how solar works, how it can be financed, and how it can be installed on your home.

Co-ops take advantage of the group’s bulk-purchasing power to get discounted pricing and a quality installation. Co-op volunteers choose an installer on behalf of the entire group through an open and competitive bidding process. The selected installer provides everyone in the group with a personalized proposal for their consideration.

Our Solar for All program is no longer accepting applicants. If you are interested in participating in a Solar for All program please visit the District’s Department of Energy and Environment’s Solar for All website to learn about the programs that are still open to new applicants.

Watch the video below to learn more about our solar co-op process and its benefits, or view our FAQs.

Consulta nuestro FAQ para más información sobre la tecnología solar y el proceso de comprar e instalar su sistema solar.

GO SOLAR ON YOUR OWN

Solar For All
Solar for All aims to bring the benefits of solar energy to 100,000 low to moderateincome families in the District of Columbia. The DC Department of Energy andEnvironment is partnering with organizations across the District to install solar on singlefamily homes and develop community solar projects to benefit renters and residents inmulti-family buildings. All Solar for All participants should expect to see a 50% savings ontheir electricity bill over 15 years and can be proud to have gone solar!  In order to beeligible, residents must meet the income guidelines below.

Options for Single Family Homeowners

Grid Alternatives Mid-Atlantic provides solarinstallations to income-qualified single-familyhomeowners through Solar Works DC, the District’s solarinstallation and job training program. In addition to preparing residents to enter careers insolar and related industries, Solar Works DC reduces energy costs for low- and moderate-income homeowners by installing solar systems on their homes. Homeowners will leasetheir solar systems at no cost to them and will receive 100% of the energy the systemproduces. You will also receive no-cost solar system maintenance, repairs, performanceguarantee, and an insurance policy covering the system.

How to apply: Contact Jacqueline Treiger, Senior Outreach Coordinator by phone at (202) 517-8858 or by email at[email protected].

Eligibility

Washington DC residents can participate in Solar for All single family solar or community solar options if the householdincome is below 80% of the area median income (AMI) threshold, as listed below

Persons in household 1 2 3 4 5 6 7 8
Income threshold $67,950 $77,650 $87,350 $97,050 $104,850 $112,600 $120,350 $128,150

Household income amounts listed in the eligibility table are effective as of 10/1/18, but may change.
Please visit the US Dept of Housing and Urban Development website for the most up-to-date numbers.

Community Solar

Community solar provides the benefits of solar to residents who can’tinstall systems on their home, including renters and homeownerswhose rooftops are shaded or need repairs. A community solar projectis not located on the home, but offsite, and the benefiting householdreceives a credit on their Pepco electricity bill each month.
Read more>>

How can I participate in Solar for All’s community solarprojects?

Several organizations are a part of the DOEE Solar for All community solar initiative. Two programs currently have openapplications. District residents interested in participating should reach out to those organizations directly using thecontact information provided below.

Additionally, in late 2019, DOEE plans to open enrollment for select income-eligible District residents to benefit from newcommunity solar projects, including a proposed project under development at Oxon Run.

Solar for All Community Solar projects currently open for general enrollment

Groundswell is installing solar on houses of worship including at the DuPont Park SeventhDay Adventist Church in Ward 7. Up to 47 income eligible households will receive energy creditsubscriptions at no cost. ContactLenwood Coleman [email protected] or 240-303-2944 formore information.

Neighborhood Solar Equity is installing solar on a local university and plans to providebenefits to income-eligible households in the District. For more information, contact[email protected] or 202-930-1904.

In addition, several other organizations are pursuing Solar for All community solar projects. Those solar projects are eitherfully subscribed, or not yet open for enrollment. See logos of all authorized Solar for All vendors below.

Authorized Solar For All Vendors


Enflection transparent logo 1200x420.png

To verify whether a solar developer / contractor is operating a DOEE Solar for All program, please email [email protected] orcall 311.

Additional Information

DOEE is working with the DC Sustainable Energy Utility Solar for All in 2019-2020. This program has the potential to savecustomers up to $500 per year on their electricity bills. Local solar contractors are working to install solar at no cost toincome-qualified District residents. Read More>>

Mayors declare heat emergencies as cities face power outages, health risks

Author:     Published: July 22, 2019 Smartcities Dive

Dive Brief:

  • The mayors of Boston, New York, Philadelphia, Baltimore andWashington, DC declared heat emergencies as temperatures across the Northeast soared to 100-plus degrees over the weekend. The mayors shared information on public spaces to be used as “relief centers,” and enhanced outreach efforts for the homeless and other vulnerable populations.
  • The excessive heat caused power outages across swaths of Brooklyn and Queens, NY on Sunday, while storms in the Washington, DC metro area left nearly 5,000 residents without power.
  • Heat waves across the U.S. were responsible for six deaths over the weekend, according to CBS News. Four people died in Maryland, one died in Arkansas and one died in Arizona.

Dive Insight:

The heat wave is causing technology failures throughout the East Coast. Thousands of New York residents were left without power for the second weekend in a row, following an outage on July 13 that left 72,000 people in darkness, according to the city’s utility company Consolidated Edison (Con Ed). At the time, Con Ed warned the outages could continue due to the electric grid’s inability to sustain demand in the face of excessive heat.

In fact, 5G functionality was called into question as temperatures climb to unprecedented numbers. Joanna Stern, a columnist for The Wall Street Journal, ran tests of 5G signals in the heat, finding the service was not very reliable.

“In Atlanta, where it was 90 degrees the day I visited, I could run only one or two 5G download tests before the phone would overheat and switch to 4G,”she wrote. The 5G failure raises concern about the reliability of innovations like autonomous vehicles and connected infrastructure in the face of rising temperatures.

Getting residents to take heat advisories seriously can be a difficult task. Most city departments turned to social media to engage with residents, as some police departments used humor to add levity to the situation. The Braintree Police Department in Massachusetts requested that anyone considering criminal activity “hold off until Monday” and instead “binge Stranger Things season 3” and “practice karate,” while the New York Police Department joked, “Sunday has been canceled.”

However, rising temperatures are no joking matter. Deaths caused by excessive heat illustrate the dangers urban residents face from climates change. By prioritizing resources like water amenities and free indoor public spaces, city officials can keep residents healthy and potentially save lives.

Eastern U.S. cities spewing 9 times more methane into air than thought

Author: Seth Borenstein Published: July 23, 2019 whyy.org

In this 2018 photo, a Twin Otter aircraft flies over New York Harbor and New York City on a research mission. In older Eastern US cities, nine times as much natural gas is leaking out of pipelines, homes than federal government had thought. (Eric Kort/University of Michigan via AP)
In this 2018 photo, a Twin Otter aircraft flies over New York Harbor and New York City on a research mission. In older Eastern US cities, nine times as much natural gas is leaking out of pipelines, homes than federal government had thought. (Eric Kort/University of Michigan via AP)

Older U.S. east coast cities are leaking nine times as much natural gas into the air — from homes or pipes heading into houses — than the federal government had thought, a new airborne monitoring study finds.

It’s probably not a safety problem because what’s coming out doesn’t reach explosive concentrations, but the extra methane heading into the air is a climate change issue, said study co-author University of Michigan atmospheric scientist Eric Kort.

Scientists flew a National Oceanic and Atmospheric Administration airplane over New York City, Washington, Philadelphia, Boston, Baltimore and Providence, Rhode Island, for 1,200 hours in 2018 and found lots more methane. They couldn’t tell if the methane, a potent greenhouse gas, was leaking from inside homes or the pipes leading to homes.

“You have a very leaky system,” study co-author Colm Sweeney, a NOAA atmospheric scientist, said Monday.

The six cities spewed nearly 937,000 tons of methane (850,000 metric tons), which is more than twice what the U.S. Environmental Protection Agency estimates, according to the study in the journal Geophysical Research Letters.

Methane comes from different places, not just natural gas, and that’s where the study found the biggest change from what the government had previously thought.

The EPA’s estimates had figured much of the methane coming out of the five cities spewed from landfills and wetlands, not natural gas for home use. But the airplane monitors, which could differentiate between landfill gas and natural gas based on other chemicals that come out, found that 88% of the methane was natural gas, except in Providence.

So scientists calculated that nine times as much natural gas was being released as EPA had estimated.

Previous studies had looked at individual cities using different methods. This study is the first to give a comprehensive look over a large area.

Cornell University’s Robert Howarth, who wasn’t part of the study, praised it, saying it “shows the problem is widespread.”

Methane traps about 30 times more heat than carbon dioxide, but doesn’t last nearly as long. By showing that leaks are a big issue, the study “represents a huge opportunity to get some early gains on controlling greenhouse gas emissions,” Sweeney said.

South Carolina General Assembly General Bill Renewable Energy Programs

Renewable energy programs

SECTION    1.    Title 58 of the 1976 Code is amended by adding:

“CHAPTER 41
Renewable Energy Programs
Section 58-41-05.    The commission is directed to address all renewable energy issues in a fair and balanced manner, considering the costs and benefits to all customers of all programs and tariffs that relate to renewable energy and energy storage, both as part of the utility’s power system and as direct investments by customers for their own energy needs and renewable goals. The commission also is directed to ensure that the revenue recovery, cost allocation, and rate design of utilities that it regulates are just and reasonable and properly reflect changes in the industry as a whole, the benefits of customer renewable energy, energy efficiency, and demand response, as well as any utility or state-specific impacts unique to South Carolina which are brought about by the consequences of this act.

Section 58-41-10.    As used in this chapter:

(1)    ‘AC’ means alternating current as measured at the point of interconnection of the small power producer’s facility to the interconnecting electrical utility’s transmission or distribution system.

(2)    ‘Avoided costs’ means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.

(3)    ‘Commission’ means the South Carolina Public Service Commission.

(4)    ‘Electrical utility’ is defined as set forth in Section 58-27-10(7), provided, however, that electrical utilities serving less than one hundred thousand customer accounts must be exempt from the provisions of this chapter. A renewable energy supplier participating in an electrical utility’s voluntary renewable energy program pursuant to this chapter must not be considered an electrical utility for purposes of this chapter.

(5)    ‘Eligible customer’ means a retail customer with a new or existing contract demand greater than or equal to one megawatt at a single-metered location or aggregated across multiple-metered locations.

(6)    ‘Generation credit’ means a credit applied by an electrical utility to the bill of a participating customer that is equal to the value of the energy and capacity avoided by the electrical utility as a result of procuring energy and capacity from a renewable energy facility.

(7)    ‘Participating customer’ means an eligible customer that elects to have a portion or all of its electricity needs supplied by a voluntary renewable energy program.

(8)    ‘Participating customer agreement’ means an agreement between a participating customer, its electrical utility, and the renewable energy supplier establishing each party’s rights and obligations under the electrical utility’s voluntary renewable energy program.

(9)    ‘Power purchase agreement’ means an agreement between an electrical utility and a small power producer for the purchase and sale of energy, capacity, and ancillary services from the small power producer’s qualifying small power production facility.

(10)    ‘PURPA’ means the Public Utility Regulatory Policies Act of 1978, as amended.

(11)    ‘Renewable energy contract’ means a power purchase agreement between an electrical utility and a renewable energy supplier that commits the parties to participating in an electrical utility’s voluntary renewable energy program for the purchase and sale of energy and capacity.

(12)    ‘Renewable energy facility’ means a facility for the production of electrical energy that utilizes a renewable generation resource as defined in Section 58-39-120(F), that is placed in service after the effective date of this chapter, and for which costs are not included in an electrical utility’s rates.

(13)    ‘Renewable energy supplier’ means the owner or operator of a renewable energy facility, including the affiliate of an electrical utility that contracts with a participating customer.

(14)    ‘Small power producer’ means a person or corporation owning or operating a ‘qualifying small power production facility’ as defined in 16 U.S.C. Section 796, as amended.

(15)    ‘Standard offer’ means the avoided cost rates, power purchase agreement, and terms and conditions approved by the commission and applicable to purchases of energy and capacity by electrical utilities as provided in this chapter from small power producers up to two megawatts AC in size.

(16)    ‘Voluntary renewable energy program’ means a tariff filed with the commission by an electrical utility that enables a participating commercial or industrial customer to receive and pay for electric service, that reflects the program cost, and that includes the environmental attributes specified in the participating customer agreement and renewable energy contract, including a generation credit for such renewable energy, from the electrical utility pursuant to the terms of the tariff.

Section 58-41-20.    (A)    As soon as is practicable after the effective date of this chapter, the commission shall open a docket for the purpose of establishing each electrical utility’s standard offer, avoided cost methodologies, form contract power purchase agreements, commitment to sell forms, and any other terms or conditions necessary to implement this section. Within six months after the effective date of this chapter, and at least once every twenty-four months thereafter, the commission shall approve each electrical utility’s standard offer, avoided cost methodologies, form contract power purchase agreements, commitment to sell forms, and any other terms or conditions necessary to implement this section. Within such proceeding the commission shall approve one or more standard form power purchase agreements for use for qualifying small power production facilities not eligible for the standard offer. Such power purchase agreements shall contain provisions, including, but not limited to, provisions for force majeure, indemnification, choice of venue, and confidentiality provisions and other such terms, but shall not be determinative of price or length of the power purchase agreement. The commission may approve multiple form power purchase agreements to accommodate various generation technologies and other project-specific characteristics. This provision shall not restrict the right of parties to enter into power purchase agreements with terms that differ from the commission-approved form(s). Any decisions by the commission shall be just and reasonable to the ratepayers of the electrical utility, in the public interest, consistent with PURPA and the Federal Energy Regulatory Commission’s implementing regulations and orders, and nondiscriminatory to small power producers; and shall strive to reduce the risk placed on the using and consuming public.

(1)    Proceedings conducted pursuant to this section shall be separate from the electrical utilities’ annual fuel cost proceedings conducted pursuant to Section 58-27-865.

(2)    Proceedings shall include an opportunity for intervention, discovery, filed comments or testimony, and an evidentiary hearing.

(B)    In implementing this chapter, the commission shall treat small power producers on a fair and equal footing with electrical utility-owned resources by ensuring that:

(1)    rates for the purchase of energy and capacity fully and accurately reflect the electrical utility’s avoided costs;

(2)    power purchase agreements, including terms and conditions, are commercially reasonable and consistent with regulations and orders promulgated by the Federal Energy Regulatory Commission implementing PURPA; and

(3)    each electrical utility’s avoided cost methodology fairly accounts for costs avoided by the electrical utility or incurred by the electrical utility, including, but not limited to, energy, capacity, and ancillary services provided by or consumed by small power producers including those utilizing energy storage equipment. Avoided cost methodologies approved by the commission may account for differences in costs avoided based on the geographic location and resource type of a small power producer’s qualifying small power production facility.

(C)    The avoided cost rates offered by an electrical utility to a small power producer not eligible for the standard offer must be calculated based on the avoided cost methodology most recently approved by the commission. In the event that a small power producer and an electrical utility are unable to mutually agree on an avoided cost rate, the small power producer shall have the right to have any disputed issues resolved by the commission in a formal complaint proceeding. The commission may require mediation prior to a formal complaint proceeding.

(D)    A small power producer shall have the right to sell the output of its facility to the electrical utility at the avoided cost rates and pursuant to the power purchase agreement then in effect by delivering an executed notice of commitment to sell form to the electrical utility. The commission shall approve a standard notice of commitment to sell form to be used for this purpose that provides the small power producer a reasonable period of time from its submittal of the form to execute a power purchase agreement. In no event, however, shall the small power producer, as a condition of preserving the pricing and terms and conditions established by its submittal of an executed commitment to sell form to the electrical utility, be required to execute a power purchase agreement prior to receipt of a final interconnection agreement from the electrical utility.

(E)(1)    Electrical utilities shall file with the commission power purchase agreements entered into pursuant to PURPA, resulting from voluntary negotiation of contracts between an electrical utility and a small power producer not eligible for the standard offer.

(2)    The commission is authorized to open a generic docket for the purposes of creating programs for the competitive procurement of energy and capacity from renewable energy facilities by an electrical utility within the utility’s balancing authority area if the commission determines such action to be in the public interest.

(3)    In establishing standard offer and form contract power purchase agreements, the commission shall consider whether such power purchase agreements should prohibit any of the following:

(a)    termination of the power purchase agreement, collection of damages from small power producers, or commencement of the term of a power purchase agreement prior to commercial operation, if delays in achieving commercial operation of the small power producer’s facility are due to the electrical utility’s interconnection delays; or

(b)    the electrical utility reducing the price paid to the small power producer based on costs incurred by the electrical utility to respond to the intermittent nature of electrical generation by the small power producer.

(F)(1)    Electrical utilities, subject to approval of the commission, shall offer to enter into fixed price power purchase agreements with small power producers for the purchase of energy and capacity at avoided cost, with commercially reasonable terms and a duration of ten years. The commission may also approve commercially reasonable fixed price power purchase agreements with a duration longer than ten years, which must contain additional terms, conditions, and/or rate structures as proposed by intervening parties and approved by the commission, including, but not limited to, a reduction in the contract price relative to the ten year avoided cost. Notwithstanding any other language to the contrary, the commission will make such a determination in proceedings conducted pursuant to subsection (A). The avoided cost rates applicable to fixed price power purchase agreements entered into pursuant to this item shall be based on the avoided cost rates and methodologies as determined by the commission pursuant to this section. The terms of this subsection apply only to those small power producers whose qualifying small power production facilities have active interconnection requests on file with the electrical utility prior to the effective date of this act. The commission may determine any other necessary terms and conditions deemed to be in the best interest of the ratepayers. This item is not intended, and shall not be construed, to abrogate small power producers’ rights under PURPA that existed prior to the effective date of the act.

(2)    Once an electrical utility has executed interconnection agreements and power purchase agreements with qualifying small power production facilities located in South Carolina with an aggregate nameplate capacity equal to twenty percent of the previous five-year average of the electrical utility’s South Carolina retail peak load, that electrical utility shall offer to enter into fixed price power purchase agreements with small power producers for the purchase of energy and capacity at avoided cost, with the terms, conditions, rates, and terms of length for contracts as determined by the commission in a separate docket or in a proceeding conducted pursuant to subsection (A). The commission is expressly directed to consider the potential benefits of terms with a longer duration to promote the state’s policy of encouraging renewable energy.

(G)    Nothing in this section prohibits the commission from adopting various avoided cost methodologies or amending those methodologies in the public interest.

(H)    Unless otherwise agreed to between the electrical utility and the small power producer, a power purchase agreement entered into pursuant to PURPA may not allow curtailment of qualifying facilities in any manner that is inconsistent with PURPA or implementing regulations and orders promulgated by the Federal Energy Regulatory Commission.

(I)    The commission is authorized to employ, through contract or otherwise, third-party consultants and experts in carrying out its duties under this section, including, but not limited to, evaluating avoided cost rates, methodologies, terms, calculations, and conditions under this section. The commission is exempt from complying with the State Procurement Code in the selection and hiring of a third-party consultant or expert authorized by this subsection. The commission shall engage, for each utility, a qualified independent third party to submit a report that includes the third party’s independently derived conclusions as to that third party’s opinion of each utility’s calculation of avoided costs for purposes of proceedings conducted pursuant to this section. The qualified independent third party is subject to the same ex parte prohibitions contained in Chapter 3, Title 58 as all other parties. The qualified independent third party shall submit all requests for documents and information necessary to their analysis under the authority of the commission and the commission shall have full authority to compel response to the requests. The qualified independent third party’s duty will be to the commission. Any conclusions based on the evidence in the record and included in the report are intended to be used by the commission along with all other evidence submitted during the proceeding to inform its ultimate decision setting the avoided costs for each electrical utility. The utilities may require confidentiality agreements with the independent third party that do not impede the third-party analysis. The utilities shall be responsive in providing all documents, information, and items necessary for the completion of the report. The independent third party shall also include in the report a statement assessing the level of cooperation received from the utility during the development of the report and whether there were any material information requests that were not adequately fulfilled by the electrical utility. Any party to this proceeding shall be able to review the report including the confidential portions of the report upon entering into an appropriate confidentiality agreement. The commission and the Office of Regulatory Staff may not hire the same third-party consultant or expert in the same proceeding or to address the same or similar issues in different proceedings.

(J)    Each electrical utility’s avoided cost filing must be reasonably transparent so that underlying assumptions, data, and results can be independently reviewed and verified by the parties and the commission. The commission may approve any confidentiality protections necessary to allow for independent review and verification of the avoided cost filing.

Section 58-41-30.    (A)    Within one hundred and twenty days of the effective date of this chapter, subject to subsection (F), each electrical utility shall file a proposed voluntary renewable energy program for review and approval by the commission. The commission shall conduct a proceeding to review the program and establish reasonable terms and conditions for the program. Interested parties shall have the right to participate in the proceeding. The commission may periodically hold additional proceedings to update the program. At a minimum, the program shall provide that:

(1)    the participating customer shall have the right to select the renewable energy facility and negotiate with the renewable energy supplier on the price to be paid by the participating customer for the energy, capacity, and environmental attributes of the renewable energy facility and the term of such agreement so long as such terms are consistent with the voluntary renewable program service agreement as approved by the commission;

(2)    the renewable energy contract and the participating customer agreement must be of equal duration;

(3)    in addition to paying a retail bill calculated pursuant to the rates and tariffs that otherwise would apply to the participating customer, reduced by the amount of the generation credit, a participating customer shall reimburse the electrical utility on a monthly basis for the amount paid by the electrical utility to the renewable energy supplier pursuant to the participating customer agreement and renewable energy contract, plus an administrative fee approved by the commission; and

(4)    eligible customers must be allowed to bundle their demand under a single participating customer agreement and renewable energy contract and must be eligible annually to procure an amount of capacity as approved by the commission.

(B)    The commission may approve a program that provides for options that include, but are not limited to, both variable and fixed generation credit options.

(C)    The commission may limit the total portion of each electrical utility’s voluntary renewable energy program that is eligible for the program at a level consistent with the public interest and shall provide standard terms and conditions for the participating customer agreement and the renewable energy contract, subject to commission review and approval.

(D)    A participating customer shall bear the burden of any reasonable costs associated with participating in a voluntary renewable energy program. An electrical utility may not charge any nonparticipating customers for any costs incurred pursuant to the provisions of this section.

(E)    A renewable energy facility may be located anywhere in the electrical utility’s service territory within the utility’s balancing authority.

(F)    If the commission determines that an electrical utility has a voluntary renewable energy program on file with the commission as of the effective date of this chapter, that conforms with the requirements of this section, the utility is not required to make a new filing to meet the requirements of subsection (A).

Section 58-41-40.    (A)    It is the intent of the General Assembly to expand the opportunity to support solar energy and support access to solar energy options for all South Carolinians, including those who lack the income to afford the upfront investment in solar panels or those who do not own their homes or have suitable rooftops. The General Assembly encourages all electric service providers in this State to consider offering neighborhood community solar programs.

(B)(1)    Within sixty days after the effective date of this chapter, the commission shall open a docket for each electrical utility to review the community solar programs established pursuant to Act 236 of 2014 and to solicit status information on existing programs from the electrical utilities.

(2)    Within one hundred and eighty days after the commission opens the docket pursuant to item (1), the electrical utilities shall update their report on their existing programs and may propose new programs.

(C)    Subject to review by the commission, a public utility must be entitled to full and timely cost recovery for all reasonable and prudent costs incurred in implementing and complying with this section. Participating customers shall bear the burden of any reasonable and prudent costs associated with participating in a neighborhood community solar program; however, the commission shall nonetheless promote access to solar energy projects for low and moderate income customers. An electrical utility may not charge any nonparticipating customers for any costs incurred pursuant to the provisions of this section.”

Findings and enumeration of electrical utility customer rights

SECTION    2.    Article 7, Chapter 27, Title 58 of the 1976 Code is amended by adding:

“Section 58-27-845.    (A)    The General Assembly finds that there is a critical need to:

(1)    protect customers from rising utility costs;

(2)    provide opportunities for customer measures to reduce or manage electrical consumption from electrical utilities in a manner that contributes to reductions in utility peak electrical demand and other drivers of electrical utility costs; and

(3)    equip customers with the information and ability to manage their electric bills.

(B)    Every customer of an electrical utility has the right to a rate schedule that offers the customer a reasonable opportunity to employ such energy and cost-saving measures as energy efficiency, demand response, or onsite distributed energy resources in order to reduce consumption of electricity from the electrical utility’s grid and to reduce electrical utility costs.

(C)    In fixing just and reasonable utility rates pursuant to Section 58-3-140 and Section 58-27-810, the commission shall consider whether rates are designed to discourage the wasteful use of public utility services while promoting all use that is economically justified in view of the relationships between costs incurred and benefits received, and that no one class of customers are unduly burdening another, and that each customer class pays, as close as practicable, the cost of providing service to them.

(D)    For each class of service, the commission must ensure that each electrical utility offers to each class of service a minimum of one reasonable rate option that aligns the customer’s ability to achieve bill savings with long-term reductions in the overall cost the electrical utility will incur in providing electric service, including, but not limited to, time-variant pricing structures.

(E)    Every customer of an electrical utility has a right to obtain their own electric usage data in a machine-readable, accessible format to the extent such is readily available. Electrical utilities shall allow customers an electronic means to assent to share the customer’s energy usage data with a third-party vendor designated by the customer.”

Definition of “customer-generator”

SECTION    3.    Section 58-40-10(C) of the 1976 Code is amended to read:

“(C)    ‘Customer-generator’ means the owner, operator, lessee, or customer-generator lessee of an electric energy generation unit which:

(1)    generates or discharges electricity from a renewable energy resource, including an energy storage device configured to receive electrical charge solely from an onsite renewable energy resource;

(2)    has an electrical generating system with a capacity of:

(a)    not more than the lesser of one thousand kilowatts (1,000 kW AC) or one hundred percent of contract demand if a nonresidential customer; or

(b)    not more than twenty kilowatts (20 kW AC) if a residential customer;

(3)    is located on a single premises owned, operated, leased, or otherwise controlled by the customer;

(4)    is interconnected and operates in parallel phase and synchronization with an electrical utility and complies with the applicable interconnection standards;

(5)    is intended primarily to offset part or all of the customer-generator’s own electrical energy requirements; and

(6)    meets all applicable safety, performance, interconnection, and reliability standards established by the commission, the National Electrical Code, the National Electrical Safety Code, the Institute of Electrical and Electronics Engineers, Underwriters Laboratories, the federal Energy Regulatory Commission, and any local governing authorities.”

Definition of “solar choice metering measurement”

SECTION    4.    Section 58-40-10 of the 1976 Code is amended by adding an appropriately lettered subsection at the end to read:

“( )    ‘Solar choice metering measurement’ means the process, method, or calculation used for purposes of billing and crediting at the commission determined value.”

Legislative intent and instructions

SECTION    5.    Section 58-40-20 of the 1976 Code is amended to read:

“Section 58-40-20.    (A)    It is the intent of the General Assembly to:

(1)    build upon the successful deployment of solar generating capacity through Act 236 of 2014 to continue enabling market-driven, private investment in distributed energy resources across the State by reducing regulatory and administrative burdens to customer installation and utilization of onsite distributed energy resources;

(2)    avoid disruption to the growing market for customer-scale distributed energy resources; and

(3)    require the commission to establish solar choice metering requirements that fairly allocate costs and benefits to eliminate any cost shift or subsidization associated with net metering to the greatest extent practicable.

(B)    An electrical utility shall make net energy metering available to all customer-generators who apply before June 1, 2021, according to the terms and conditions provided to all parties in Commission Order No. 2015-194. Customer-generators who apply for net metering after the effective date of this act but before June 1, 2021, including subsequent owners of the customer-generator facility or premises, may continue net energy metering service as provided for in Commission Order No. 2015-194 until May 31, 2029.

(C)    No later than January 1, 2020, the commission shall open a generic docket to:

(1)    investigate and determine the costs and benefits of the current net energy metering program; and

(2)    establish a methodology for calculating the value of the energy produced by customer-generators.

(D)    In evaluating the costs and benefits of the net energy metering program, the commission shall consider:

(1)    the aggregate impact of customer-generators on the electrical utility’s long-run marginal costs of generation, distribution, and transmission;

(2)    the cost of service implications of customer-generators on other customers within the same class, including an evaluation of whether customer-generators provide an adequate rate of return to the electrical utility compared to the otherwise applicable rate class when, for analytical purposes only, examined as a separate class within a cost of service study;

(3)    the value of distributed energy resource generation according to the methodology approved by the commission in Commission Order No. 2015-194;

(4)    the direct and indirect economic impact of the net energy metering program to the State; and

(5)    any other information the commission deems relevant.

(E)    The value of the energy produced by customer-generators must be updated annually and the methodology revisited every five years.

(F)(1)    After notice and opportunity for public comment and public hearing, the commission shall establish a ‘solar choice metering tariff’ for customer-generators to go into effect for applications received after May 31, 2021.

(2)    In establishing any successor solar choice metering tariffs, and in approving any future modifications, the commission shall determine how meter information is used for calculating the solar choice metering measurement that is just and reasonable in light of the costs and benefits of the solar choice metering program.

(3)    A solar choice metering tariff shall include a methodology to compensate customer-generators for the benefits provided by their generation to the power system. In determining the appropriate billing mechanism and energy measurement interval, the commission shall consider:

(a)    current metering capability and the cost of upgrading hardware and billing systems to accomplish the provisions of the tariff;

(b)    the interaction of the tariff with time-variant rate schedules available to customer-generators and whether different measurement intervals are justified for customer-generators taking service on a time-variant rate schedule;

(c)    whether additional mitigation measures are warranted to transition existing customer-generators; and

(d)    any other information the commission deems relevant.

(G)    In establishing a successor solar choice metering tariff, the commission is directed to:

(1)    eliminate any cost shift to the greatest extent practicable on customers who do not have customer-sited generation while also ensuring access to customer-generator options for customers who choose to enroll in customer-generator programs; and

(2)    permit solar choice customer-generators to use customer-generated energy behind the meter without penalty.

(H)    The commission shall establish a minimum guaranteed number of years to which solar choice metering customers are entitled pursuant to the commission approved energy measurement interval and other terms of their agreement with the electrical utility.

(I)    Nothing in this section, however, prohibits an electrical utility from continuing to recover distributed energy resource program costs in the manner and amount approved by Commission Order No. 2015-194 for customer-generators applying before June 1, 2021. Such recovery shall remain in place until full cost recovery is realized. Electrical utilities are prohibited from recovering lost revenues associated with customer-generators who apply for customer-generator programs on or after June 1, 2021.

(J)    Nothing in the section prohibits the commission from considering and establishing tariffs for another renewable energy resource.

Lease of renewable electric generation facility

SECTION    6.    Section 58-27-2610 of the 1976 Code is amended to read:

“Section 58-27-2610.    (A)    An entity that owns a renewable electric generation facility, located on a premises or residence owned or leased by an eligible customer-generator lessee to serve the electric energy requirements of that particular premises or residence or to enable the customer-generator lessee to obtain a credit for or engage in the sale of energy from the renewable electric generation facility to that customer-generator lessee’s retail electric provider or its designee, shall be permitted to lease such facility exclusively to a customer-generator lessee under a lease, provided that the entity complies with the terms, conditions, and restrictions set forth within this article and holds a valid certificate issued by the Office of Regulatory Staff. An entity owning renewable electric generation facilities in compliance with the terms of this article shall not be considered an ‘electrical utility’ under Section 58-27-10 if the renewable electric generation facilities are only made available to a customer-generator lessee for the customer-generator lessee’s use on the customer-generator lessee’s premises or the residence where the renewable electric generation facilities are located, or for the sale of energy to that customer-generator lessee’s retail electric provider or its designee, and pursuant to a lease.

(B)    All customer-generator lessees that interconnect renewable electric generation facilities to a retail electric provider’s transmission or distribution system must enroll in the applicable rate schedules made available by that retail electric provider and the customer-generator lessee shall otherwise comply with all requirements of Section 58-40-10, et seq., or the policy adopted by the retail electric provider not subject to Section58-40-10, et seq.

(C)    To comply with the terms of this article, each customer-generator lessee renewable electric generation facility shall serve only one premises or residence, and shall not serve multiple customer-generator lessees or multiple premises or residences.

(D)    Any lease of a renewable electric generation facility not entered into pursuant to this article is prohibited. The owner of a renewable electric generation facility subject to any lease entered into outside of this program shall be considered an ‘electrical utility’ under Section 58-27-10.

(E)    This section shall not be construed as allowing any sales of electricity from renewable electric generation facilities directly to any customer of any retail electric provider by the owner. This article shall not be construed as abridging or impairing any existing rights or obligations, established by contract or statute, of retail electric providers to serve South Carolina customers. The electrical output from any renewable electric generation unit leased pursuant to this program shall be the sole and exclusive property of the customer-generator lessee.

(F)    An entity and its affiliates that lawfully provide retail electric service to the public may offer leases of renewable generation facilities in those areas or territories where it provides retail electric service. No such provider or affiliate shall offer or enter into leases of renewable generation facilities in areas served by another retail electric provider.

(G)    The costs an electrical utility incurs in marketing, installing, owning, or maintaining solar leases through its own leasing programs as a lessor shall not be recovered from other nonparticipating electrical utility customers through rates, provided, however, that an electrical utility and the customer-generator lessees which lease facilities from it may participate on an equal basis with other lessors and lessees in any applicable programs provided pursuant to Chapter 39 of this title and nothing in this section shall prevent the reasonable and prudent costs of a utility’s distributed energy resource programs, including the provision of incentives to its own lessees and other allowable costs, from being reflected in a utility’s rates as provided for in Chapter 39 or as otherwise permitted under generally applicable regulatory principles.

(H)(1)    The provisions of this Article 23 related to leased generation facilities shall not apply to:

(a)    facilities serving a single premises that are not interconnected with a retail electric provider;

(b)    facilities owned by customer-generators but financed by a third party; or

(c)    facilities used exclusively for standby emergency service or participation in an approved standby generation program operated by a retail electric provider.

(2)    The commission may promulgate regulations consistent with this section interpreting the scope of these exemptions as to electrical utilities.”

Integrated resource plans

SECTION    7.    Section 58-37-40 of the 1976 Code is amended to read:

“Section 58-37-40.    (A)    Electrical utilities, electric cooperatives, municipally owned electric utilities, and the South Carolina Public Service Authority must each prepare an integrated resource plan. An integrated resource plan must be prepared and submitted at least every three years. Nothing in this section may be construed as requiring interstate natural gas companies whose rates and services are regulated only by the federal government or gas utilities subject to the jurisdiction of the commission to prepare and submit an integrated resource plan.

(1)    Each electrical utility must submit its integrated resource plan to the commission. The integrated resource plan must be posted on the electrical utility’s website and on the commission’s website.

(2)    Electric cooperatives and municipally owned electric utilities shall each submit an integrated resource plan to the State Energy Office. Each integrated resource plan must be posted on the State Energy Office’s website. If an electric cooperative or municipally owned utility has a website, its integrated resource plan must also be posted on its website. For distribution, electric cooperatives that are members of a cooperative that provides wholesale service, the integrated resource plan may be coordinated and consolidated into a single plan provided that nonshared resources or programs of individual distribution cooperatives are highlighted. Where plan components listed in subsection (B)(1) and (2) of this section do not apply to a distribution or wholesale cooperative or a municipally owned electric utility as a result of the cooperative or the municipally owned electric utility not owning or operating generation resources, the plan may state that fact or refer to the plan of the wholesale power generator. For purposes of this section, a wholesale power generator does not include a municipally created joint agency if that joint agency receives at least seventy-five percent of its electricity from a generating facility owned in partnership with an electrical utility and that electrical utility:

(a)    generally serves the area in which the joint agency’s members are located; and

(b)    is responsible for dispatching the capacity and output of the generated electricity.

(3)    The South Carolina Public Service Authority shall submit its integrated resource plan to the State Energy Office. The integrated resource plan must be developed in consultation with the electric cooperatives and municipally owned electric utilities purchasing power and energy from the Public Service Authority and consider any feedback provided by retail customers and shall include the effect of demand-side management activities of the electric cooperatives and municipally owned electric utilities that directly purchase power and energy from the Public Service Authority or sell power and energy generated by the Public Service Authority. The integrated resource plan must be posted on the State Energy Office’s website and on the Public Service Authority’s website.

(B)(1)    An integrated resource plan shall include all of the following:

(a)    a long-term forecast of the utility’s sales and peak demand under various reasonable scenarios;

(b)    the type of generation technology proposed for a generation facility contained in the plan and the proposed capacity of the generation facility, including fuel cost sensitivities under various reasonable scenarios;

(c)    projected energy purchased or produced by the utility from a renewable energy resource;

(d)    a summary of the electrical transmission investments planned by the utility;

(e)    several resource portfolios developed with the purpose of fairly evaluating the range of demand-side, supply-side, storage, and other technologies and services available to meet the utility’s service obligations. Such portfolios and evaluations must include an evaluation of low, medium, and high cases for the adoption of renewable energy and cogeneration, energy efficiency, and demand response measures, including consideration of the following:

(i)        customer energy efficiency and demand response programs;

(ii)    facility retirement assumptions; and

(iii)    sensitivity analyses related to fuel costs, environmental regulations, and other uncertainties or risks;

(f)    data regarding the utility’s current generation portfolio, including the age, licensing status, and remaining estimated life of operation for each facility in the portfolio;

(g)    plans for meeting current and future capacity needs with the cost estimates for all proposed resource portfolios in the plan;

(h)    an analysis of the cost and reliability impacts of all reasonable options available to meet projected energy and capacity needs; and

(i)        a forecast of the utility’s peak demand, details regarding the amount of peak demand reduction the utility expects to achieve, and the actions the utility proposes to take in order to achieve that peak demand reduction.

(2)    An integrated resource plan may include distribution resource plans or integrated system operation plans.

(C)(1)    The commission shall have a proceeding to review each electrical utility’s integrated resource plan. As part of the integrated resource plan filing, the commission shall allow intervention by interested parties. The commission shall establish a procedural schedule to permit reasonable discovery after an integrated resource plan is filed in order to assist parties in obtaining evidence concerning the integrated resource plan, including the reasonableness and prudence of the plan and alternatives to the plan raised by intervening parties. No later than three hundred days after an electrical utility files an integrated resource plan, the commission shall issue a final order approving, modifying, or denying the plan filed by the electrical utility.

(2)    The commission shall approve an electrical utility’s integrated resource plan if the commission determines that the proposed integrated resource plan represents the most reasonable and prudent means of meeting the electrical utility’s energy and capacity needs as of the time the plan is reviewed. To determine whether the integrated resource plan is the most reasonable and prudent means of meeting energy and capacity needs, the commission, in its discretion, shall consider whether the plan appropriately balances the following factors:

(a)    resource adequacy and capacity to serve anticipated peak electrical load, and applicable planning reserve margins;

(b)    consumer affordability and least cost;

(c)    compliance with applicable state and federal environmental regulations;

(d)    power supply reliability;

(e)    commodity price risks;

(f)    diversity of generation supply; and

(g)    other foreseeable conditions that the commission determines to be for the public interest.

(3)    If the commission modifies or rejects an electrical utility’s integrated resource plan, the electrical utility, within sixty days after the date of the final order, shall submit a revised plan addressing concerns identified by the commission and incorporating commission-mandated revisions to the integrated resource plan to the commission for approval. Within sixty days of the electrical utility’s revised filing, the Office of Regulatory Staff shall review the electrical utility’s revised plan and submit a report to the commission assessing the sufficiency of the revised filing. Other parties to the integrated resource plan proceeding also may submit comments. No later than sixty days after the Office of Regulatory Staff report is filed with the commission, the commission at its discretion may determine whether to accept the revised integrated resource plan or to mandate further remedies that the commission deems appropriate.

(4)    The submission, review, and acceptance of an integrated resource plan by the commission, or the inclusion of any specific resource or experience in an accepted integrated resource plan, shall not be determinative of the reasonableness or prudence of the acquisition or construction of any resource or the making of any expenditure. The electrical utility shall retain the burden of proof to show that all of its investments and expenditures are reasonable and prudent when seeking cost recovery in rates.

(D)(1)    An electrical utility shall submit annual updates to its integrated resource plan to the commission. An annual update must include an update to the electric utility’s base planning assumptions relative to its most recently accepted integrated resource plan, including, but not limited to: energy and demand forecast, commodity fuel price inputs, renewable energy forecast, energy efficiency and demand-side management forecasts, changes to projected retirement dates of existing units, along with other inputs the commission deems to be for the public interest. The electrical utility’s annual update must describe the impact of the updated base planning assumptions on the selected resource plan.

(2)    The Office of Regulatory Staff shall review each electric utility’s annual update and submit a report to the commission providing a recommendation concerning the reasonableness of the annual update. After reviewing the annual update and the Office of Regulatory Staff report, the commission may accept the annual update or direct the electrical utility to make changes to the annual update that the commission determines to be in the public interest.

(E)    The commission is authorized to promulgate regulations to carry out the provisions of this section.”

Independent study to evaluate integration of emerging energy technologies

SECTION    8. Chapter 37, Title 58 of the 1976 Code is amended by adding:

“Section 58-37-60.    (A)    The commission and the Office of Regulatory Staff are authorized to initiate an independent study to evaluate the integration of renewable energy and emerging energy technologies into the electric grid for the public interest. An integration study conducted pursuant to this section shall evaluate what is required for electrical utilities to integrate increased levels of renewable energy and emerging energy technologies while maintaining economic, reliable, and safe operation of the electricity grid in a manner consistent with the public interest. Studies shall be based on the balancing areas of each electrical utility. The commission shall provide an opportunity for interested parties to provide input on the appropriate scope of the study and also to provide comments on a draft report before it is finalized. All data and information relied on by the independent consultant in preparation of the draft study shall be made available to interested parties, subject to appropriate confidentiality protections, during the public comment period. The results of the independent study shall be reported to the General Assembly.

(B)    The commission may require regular updates from utilities regarding the implementation of the state’s renewable energy policies.

(C)    The commission may hire or retain a consultant to assist with the independent study authorized by this section. The commission is exempt from complying with the State Procurement Code in the selection and hiring of the consultant authorized by this subsection.”

Mandatory demonstration before commencing construction of major utility facility

SECTION    9.    Section 58-33-110 of the 1976 Code is amended by adding an item at the end to read:

“( )(a)    Notwithstanding the provisions of item (7), and not limiting the provisions above, a person may not commence construction of a major utility facility for generation in the State of South Carolina without first having made a demonstration that the facility to be built has been compared to other generation options in terms of cost, reliability, and any other regulatory implications deemed legally or reasonably necessary for consideration by the commission. The commission is authorized to adopt rules for such evaluation of other generation options.

(b)    The commission may, upon a showing of a need, require a commission-approved process that includes:

(i)        the assessment of an unbiased independent evaluator retained by the Office of Regulatory Staff as to reasonableness of any certificate sought under this section for new generation;

(ii)    a report from the independent evaluator to the commission regarding the transparency, completeness, and integrity of bidding processes, if any;

(iii)    a reasonable period for interested parties to review and comment on proposed requests for proposals, bid instructions, and bid evaluation criteria, if any, prior to finalization and issuance, subject to any trade secrets that could hamper future negotiations; however, the independent evaluator may access all such information;

(iv)    independent evaluator access and review of final bid evaluation criteria and pricing information for any and all projects to be evaluated in comparison to the request for proposal bids received;

(v)    access through discovery, subject to appropriate confidentiality, attorney-client privilege or trade secret restrictions, for parties to this proceeding to documents developed in preparing the certificate of public convenience and necessity application;

(vi) a demonstration that the facility is consistent with an integrated resource plan approved by the commission; and

(vii)    treatment of utility affiliates in the same manner as nonaffiliates participating in the request for proposal process.”

Promulgation and review of standards for interconnection of renewable energy facilities

SECTION    10.    Section 58-27-460 of the 1976 Code is amended to read:

“Section 58-27-460.    (A)(1)    The commission shall promulgate and periodically review standards for interconnection and parallel operation of generating facilities to an electrical utility’s distribution and transmission system, where such interconnection is under the jurisdiction of the commission pursuant to Title 16, Chapter 12, Subchapter II of the United States Code, as amended, regulations and orders of the Federal Energy Regulatory Commission, and the laws of South Carolina. Each electrical utility shall implement such standards in a fair, nondiscriminatory manner.

(2)    The commission shall, within six months of the effective date of the amendments to this section, establish proceedings for the purpose of considering revisions to the standards promulgated pursuant to this section. In developing such revisions, the commission may consider any issue, which, in the exercise of its discretion, the commission deems relevant to improving the fairness and effectiveness of the procedures.

(3)    In implementing item (1), the commission shall ensure such standards provide for efficient and timely processing of interconnection requests and take into account the impact of generator interconnection on electrical utility system assets, service reliability, and power quality. Such standards shall address the impact of the addition of energy storage and the interconnection processes for amending existing interconnection requests to include energy storage. The commission shall enact standards that are fair, reasonable, and nondiscriminatory with respect to interconnection applicants, other utility customers, and electrical utilities, and the standards shall serve the public interest in terms of overall cost and system reliability.

(B)    No generating facility shall connect or operate in parallel phase and synchronization with any electrical utility without written approval by the electrical utility that all of the commission’s requirements have been met. For a generating facility that violates this provision, an electrical utility immediately may and without notice disconnect the generating facility’s electric service.

(C)    In the event of a dispute between an interconnection customer and the electrical utility on an issue relating to interconnection service, the parties first shall attempt to resolve the claim or dispute using any dispute resolution procedures provided for pursuant to the applicable interconnection standards promulgated by the commission. If the parties are unable to resolve such claim or dispute using those procedures, then either party may petition the commission for resolution of the dispute including, but not limited to, a determination of the appropriate terms and conditions for interconnection. The commission shall resolve such disputes within six months from the filing of the petition in accordance with the terms of applicable state and federal law.

(D)    Each electrical utility shall comply with the South Carolina generator interconnection procedures and all commission-approved agreements regarding interconnection practices and reporting requirements. The commission shall establish reasonable guidelines to ensure reasonable interconnection timelines, including time requirements to deliver a final system impact study to all interconnection customers that execute a system impact study agreement prior to three months after the effective date of this act. The commission shall consider implementation of additional performance incentives and enforcement mechanisms for electrical utilities to ensure compliance with this requirement.

(E)    The commission shall, as part of implementing subsection (A)(1), consider whether a comprehensive independent review of interconnection should be performed and consider whether to require each electrical utility to:

(1)    conduct a study to determine the scope and cost of necessary transmission upgrades to support development of renewable energy resources in a manner that does not impact reliability;

(2)    evaluate the cost of developing and maintaining hosting capacity maps to allow power producers to identify areas of the distribution grid that are more amenable to building and interconnecting their generation facilities and to avoid areas that are already saturated with distributed generation; and

(3)    file a list of interconnected facilities with the commission each quarter, to include interconnections that are under the jurisdiction of the Federal Energy Regulatory Commission.”

Development of consumer protection regulations

SECTION    11.    Article 23, Chapter 27, Title 58 of the 1976 Code is amended by adding:

“Section 58-27-2660.    (A)(1)    The Office of Regulatory Staff and the Department of Consumer Affairs are directed to develop consumer protection regulations regarding the sale or lease of renewable energy generation facilities pursuant to the distributed energy resource program in Chapter 40 of this title. These regulations shall provide for the appropriate disclosure provided by sellers and lessors. Sellers must comply with Title 37. Nothing herein alters existing protections afforded by Title 37.

(2)    To fulfill the duties and responsibilities provided for in this section, the Office of Regulatory Staff shall develop a formal complaint process as part of the consumer protection regulations.

(B)    The Office of Regulatory Staff is authorized to enforce any applicable consumer protection provision set forth in this title by:

(1)    conducting an investigation into an alleged violation;

(2)    issuing a cease and desist order against a further violation;

(3)    imposing an administrative fine not to exceed two thousand five hundred dollars per violation on a solar company that materially fails to comply with the consumer protection requirements; and

(4)    voiding the agreement if necessary to remedy the violation or violations.”

Office of Regulatory Staff, party of record in all commission filings, applications, or proceedings

SECTION    12.    Section 58-4-10(B) of the 1976 Code, as last amended by Act 258 of 2018, is further amended to read:

“(B)    Unless and until it chooses not to participate, the Office of Regulatory Staff must be considered a party of record in all filings, applications, or proceedings before the commission. The regulatory staff must represent the public interest of South Carolina before the commission. For purposes of this chapter only, ‘public interest’ means the concerns of the using and consuming public with respect to public utility services, regardless of the class of customer, and preservation of continued investment in and maintenance of utility facilities so as to provide reliable and high quality utility services.”

Employment of certain expert witnesses and third-party consultants exempted from State Procurement Code

SECTION    13.    Section 58-4-100 of the 1976 Code is amended to read:

“Section 58-4-100.    (A)    To the extent necessary to carry out regulatory staff responsibilities, the executive director is authorized to employ expert witnesses and other professional expertise as the executive director may consider necessary to assist the regulatory staff in its participation in commission proceedings. The compensation paid to these persons may not exceed compensation generally paid by the regulated industry for such specialists. The compensation and expenses therefor must be paid by the public utility or utilities participating in the proceedings upon agreement between the public utility or utilities participating in the proceedings and the Office of Regulatory Staff or upon approval by the Review Committee or from the regulatory staff’s budget. If paid by the public utility or utilities, the compensation and expenses must be treated by the commission, for ratemaking purposes, in a manner generally consistent with its treatment of similar expenditures incurred by utilities in the presentation of their cases before the commission. An accounting of compensation and expenses must be reported annually to the review committee, the Speaker of the House of Representatives, and the Chairman of the Senate Judiciary Committee.

(B)    The Office of Regulatory Staff is exempt from the State Procurement Code in the selection and hiring of an expert or third-party consultant to conduct an independent study described in Section 58-37-60 and Section 58-41-20(H). However, the Office of Regulatory Staff and the commission may not hire the same expert or third-party consultant in the same proceeding or to address the same or similar issues in different proceedings.”

Interpretation and construction of certain provisions

SECTION    14.    The provisions of Section 58-41-20 shall not be interpreted to supersede the conditions of any settlement entered into by an electrical utility and filed with the commission prior to the adoption of this act.

Recovery of certain costs

SECTION    15.    All costs incurred by the utility necessary to effectuate this act, that are not precluded from recovery by other provisions of this act and that do not have a recovery mechanism otherwise specified in other provisions of the act or established by state law, shall be deferred for commission consideration of recovery in any proceeding initiated under Section 58-27-870, if deemed reasonable and prudent.

Certain costs and expenses must be excluded from electrical utility rates

SECTION    16.    Notwithstanding another provision of this act, or another provision of law, no costs or expenses incurred nor any payments made by the electrical utility in compliance or in accordance with this act must be included in the electrical utility’s rates or otherwise be borne by the general body of South Carolina retail customers of the electrical utility without an affirmative finding supported by the preponderance of evidence of record and conclusion in a written order by the Public Service Commission that such expense, cost, or payment was reasonable and prudent and made in the best interest of the electrical utility’s general body of customers.

Severability

SECTION    17.    The provisions of this act are severable. If any section, subsection, paragraph, subparagraph, item, subitem, sentence, clause, phrase, or word of this act is for any reason held to be unconstitutional or invalid, such holding shall not affect the constitutionality or validity of the remaining portions of the act, the General Assembly hereby declaring that it would have passed each and every section, subsection, paragraph, subparagraph, item, subitem, sentence, clause, phrase, and word thereof, irrespective of the fact that any one or more other sections, subsections, paragraphs, subparagraphs, items, subitems, sentences, clauses, phrases, or words hereof may be declared to be unconstitutional, invalid, or otherwise ineffective.

Time effective

SECTION    18.    This act takes effect upon approval by the Governor.

Ratified the 13th day of May, 2019.

Approved the 16th day of May, 2019.

__________
This web page was last updated on June 20, 2019 at 10:47 AM

Morgan State students work to restore the school’s chapel as part of historic preservation program for black students

Author: BALTIMORE SUN  JUL 11, 2019

Morgan State students work to restore the school’s chapel as part of historic preservation program for black students

Tyriq Charleus is one of six Morgan State University architecture students working with the Touching History: Preservation in Practice program to restore wooden windows at the campus’ historic University Memorial Chapel. (Kenneth K. Lam)

An eighth-grade Spanish project convinced Stephanie Walker she ought to study architecture.

The assignment was to draw her dream house and label it in Spanish, and Walker, now a rising senior architecture major at Morgan State University, created a meticulous floor plan. So meticulous, in fact, that Walker’s teacher told her she should consider a career in architectural drawing.

Walker is among a cohort of six architecture students at Morgan State who are restoring the windows of the university’s historic chapel. It’s part of a program called Touching History: Preservation in Practice, which is meant to bring more black students into careers in historic preservation.

“I always wanted to get into architecture for affordable housing, so that I could affect the way affordable housing is designed,” Walker said. “But me being exposed to historic preservation — it’s making me change my direction.”

At the chapel, which is on the National Register of Historic Places, students are scraping lead paint from the exterior windows and repainting them, as well as repairing any rotting wood they discover in the frames and repairing the windows’ glazing.

“The students who are restoring these original windows, designed by early African American architect Albert Cassell, are restoring that legacy and helping to restore this to its former glory,” said Dale Green, an assistant professor of architecture at Morgan State and the lead faculty for historic preservation.

The building was constructed using proceeds from the sale of what was then called Morgan College to the state of Maryland. It is one of several buildings on Morgan’s campus designed by Cassell, a Towson native, and is an “iconic symbol” of Morgan’s founding, Green said. That took place in 1867, when a group of ministers convened in the basement of Sharp Street Church to establish the Centenary Biblical Institute.

This summer, the students in the program have restored log cabins at Grand Teton National Park in Wyoming and helped with masonry work at the Peale Center for Baltimore History and Architecture, which is billed as the oldest museum in the nation.

Last year’s cohort of Morgan State students, the first group to participate in the program, also made restorations at the Peale Center. And this fall, a new group of students is headed to Antigua and Barbuda, where they will restore the government house as part of a project administered by Queen Elizabeth and overseen by Prince Harry, Green said. Various groups of students and faculty will visit the site to help with restorations over the next five years, he said.

Tyriq Charleus, another rising senior in architecture, grew up in Washington. His experience there inspired him to pursue a career in the field.

Charleus scrapes lead paint off of a window frame at the Morgan State University Memorial Chapel Thursday as part of the Touching History program.
Charleus scrapes lead paint off of a window frame at the Morgan State University Memorial Chapel Thursday as part of the Touching History program.

“My community has always had dilapidated homes,” he said. “And now in D.C. they’re usually just getting torn down and replaced with new, shinier buildings. But the history that happened in that neighborhood is also being erased.”

He remembered his mother sharing stories from the city, adding that many of the locations that shaped her childhood have since disappeared at the hands of new development.

So Charleus got into historic preservation.

The Touching History program was developed by the Advisory Council on Historic Preservation, the National Park Service and the National Trust for Historic Preservation’s Hands-On Preservation Experience Crew.

David Vela, the National Park Service’s acting deputy director of operations, said the students are helping with a $12 billion maintenance backlog at the service.

Through their work at Morgan’s Memorial Chapel, and possibly other sites in the future, including the home of Frederick Douglass and buildings at other historically black colleges and universities, students that participate in the program will diversify the field too, he said.

“The folks that are involved in the preservation community don’t reflect the face of America today. Programs like this will help to change that,” Vela said.

More Growth, Consolidation, and M&A Expected for Hemp Industry in 2019

Author:  Chris Hudock                 Published     July 10, 2019

 

By William SumnerHemp Business Journal Contributor

From acquisitions to equity investments, the North American hemp industry has been awash in capital investment since the Farm Bill 2018 was federally passed in the United States last December. In the rush for first-mover advantages, entrepreneurs and investors have been scrambling for respective footholds in the nascent hemp market; even among those following the industry, it can be hard to keep up with all the activity.

The Hemp Business Journal has been closely monitoring such activity, and will soon publish more comprehensive data pertaining to the latest deals. By means of a thumbnail review, however, included here are the five biggest deals from the first half of the year.

Tilray Acquires Manitoba Harvest

Arguably the biggest deal in the hemp industry so far this year has been the acquisition of Manitoba Harvest by Tilray (NASDAQ: TLRY). With products in over 16,000 retail stores throughout North America, Manitoba Harvest is the world’s largest hemp food manufacturer. At a price of CAD $419 million (USD $320.3 million), the acquisition was made with a combination of cash payments and issuance of Tilray stock.

As a wholly owned subsidiary, Manitoba Harvest will continue its normal day-to-day operations while collaborating with Tilray in the development of new cannabidiol (CBD) wellness products and hemp-based food products. Using Manitoba Harvest’s expertise in CBD, and its existing distribution network, Tilray aims to accelerate its entry to the North American market.

SOL Global Purchases Majority Stake in Blühen Botanicals

Earlier this year, the international investment company SOL Global (SOL) announced its intentions to enter the hemp-CBD space with the formation of a subsidiary company called Heavenly Rx, Ltd. The overall goal of Heavenly Rx is to purchase controlling interests in hemp and CBD companies with proven track records of success, as well as to acquire brands proving more successful selling CBD-infused products.

To spur the growth of its new subsidiary, SOL purchased a 50.1% stake in Knoxville, Tenn.-based Blühen Botanicals, LLC (Blühen), for $30.6 million. Blühen is a hemp-biomass processing and extraction company offering a series of wellness boutique products including a full spectrum of hemp-extract tinctures, capsules, and creams. The company also owns a retail store in Knoxville, with plans to expand into Florida later this year. The proceeds of the deal will go towards expanding Blühen’s R&D team, and the company’s retail operations.

Mile High Labs Raises $65 Million

While some companies have been spending millions of dollars to acquire leading brands, other hemp companies are taking on significant debt to help expand operational capacities. In April, Mile High Labs managed to raise $65 million from MGG Capital in a five-year term loan leveraged to buy millions of pounds of hemp, making it one of the most substantial non-dilutive capital raises in the hemp industry.

Despite going the debt, Mile High Labs is not necessarily short on cash: Prior to the close of the fourth quarter of 2018, Mile High Labs raised $35 million in a Series-A funding round.

“Following the signing of the Farm Bill in late 2018, we started seeing speculators take out significant portions of the available hemp supply”, explained Mile High Labs CFO, Jon Hilley. “So, we acted decisively to secure the single largest source of high-quality biomass available,” he added. “It is quite literally a mountain of hemp – millions of pounds – and this funding guarantees we can continue to meet the increasing demand for CBD from our customers.”

Aurora Cannabis Acquires Hempco Food and Fiber Inc.

Much has been made about Aurora’s 2018 acquisition of the European company UAB Agropro. Yet, what slipped beneath the general industry’s radar was the company’s acquisition of Hempco Food and Fiber, Inc., for CAD $63.4 million (USD $48.5 million). One of the stated reasons behind the deal was Hempco’s solid track record for providing quality hemp-based foods with distribution channels through platforms like Amazon.com, Well.ca, and Metro, Inc. Of course, Aurora is uniquely positioned to help spur Hempco’s growth.

However, the most significant element was Hempco’s brand-new, 56,000-square-foot facility capable of processing 2.9 million kilograms of hemp annually. Aurora’s play looks to be using the facility to provide a steady supply of low-cost CBD as the company established itself in the hemp-CBD market.

Neptune Wellness Solutions Acquires SugarLeaf

Next to Tilray, Neptune Wellness Solutions’ acquisition of SugarLeaf Labs, LLC, and Forest Remedies, LLC (collectively, SugarLeaf), is the year’s biggest hemp deal yet. Under the agreement, Neptune pays SugarLeaf $18 million ($12 million in cash and $6 million in shares).

Provided that certain performance targets are met, Neptune will pay up to $132 million for SugarLeaf over the next three years, bringing the aggregate price to $150 million.

What will Neptune get out of the deal? In addition to SugarLeaf’s existing U.S.-based, hemp-extract supply chain, Neptune will gain a 24,000-square-foot processing facility capable of processing an annual 1.5 million kilograms of hemp. Projecting that the hemp-CBD market continues to heat up, the increased processing capacity will be vital to companies like Neptune that want to gain a leg up on the competition.

Retail Momentum Gathers for CBD Topicals While FDA Decides Its Direction

Author:  Chris Hudock     Published: July 17, 2019

By William SumnerHemp Business Journal Contributor

Hemp-derived CBD is all the rage right now, even as confusion and illegality abound. Prompted by the passage of the 2018 Farm Bill, which legalized hemp and hemp derivatives like CBD, investors and entrepreneurs have been scrambling to capitalize on the increasingly popular substance. The United States Food and Drug Administration (FDA) has tried its regulatory best to pump the breaks on the phenomenon by asserting its authority and cracking down on illicit sales of CBD supplements.

Standing on the sidelines are large-scale national retailers, many of which understand the potential profits but prefer not to pique the ire of federal authorities. While some retailers are staying out of the CBD craze completely, others are splitting the difference by offering topical CBD products, which are less likely to draw the legal wrath of the FDA.

In March, CVS and Walgreens became the first national retailers to announce that they were peddling CBD creams, patches, and sprays in their stores. CVS was selling them in eight states (Alabama, California, Colorado, Illinois, Indiana, Kentucky, Maryland, and Tennessee), while Walgreens marketed them in nine (Colorado, Kentucky, Illinois, Indiana, New Mexico, Oregon, South Carolina, Tennessee, and Vermont).

Following suit, Kroger — the nation’s largest grocery chain — announced last month its plans to sell CBD products in 945 stores in 17 U.S. states (Arizona, Arkansas, Colorado, Illinois, Indiana, Kansas, Kentucky, Michigan, Missouri, Nevada, Oregon, South Carolina, Tennessee, West Virginia, Washington, Wisconsin and Wyoming).

Both chains were deliberate in noting that their offerings would be limited to topicals, while stopping short of any foods, beverages, or dietary supplements as the FDA determines its policies for oversight and quality assurances.

For now, corporate retailers’ selling CBD-infused beauty and skin-care products brings far less legal jeopardy and exposure to liability, which explains their choices in stocking such types of products first. The FDA is tolerating topicals and oils containing CBD, so long as marketers refrain from making exaggerated health claims. Meantime, the FDA is considering any avenues by which companies could add CBD to food and dietary supplements. The agency closed its period for public comment this week, and Dr. Amy Abernethy, FDA’s principal deputy commissioner and acting CIO, pledged to provide guidance by the early fall.

Meantime, pharmacies and grocery stores are not the only retail players in the market. Last year, the cosmetics chain Sephora began involving itself with CBD topicals when it started selling a high-CBD body lotion made by the luxury brand Lord Jones through its online shop. Now the company is offering a variety of CBD lotions and body oils in 171 of its retail stores nationwide. Not to be left out, the luxury retailer Neiman Marcus is also offering CBD topicals as well.

The cannabis company Green Growth Brands has likewise made some major in-roads with national retailers. Recently, the company signed with Brookfield Properties and Simon Property Group, two of the largest mall owners in the U.S., to sell branded topical CBD products. The company signed similar deals with Designer Shoe Warehouse and American Eagle.

Perhaps the biggest adopter of CBD topicals yet is the organic grocery chain Whole Foods: With little fanfare, the company has begun selling CBD products throughout its stores, a practice made all the more significant given that Whole Foods isowned by Amazon.

Should the retail momentum behind such large national retailers be aided by favorable treatment from the FDA, CBD products will truly have made a game-changing impact beyond the countertop of the local gas station.


 

Metro’s Solar Plan Would Bring Power to 1,500 DC Homes

Author: UrbanTurf Staff         July 17, 2019

A proposed solar array for ward 8

The Washington Metropolitan Area Transit Authority (WMATA) has some solar plans in the works.

Metro announced on Wednesday a proposal to install solar panels at four Metro-owned facilities in the DC area. The energy created by the panels would be enough to power 1,500 homes.

“Metro is offering a 15-year solar ground lease to develop and operate solar photovoltaic (PV) power systems on surface and rooftop parking lots at Anacostia, Cheverly, Naylor Road and Southern Avenue stations,” a statement read.

The panels will be owned, operated and maintained by a third-party solar energy provider.

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Author: info@clearblugroup.com                   Published: July 15, 2019                                                                                          WEEKLY NEWSLETTER                             Week of July 15th, 2019

ClearBlu Capital Group is delighted to share our weekly newsletter providing articles on current housing and economic market conditions, business development, commercial real estate and key products offered to our wide variety of customers. Please enjoy and feel free to click here to schedule a meeting with our team if we can assist in expanding your business or real estate investment endeavors.
Trump Signs New Law To Protect Innocent Small Business Owners From IRS Seizures – Nick Sibilla
3 Fintech Innovations That Could End Financial Hurdles For Small Businesses – Brock Blake
Small businesses flourish with SBIC-backed loans – Kevin Robinson-Avila
Uncertainty Climbs Among America’s Small-Business Owners – Nancy Moran and Ryan Haar
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SOLAR BUSINESS TIPS How to Get HOA Solar Approval: Tips for Success

Author: Sara Carbone Published:  June 19th, 2019 blog.aurorasolar.com

HOA Approval Cover Image-1

In some areas, Homeowners Associations (HOAs) can present significant barriers to homeowners’ ability to install solar.

Before Texas enacted protective solar access laws that limited what restrictions HOAs could place on solar installations in their neighborhoods, HOAs meant a lot of frustration. Speaking to the New York Times in 2009 when he was chief executive of Houston-based residential solar company Standard Renewable Energy,John Berger (now CEO of Sunnova Corporation), said HOA prohibitions had cost SRE over $1 million in business.

In Missouri, a state without policies protecting from HOA solar restrictions, there are a number of cases in court where HOAs are butting heads with homeowners that install solar.

As a solar contractor, the extent to which HOAs impact your business is dependent on your state’s laws and the HOA bylaws in the neighborhoods you target. However, there are a number of strategies you can employ to help ensure HOA approval for your customers’ PV solar systems, regardless of where you do business.

In this article, we discuss techniques compiled from interviews with solar contractors with extensive experience working with HOAs and online research to help ensure successful outcomes on projects in HOA communities—and guide your prospective customer through the process as well.

See how Aurora Solar software can help you close more sales in a free consultation.

How an HOA Can Impact Your Solar Business

HOAs are neighborhood organizations that create and enforce rules for houses or condominiums in established communities. Solar Power World states that “a major directive of the HOA is neighborhood uniformity and/or a high standard of appearance for each property.” HOAs’ concerns, and resulting rules, about solar installations tend to relate to how PV panels will affect the look of neighborhoods or property values.

These rules can impact a homeowner’s efforts to go solar. A significant proportion of American homeowners interact with an HOA: over 351,000 HOAs in the U.S.regulate about 40 million households or 53% of owner-occupied households. Therefore, there is a good chance that your prospect needs to work with one. However, about half of U.S.states have laws preventing HOAs from denying solar for aesthetic reasons, so the impact on your business is partially dependent on where you operate.

Getting Approval from an HOA: The Steps

It is helpful to understand the typical process for getting approval for a solar installation from an HOA so that you are better able to guide your customer through it. Usually, a customer requests an application from their HOA or gives the contractor permission to do so. While there are some customers who choose to fill out the application and send it in themselves, others prefer that the contractor do this.

Mike Busby, Co-Founder & President of Victory Solar, a leading residential and commercial installer in Texas, spoke with Aurora about his company’s extensive experience working with HOAs. He states that his company does all the HOA paperwork on the homeowner’s behalf, only getting the homeowner involved if they have to.

Bobby Custard, Solar Consultant for Pur Solar & Electrical, an Arizona-based contractor with over 40 years of electrical contracting experience, also shared his insights about interacting with HOAs. He says that after Pur Solar has given the customer everything they need to review and sign, the company notifies the HOA when they begin the permitting process. They send the HOA a copy of the plans, the proposal, and images of what the project will look like.

If the application is approved by the HOA, you can move forward with the installation. If not, you should understand the applicable laws in your state in case you are able to help your customer appeal the decision.

See how Aurora helps solar companies around the world grow their business

Strategies That Can Expedite the HOA Application Process

There are a number of best practices to keep in mind that may help make the process of getting HOA solar approval as easy as possible and increase the likelihood of a successful outcome.

Know Your State’s Laws

“Solar access” laws have been adopted by many states including California, Utah, and Florida that protect homeowners’ rights during the HOA solar approval process. Given that you may be the one educating your customers about their rights in this respect, it is important to know your state’s existing laws, whether provide protections from HOA solar restrictions, and what forms they take.

Solar access laws prevent HOAs from prohibiting solar panel installations or having contracts that restrict homeowners from installing them. However, HOAs can usually make certain requests about a system, as long as they don’t make the proposed solar system less effective or more expensive. Often HOAs are allowed to place certain restrictions on systems, like retaining the right to influence design elements of a rooftop solar array, such as requiring that all electrical wiring be placed out of sight.

California has had The Solar Rights Act since 1978, which has helped encourage the growth of solar in the state and is the basis for many other states’ protective laws. It includes protections that limit HOA ability to pass prohibitive laws but allows an HOA to impose “reasonable restrictions” on solar energy systems. These restrictions are currently limited to ones that don’t increase the cost of a proposed system by more than $1,000 or decrease its potential performance by more than 10%.

Under this law, a homeowner does have some responsibility to their neighborswhen they seek to go solar. For example, in multifamily dwellings with common roof areas an applicant must notify each owner in the building about a proposal. Additionally, they might also be required to have homeowner liability coverage and provide proof of this to their HOA annually.

Arizona has solar access laws that are similar to those of California but with less stringency and specificity about what an HOA can and cannot do. For example, the “reasonableness” of HOA solar installation restrictions is decided on a case-by-case in the courts.

However, Custard explains that protective Arizona laws have made the HOA approval process very easy for Pur Solar & Electrical. 60-80% of Pur Solar’s installations involve HOAs, and they have never been rejected. He states that even when his company installed several systems near upscale private golf courses, they were able to install the panels facing the fairway for one and facing the putting green for another.

The actual provisions of solar access laws vary widely by state and comprehensive information about state and local rules is available at the Database of State Incentives for Renewables and Efficiency (DSIRE).

Be Your Customer’s Guide Through the HOA Approval Process

Functioning as your prospect’s expert on how to navigate their HOA’s solar stipulations and state laws from the beginning of the sales process can go a long way towards winning the deal. Find out the HOA’s rules about PV panel installation early, particularly any rules they may have regarding design and placement. These can impact aspects of the installation process, such as system price, even if your state has solar access laws.

Gauge your prospect’s level of familiarity with this topic and make sure they are aware of their HOA’s rules as well as their state’s laws. “Many homeowners are not aware of their rights,” says Custard.

He states that a homeowner may have just bought their house or might be new to the area; “they may have just gotten their HOA rule book, and they’re trying to figure out what direction they can put their car or what their yard has to look like. So they’re a little bit overwhelmed and gun shy.” Victory Solar’s Busby adds that while some people know how the approval process works or are even on their HOA board, others are completely unaware of how it works.

Custard explains that prospects are often concerned about what their HOA will say regarding installing solar. Therefore, his team makes sure to show the homeowner information about Arizona’s HOA solar laws via emails or printed articles. As a result “the prospect feels much more comfortable moving forward knowing that if they put down a deposit and get the ball rolling with solar, the HOA isn’t going to be throwing speed bumps in the path.”

Have a Streamlined HOA Application Process

It helps to show your prospects that you and your team are aware of how to achieve an expedited approval process. For example, there are ways you canreassure a prospect’s HOA and address their concerns. This can be done by demonstrating how PV panels can increase property values and providing examples of successful installations you have done for similar neighborhoods and home types.

Busby notes that Victory Solar has a streamlined process in place to ensure HOA solar approval given that they deal with HOAs on about 90% of their projects. He told us, “we probably submit too much paperwork but have a 100% approval rate. The paperwork has got to be very detailed and ironclad. An HOA can rarely oppose that.”

Busby also asserts that an important part of a smooth HOA solar approval process is having an operations team that gets paperwork together efficiently. He states, “you have to make the right hires within the operations group of your organization because they’re just as important as your roof crew. If they’re fast on the paperwork approval it flows down through every part of the operations side. As a result, we’re very quick. We install systems within 30 to 40 days while the industry average is 150 days.”

Be Prepared to be Creative and Flexible

HOA rules may require that you adjust your approach and think outside the box, even in a state with solar access laws. Victory Solar was able to secure approval for a client with a Spanish tile roof whose HOA had already rejected ground mount system proposals from three different contractors. They did this by suggesting a ballasted ground mount system with a black mesh fence screen to obscure the system from view. It included removing the grass and putting in white rock for a flat roof commercial system on the ground and ensuring the system was below the fence line.

Busby also describes one customer in an affluent neighborhood where the HOA wanted the solar system to be installed out of view. Noticing that the customer had an old unused concrete tennis court and, Victory suggested the customer repurpose the court as a solar pad for a ballasted ground mount solar system.

You may also consider adjusting the equipment you use. Custard talks about the benefits of using solid black panels: “HOAs very much prefer a solid black panel with a black screen instead of a white paper backing with a silver frame. When we use these kinds of panels they are more receptive to the installation and are less likely to come back with any questions, even in places that have really specific, stringent rules.”

Educate Solar Prospects and HOAs

In an effort to improve the HOA approval process and help ensure solar’s growth, you may look for opportunities to provide educational information to both prospects and HOAs. Laura Ann Arnold of the Indiana Distributed Energy Alliance, a state that currently has a host of solar related HOA challenges, says that “the solar industry as a whole needs to stay vigilant on HOA solar issues and work to educate the public as more people want to go solar.”

This may mean providing homeowners with information about HOA prohibitions and restrictions regarding solar in order to encourage them to ask questions before they buy a home. It may also mean seeking ways to educate HOA boards about removing outdated strictures or easing overly prohibitive rules. Arnold describes how some boards don’t understand the impact of certain rules like limiting solar to the back of the house or away from the street when it faces north. “There is a lack of understanding about the technology and the economics,” she declares.

Employing best practices when working with a customer and their Homeowner’s Association can help you offer the best customer service and increase the likelihood of closing the sale. A key part of this can be coming from a position of cooperation and consensus, which can lead to an expedited approval process. As Custard explains, “as long as you’re civil with an HOA so that you don’t end up on their radar as a ‘problem person,’ they’re much more likely to help instead of hinder the process.”

Sanders and Ocasio-Cortez move to declare climate crisis official emergency

Exclusive: Democrats to introduce resolution in House on Tuesday in recognition of extreme threat from global heating

Sanders with Alexandria Ocasio-Cortez, Ilhan Omar and Pramila Jayapal. Data shows nations are not on track to limit the dangerous heating of the planet significantly enough.

Sanders with Alexandria Ocasio-Cortez, Ilhan Omar and Pramila Jayapal. Data shows nations are not on track to limit the dangerous heating of the planet significantly enough. Photograph: Saul Loeb/AFP/Getty Images

A group of US lawmakers including the 2020 Democratic presidential contender Bernie Sanders are proposing to declare the climate crisis an official emergency – a significant recognition of the threat taken after considerable pressure from environment groups.

Alexandria Ocasio-Cortez, the Democratic congresswoman from New York, and Earl Blumenauer, a Democratic congressman from Oregon, plan to introduce the same resolution in the House on Tuesday, their offices confirmed.

A Sanders spokesperson said: “President Trump has routinely declared phoney national emergencies to advance his deeply unpopular agenda, like selling Saudi Arabia bombs that Congress had blocked.

“On the existential threat of climate change, Trump insists on calling it a hoax. Senator Sanders is proud to partner with his House colleagues to challenge this absurdity and have Congress declare what we all know: we are facing a climate emergency that requires a massive and immediate federal mobilization.”

Climate activists have been calling for the declaration, as data shows nations are not on track to limit the dangerous heating of the planet significantly enough. The UN has warned the world is experiencing one climate disaster every week. A new analysis from the economic firm Rhodium Group today finds the US might achieve less than half of the percentage of pollution reductions it promised other countries in an international agreement.

Senate Legislative CounselDraft Copy of KAT19097
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7/8/20192:38 PM
Title: Expressing the sense of Congress that there is a climate emergency which demands a
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massive-scale mobilization to halt, reverse, and address its consequences and causes.
234
Whereas 2015, 2016, 2017, and 2018 were the four hottest years on record and the 20 warmest
5
years on record have occurred within the past 22 years;
6
Whereas global atmospheric concentrations of the primary heat-trapping gas, or greenhouse gas,
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carbon dioxide—
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(1) have increased by 40 percent since preindustrial times, from 280
9
 parts per million to 415 parts per million, primarily due to human
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activities, including burning fossil fuels and deforestation;
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(2) are rising at a rate of 2 to 3 parts per million annually; and
12
(3) must be reduced to no more than 350 parts per million, and likely
13
lower, “if humanity wishes to preserve a planet similar to that on which
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civilization developed and to which life on Earth is adapted,” according to
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former National Aeronautics and Space Administration climatologist, Dr.
16
James Hansen;
17
Whereas global atmospheric concentrations of other greenhouse gases, including methane,
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nitrous oxide, and hydrofluorocarbons, have also increased substantially since preindustrial
19
times, primarily due to human activities, including burning fossil fuels;
20
Whereas current climate science and real-world observations of climate change impacts, ocean
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warming and acidification, floods, droughts, wildfires, and extreme weather demonstrate
22
that a global rise in temperatures of 1 degree Celsius above preindustrial levels is already
23
having dangerous impacts on human populations and the environment;
24
Whereas the 2018 National Climate Assessment found that climate change due to global
25
warming has caused, and is expected to cause additional, substantial interference with and
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growing losses to infrastructure, property, industry, recreation, natural resources,
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agricultural systems, human health and safety, and quality of life in the United States;
28
Whereas the National Oceanic and Atmospheric Administration has determined that climate
29
change is already increasing the frequency of extreme weather and other climate-related
30
disasters, including drought, wildfire, and storms that include precipitation;
31
Whereas climate-related natural disasters have increased exponentially over the past decade,
32
costing the United States more than double the long-term average during the period of 2014
33
through 2018, with total costs of natural disasters during that period of approximately $100
34
 billion per year;
35
Whereas the Centers for Disease Control and Prevention have found wide-ranging, acute, and
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fatal public health consequences from climate change that impact communities across the
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United States;
38
Whereas the National Climate and Health Assessment of the United States Global Change
39
Research Program identified climate change as a significant threat to the health of the
40
 people of the United States, leading to increased—
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Sixteen countries and hundreds of local governments, including New York City last month, have declared a climate emergency already, according to the advocacy group the Climate Mobilization. The activist group Extinction Rebellion has said the declaration is a crucial first step in addressing the crisis.

Blumenauer’s office said he decided to draft the resolution after Donald Trump declared an emergency at the US border with Mexico so he could pursue building a wall between the two countries.

In Congress, Democrats in control of the House might have enough support for the resolution, but Republicans in the majority in the Senate are not likely to approve.

The resolution says: “The global warming caused by human activities, which increase emissions of greenhouse gases, has resulted in a climate emergency” that “severely and urgently impacts the economic and social well-being, health and safety, and national security of the United States”.

It then goes on to say that Congress “demands a national, social, industrial, and economic mobilization of the resources and labor of the United States at a massive-scale.”

Trump and his administration have questioned the science showing that humans are causing the climate crisis. They have downplayed the risks of rising temperatures and gutted government efforts to limit the heat-trapping pollution from power plants, cars and other sources.

Despite that record, Trump touted the US as an environmental leader in aspeech on Monday at the White House.

Even if the resolution passed and was signed by the president, it would not force any action on climate change. But advocates say similar efforts in Canada and the United Kingdom have served as a leverage point, highlighting the hypocrisy between the government position that the situation is an emergency and individual decisions that would exacerbate the problem.

Several of the Democrats running for president have rolled out partial or full blueprints for cutting emissions. Nearly all have said it is a top issue. Sanders has a history of prioritizing the climate crisis, and has previously suggested specific policy options, but he has yet to release his own proposal.

As the crisis escalates…

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BRIEF US renewable energy transition to move faster than anticipated by 2022: FERC report

Dive Brief:

  • By June 2022, the pace of U.S. renewables growth is going to surpass fossil fuel growth by a significantly greater margin than what FERC had anticipated as recently as April, according to the commission’s May 2019 Energy Infrastructure Update, released Friday.
  • The renewable energy-focused SUN DAY Campaign said new renewable energy capacity would grow more than 10% by 2022 while fossil fuel capacity would only increase about 1%, compared to the April forecast of a 5% net increase. The fossil fuel dip will be largely driven by the more than 4.6 GW of coal forecast for retirement, according to FERC’s May update.
  • While SUN DAY’s analysis asserts that FERC “drastically revised” its 3-year forecast, “the generation additions/retirements section of the monthly report is NOT a forecast or prediction of Commission expectations,” FERC media relations director Mary O’Driscoll told Utility Dive via email. The estimates come from outside sources: Velocity Suite, ABB Inc. and The C Three Group.

Dive Insight:

Looking between FERC’s April and May infrastructure updates, renewables appear to be displacing fossil fuel and nuclear capacity at a faster pace. The May Energy Infrastructure Update included an additional 3 GW of coal capacity expected for retirement.

“The revisions in FERC’s latest three-year projections underscore the dramatic changes taking place in the nation’s electrical generating mix,” Ken Bossong, executive director of the SUN DAY Campaign, said in a statement.

“The FERC 3-year forecast of U.S. electrical generating mix is an affirmation that the clean energy transition is underway,” World Resources Institute (WRI) Senior Associate Devashree Saha told Utility Dive via email.

Based on the data aggregated from independent analysts, “there will be effectively no growth in the generating capacity of fossil fuels while renewables will see significant growth in capacity,” Saha said.

While natural gas has become more economic and is expected to grow, more than 10 GW of natural gas generation are expected to be retired in the next three years. Groups like WRI are tracking regional trends to install more natural gas or to pass on gas projects based on state and local support for clean energy.

In a web post published on Monday, Saha highlighted the growing number of state rejections of utility plans to replace coal generation with natural gas amid falling renewable energy prices and climate concerns.

Credit: FERC

The SUN DAY Campaign’s analysis calculated net generation capacity changes by looking at unit retirements and “highly probable” additions. The net new renewable generation capacity will be nearly 27 GW for wind and more than 16 GW for utility-scale solar by June 2022,  according to the May 2019 Energy Infrastructure Update.

“These are fairly conservative numbers with groups like Wood Mackenzie estimating more renewable energy growth,” Saha said.

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Solar + wind + storage developers ‘gearing up’ as hybrid projects edge to market

A “wave” of new projects is coming to use wind, solar, and battery storage in ways that will stabilize grids, increase efficiencies and lower power costs.

Renewables are shedding their individual identities as wind and solar become clean energy MWhs.

Though no full-scale hybrid projects co-locating both resources and energy storage have been built in the U.S. and few are online around the world, the U.S. renewables industries are taking on barriers such as interconnection, dispatch and compensation challenges, according to speakers at the 2019 American Wind Energy Association’s Windpower conference.

“It’s like the storm is brewing. It hasn’t coalesced yet, but hybrid projects are absolutely the future.”

Rhonda Peters

Consulting Principal, InterTran Energy

For the first time, the conference featured multiple sessions on the trials and opportunities of these hybrid renewables projects. In line with the ambitious resource partnerships among renewable energy groups, next year’s conference will be rebranded Cleanpower 2020.

Developers of hybrid projects “are gearing up,” InterTran Energy Consulting Principal Rhonda Peters, who has long worked on regulatory obstacles to hybrid projects, told Utility Dive. “It’s like the storm is brewing. It hasn’t coalesced yet, but hybrid projects are absolutely the future.”

California Senate passes $21B wildfire fund legislation, as Newsom pushes for final vote Friday

Author: July 9, 2019

Dive Brief:

  • The California Senate on Monday passed AB 1054, legislation Gov. Gavin Newsom, D, is rapidly pushing to help utilities cover wildfire damage liabilities through a new $21 billion liquidity fund.
  • The legislation was advanced by the Senate Energy, Utilities and Communications Committee and the Senate Appropriations Committee, before being approved 31-7 by the full chamber. Newsom is pressing for a final vote in the Assemby on Friday.
  • Some customer advocates say they have concerns that the legislation weakens the standards to hold utilities accountable. On the other side, Pacific Gas & Electric (PG&E) declared bankruptcy earlier this year in part due to wildfire liabilities, and the utility’s creditors have supported the legislation as a much-needed solution.

Dive Insight:

PG&E’s creditors are pressing for quick passage of AB 1054, while advocacy group Consumer Watchdog has warned that an accelerated schedule leaves utility customers vulnerable.

A Friday vote would leave no time for amendments to what is “very complex legislation where details have a lot of devils,” Consumer Watchdog President and Chairman of the Board Jamie Court wrote in a Monday blog post.

The proposal calls for utility ratepayers to contribute $10.5 billion, with shareholders contributing the same amount. Customers would pay into the fund through a $2.50 monthly charge on bills that has been in place since the state’s energy crisis, and had been slated to roll off.

But Consumer Watchdog warned the legislation’s details give the state’s Public Utilities Commission “power to bond endlessly” without approval from lawmaker, if customers are forced to bear “recoverable” costs.

“The problem is the legislature is weakening the standard by which ratepayers can hold utilities accountable for not being prudent managers and starting fires,” Court wrote. “So ratepayers will pay in more instances than the past.”

PG&E’s official creditors committee, however, warned that taking too much time could be costly.

“Delays in legislation to address California’s wildfire liability crises will result in damaging consequences for wildfire victims, ratepayers, and businesses across California,” the group said in a statement. “Furthermore, these delays will affect the bankruptcy process, and likely result in delayed payments to victims, service and energy providers, and lenders.”

Several trade associations representing California’s wind, solar, geothermal, and bioenergy industries, have also said the legislation is necessary to “stabilize and hold accountable the state’s largest utilities.

“California’s energy future is dependent upon getting to a financially stable market, as AB 1054 intends,” Independent Energy Producers CEO Jan Smutny-Jones said in a statement.