Edison Energy Renewables Market Update | Q2 2020 by Trio

Renewables Market Update Q2 2020

INSIDE THIS REPORT: ›› Renewable Energy Marketplace ›› U.S. PPA Price Trends ›› PJM MOPR Ruling ›› COVID-19 Impacts on U.S. Energy Markets ›› European Market Overview ›› European Policy Update ›› Alberta Market Overview ›› COVID-19: Strengthening the Business Case for Renewables ›› COVID-19 Impacts on the Renewable Industry ›› Case Study: Saint-Gobain ›› Electric Vehicle (EV) Optimization ›› U.S. Regulated Market Snapshot ›› Energy Bills We're Watching in 2020

Renewable Energy Marketplace Robust Inventory of Projects Despite Development Delays Edison Energy continued to see robust project inventory across several markets in the U.S., with solar projects making up a larger share of the project inventory than wind. The vast majority of available projects are anticipated to come online by the end of 2022 or the end of 2023. Some projects, however, may

see delays in development timelines, as widespread stay-at-home orders have the potential to slow progress on key development milestones, including completion of interconnection studies and permitting approvals (see COVID-19 section, page 7 for more details).

Figure 1. Edison Energyâ&#x20AC;&#x2122;s U.S. Renewable Energy Marketplace â&#x20AC;&#x201C; Recently Available Utility-Scale Projects

In PJM and ERCOT, projects continue to come on and off the market quickly, as there has been significant buyer interest from corporations, energy retailers, banks, and utilities. Buyers are best positioned to transact in these markets when they are ready to move swiftly, have team members who are well educated on power purchase agreements, and have aligned internal stakeholders on the procurement strategy. In MISO and SPP, more solar projects are on the market today than a year ago. In MISO, the inventory of solar projects has grown across the entire market. In SPP, solar projects are concentrated in the southern region, particularly in Texas and Oklahoma. Edison has seen less demand for renewable projects in these markets, as compared to PJM and ERCOT, so buyers generally have more time to act before these projects go off the market.

Edison Energy Renewables Market Update

Q2 2020

U.S. PPA Price Trends Prices Remain Flat to Slightly Higher Compared to Q1 Market Update Figure 2. Indicative PPA Prices by Market and Technology

PPA prices shown above reflect flat, hub-settled, unit contingent offers received since April 2019, but some offers shown may no longer be on the market.

Table 1. Q1 PPA Pricing: Best 10% of Available Pricing ($/MWh)* Map

Solar

Wind

SPP

$27.62

$15.00

ERCOT

$23.35

$16.24

MISO

$28.71

$24.65

PJM, West

$30.75

$31.69

PJM, East

$32.73

Table 2. Historical monthly, around-the-clock (ATC), wholesale market prices from April 2019 to March 2020 for representative hubs in a given market (SPP – North and South Hub; ERCOT – North, South, Houston, and West Zones; MISO – Arkansas, Illinois, Indiana, Michigan, and Minnesota Hubs; PJM – AEP-Dayton, Dominion, Eastern, N. Illinois, and Western Hubs) Power Market

SPP

ERCOT

MISO

PJM

ATC Minimum

$12.82

$14.56

$14.79

$16.34

ATC Average

$19.06

$34.28

$22.81

$23.44

ATC Maximum

$25.94

$132.13

$29.71

$35.79

*Table pricing does not include ERCOT West Hub

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U.S. PPA Price Trends Prices Remain Flat to Slightly Higher Compared to Q1 Market Update Across markets, the median PPA prices are on par or slightly more expensive than Edison’s Q1 2020 report. Edison Energy has not seen an increase in PPA pricing due to COVID-19 specifically, as developers hope that the pandemic will have an impact only in the short term, whereas the lead time on these projects is two to three years before commercial operation. However,

Edison continues to track potential impacts related to COVID-19. Implications for PPA pricing and project availability may change if the pandemic extends for a significant period of time (see more on page 7). When evaluating year to year changes in PPA pricing, there has been a divergence between trends in wind and solar, as explored in the market-specific sections below.

PJM: In PJM, the best 10% (p10) of wind and solar PPA prices were higher than in Edison’s Q1 2020 report, driven by the production tax credit (PTC) step down and regulatory uncertainty related to the minimum offer price rule (MOPR). For wind projects, p10 prices are 0.5% higher than Edison’s Q1 2020 report and 20% higher than a year ago. This increase is largely driven by projects currently on the market being eligible for partial value of the PTC rather than the full value, which was available in the first quarter of last year. For solar projects, p10 prices are flat from Edison’s Q1 2020 report and 5% higher than a year ago. While solar projects can secure the full value of the investment tax credit (ITC) if online by the end of 2023, the uncertainty caused by a regulatory proceeding has put upward pressure on pricing. The minimum price offer rule (MOPR), being debated between FERC and PJM, impacts whether solar projects can expect to receive revenue from the capacity market, an assumption that influences PPA prices. In the last few months, FERC and PJM have put forward an order and compliance filing, respectively, that allow potential options for renewable projects to seek capacity revenue. While this has the potential to be good news for corporate buyers, the pathways forward are nuanced, and the rules are not yet set in stone. Developers are continuing to iterate on pricing, with the most competitive prices likely to be accompanied by contingencies on projects’ ability to earn capacity revenue (see page 5 for more PJM MOPR updates).

MISO: In MISO, the p10 PPA price for solar projects increased 2% from Edison’s Q1 2020 report but were flat as compared to a year ago. Not all MISO solar projects are created equal though. Southern MISO solar projects, by leveraging a stronger solar resource, are pricing at a 6% to 16% discount to northern MISO solar projects. P10 wind PPA pricing has increased 13% from Edison’s Q1 2020 report and over 30% from a year ago. A large portion of this increase is likely due to the step down in PTC value that wind projects coming online in 2021 and later can capture.

ERCOT: ERCOT remains the most popular market for renewable energy buyers, and solar remains the predominant technology. However, buyers are not expected to see sub-$20 or very low $20s PPA prices going forward, as it appears solar pricing hit the bottom of the market in 2019 and is now rebounding. Project developers concerned with a “race to the bottom” in corporate procurement are seeing other contracting opportunities, with utilities, energy retailers, and banks through hedges, that will pay a higher price. The p10 PPA price for ERCOT solar projects has held at approximately $23/MWh with only a 2% increase from Edison’s Q1 2020 report. This is potentially signaling stabilizing market prices for solar in the region. For wind, ERCOT projects have not seen as drastic a price increase in p10 PPA prices as other markets. The p10 PPA price for ERCOT wind increased 4% from Edison’s Q1 2020 report and 5% from where it was a year ago.

SPP: As seen in other markets, the PTC step down put upward pressure on SPP wind PPA prices, but to a lesser extent than in PJM and MISO. Wind p10 PPA prices increased by 12% from a year ago but are flat from Edison’s Q1 2020 report. There was a very small inventory of solar projects marketed in SPP a year ago. Solar p10 PPA prices were up 1% from Edison’s Q1 2020 report.

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Q2 2020

PJM MOPR Ruling Compliance Filing & Recent FERC Order Bode Well for Buyers On December 19, 2019, the Federal Energy Regulatory Commission (FERC) ordered changes to PJM’s capacity market rules that will subject all new state-subsidized resources to a “minimum offer price rule” (MOPR). Under the order, all new state-subsidized resources will be subject to the MOPR, which will create an artificial price floor for these resources in future capacity auctions. While this price floor is beneficial for traditional generators previously impacted by price suppression, there is significant risk that new wind and solar projects will be barred from earning revenues in PJM’s capacity market. FERC’s order has created uncertainty surrounding the capacity revenue that new projects can expect to receive, and developers have reacted differently to

this uncertainty, which is reflected in recent PPA pricing changes. Wind PPAs are minimally impacted by this order because wind projects generally assume little to no capacity revenue. However, virtually all solar offers in PJM assume some capacity revenue given their onpeak generation profile, so the order is putting upward pressure on solar PPA rates as developers reassess their capacity value assumptions. On March 18, 2020, PJM filed a compliance filing outlining its implementation of FERC’s 2019 Order and clarified some outstanding issues. On April 16, 2020, FERC denied rehearing requests from numerous stakeholders on their MOPR Order, allowing stakeholders to file lawsuits at the U.S. Court of Appeals for the District of Columbia Circuit. On the next page we share how the renewable PPA market is reacting to these recent filings.

DEVELOPERS ARE GAINING CONFIDENCE WITH VOLUNTARY RENEWABLE PURCHASES IN PJM, DESPITE ONGOING REGULATORY UNCERTAINTY. In FERC’s April 2019 Order denying petitions for rehearing, FERC clarified that “purely voluntary transactions for RECs are not considered State Subsidies,” and therefore do not trigger the MOPR. FERC explicitly highlighted a pathway for exemption for these voluntary renewable

transactions, called the Competitive Exemption (described on the following page). With this positive news, developers are eager to see the final ruling from FERC, which could occur in mid-June at the earliest.

Figure 3. PJM Project Offers Received in the Past Six Months

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PJM MOPR Ruling Compliance Filing & Recent FERC Order Bode Well for Buyers DEVELOPERS ARE STILL WEIGHING OPTIONS TO SEEK EXEMPTION FROM THE MOPR, WHICH MAY LEAD TO REVISED PPA PRICING IN THE NEAR-TERM. Under PJM's compliance filing, there are three pathways for renewable projects to be granted exemption from the MOPR:

Existing Renewables: Projects with signed interconnection agreements are exempt from the MOPR, regardless of if they are receiving state subsidies, and this exemption will last the life of the project. There is a finite pool of projects that meet this exemption.

Competitive Exemption: Projects certify that the new resource will forgo any state subsidies may be exempt from the MOPR. PJM’s tracking system, GATs, will be modified to “tag” the project’s RECs to ensure they cannot be retired into a state renewable portfolio standard compliance account or be transferred to another REC tracking system.

The certification is binding for the entire project life, which can create significant long-term regulatory risk. Projects that elect this exemption and later take a state subsidy are banned from participating in the capacity market for the next 20 years (called the asset life ban) and lose all capacity revenue going forward. Additionally, a renewable resource taking this exemption cannot partition the project to sell some of its RECs to voluntary buyers and some to a compliance buyer. Given that many of these renewable projects are too large for a single offtaker, demand for voluntary buyers may increase to contend with this requirement. Based on conversations with developers exploring the competitive exemption pathway, the asset life ban risk is raising PPA prices by ~$0.50/MWh. This price increase is due to developers assuming no capacity revenue to the project in the years after the initial voluntary buyer PPA.

Resource-Specific Exemption (also called Unit-Specific Exemption): Projects taking state subsidies can apply for this exemption by justifying a unit-specific MOPR floor price based on the specific attributes of the project, such as actual project costs, asset life, etc. This exemption would allow projects to bid a lower offer floor price in the capacity auction, giving them a greater chance of clearing the auction. Once a project clears the first auction with a unit-specific price, it will clear future auctions as an existing resource, guaranteeing capacity revenue for the remainder of the project. This pathway has a higher burden of proof to justify the unit-specific MOPR floor price but lower long-term regulatory risk. Many developers are exploring this option given the regulatory risk under the competitive exemption and ability to monetize the project RECs. At the time of this publication, developers were revisiting their financial models to provide updated PPA pricing to Edison Energy.

Edison Energy can help clients evaluate PJM projects and assist with contracting around this regulatory uncertainty in PJM. If you’d like to learn more about FERC’s Order on PJM MOPR, please reach out to Shannon.Weigel@EdisonEnergy.com for our policy brief.

Edison Energy Renewables Market Update

Q2 2020

COVID-19 Impacts on U.S. Energy Markets What the Pandemic Means for Power Prices & PPAs During the past month, U.S. energy markets have seen massive upheaval with unprecedented, rapid changes to traditional fundamental price movers. The oil industry has been severely impacted by the COVID-19 pandemic. Prices have collapsed due to reduced global economic output. What exactly does this mean for natural gas and electricity prices? Edisonâ&#x20AC;&#x2122;s commodity experts explain the link between oil and gas below and explore the subsequent impacts on electricity pricing and renewable PPA performance for the rest of 2020 and beyond. For several years, the primary economic driver for domestic producers to drill has been the price of crude oil. A vast majority of wells that have targeted crude oil have also produced natural gas out of the same well. This natural gas production, from crude oil wells, is a by-product called "associated gas". Until recently, US producers have been willing to invest and drill because of the profitability of crude; they were willing to take a loss on the byproduct of the oil well, which accounted for over 50% of the growth in natural gas production in 2019. However, well economics based on the price of crude have been turned upside down during the past month with the one-two punch of international demand destruction and short-term oversupply caused by COVID-19. It is estimated that 20% of worldwide demand for oil has evaporated since the beginning of the pandemic.

Producers have reacted quickly to the drop in crude pricing by immediately cutting back on the number of active rigs, resulting in a decrease of 190 total rigs over the past month. For perspective, the total US rig count one year ago was at 1,022 and is now measured at 602. Equating current rig count to future production is not an exact science and several unrelated variables go into the magnitude and timing of the actual impact to production. Most analysts forecast that it typically takes 6-12 months for a major drop in rig counts to cause a decline in actual production. As of today, May 2020 NYMEX gas forward prices are near all-time lows. As shown in figure 4 below, there is a huge discount in the near months with a big price premium starting this winter and remaining through calendar year 2021 before coming back to where it was three months ago for the summer of 2022.

$/MMBtu

Figure 4. NYMEX Gas Futures Pricing: Three Months Ago vs. Current

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COVID-19 Impacts on U.S. Energy Markets What the Pandemic Means for Power Prices & PPAs In the U.S., natural gas is a primary fuel for electricity generation, causing the two markets to be closely linked in many regions. As can be seen in the graph below, prices at PJM Western Hub have dropped from May through the summer, but as can be seen in November and December, those winter months are carrying more of a premium. These pricing trends reflect the short-term oversupply of natural gas and potential future shortage due to the major drop in rig count occurring today. Figure 5. PJM Western Hub Around-the-Clock Electricity Prices

HOW WILL THESE CHANGES IN THE POWER MARKET IMPACT PPA PERFORMANCE FOR OPER ATING PROJECTS? PPAs typically see negative or moderately positive settlements in the shoulder months of the year when electricity demand is low and supply is more than adequate. Figure 6 on the following page shows actual and expected monthly settlements from a sample ERCOT wind project settling at ERCOT South Hub. The solid blue line shows actual settlements since January 2019. The forecasted settlements are shown in the dotted lines. For illustrative purposes, it is assumed that the project will produce the same generation and shape for the next two years as in 2019. In March 2019, this sample project saw a moderately positive financial settlement. However, March 2020 had a moderately

Edison Energy Renewables Market Update

negative settlement. Given the current market conditions, it is anticipated that as clients review their settlements for March and April, they will see that the lower power prices from the past months result in a less favorable settlement than usual at this time of the year. The graph shows how the lower power forwards come through in the forecasted summer settlements. The orange dotted line shows Edisonâ&#x20AC;&#x2122;s view from the outset of this year -- the settlements that were anticipated, based on where power was trading in January 2020. The dark blue dotted line shows Edisonâ&#x20AC;&#x2122;s current view, based on where power is currently trading.

Q2 2020

COVID-19 Impacts on U.S. Energy Markets What the Pandemic Means for Power Prices & PPAs Focusing in on the remainder of 2020 – the downward shift of power price forwards has driven lower forecasted PPA settlements. This is demonstrated by the dark blue dotted line falling below the orange. The most significant drop is in the summer months for this ERCOT project. Last year, ERCOT saw significant price spikes during hot summer days, with Around-The-Clock (ATC) ERCOT South Hub prices averaging $130/MWh. Because wind projects, like the sample project, generate more during off-peak times, this project captured a weighted average price of $96/MWh. As of January, monthly ATC forwards were trading at ~$100/MWh for August, and now are at ~$80/MWh. Despite this downward shift, the summer settlement for this sample project is still forecasted to be strongly positive.

Moving to 2021 and beyond, power forwards from November 2020 onwards have gained strength since the pandemic began. On the graph, the anticipated monthly settlements for 2021 and 2022 are looking about the same or better than they did at the beginning of this year, with the blue dotted line either in line with or above the orange dotted line, starting around January 2021 and continuing through the end of 2022. This signifies that the impacts from COVID-19 are anticipated to be temporary and will have little to no impact to projects operating in 2021 or 2022.

Figure 6. PPA Settlement: Actual + Forecasted (2019 - 2022) Monthly Settlement for 100 MW Texas Wind PPA

KEY THINGS TO KEEP IN MIND:

A PPA is a long-term instrument – most of these agreements are for 12 years or longer. This period of particularly low power prices is expected to be temporary; buyers are in this for the long game.

For many buyers, a PPA is a hedge to their utility expenditure – while low wholesale power prices are making for unfavorable PPA settlements right now, they should also be bringing down retail power costs. It’s important to keep both sides of this equation in mind.

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European Market Overview Insights & Opportunities The European market for corporate renewable energy PPAs is newer than the U.S. but expanding quickly. As subsidy regimes evolve, and renewable energy suppliers seek to guarantee revenue from sources other than government auctions, corporations have an opportunity to pursue renewables in new markets. Recently, Edison has been active in soliciting pricing in established markets such as Spain, Italy, and the United Kingdom as well as some emerging markets, namely Poland and Finland. This map below illustrates a snapshot of available opportunities and highlights how Europe is increasingly becoming an opportunity for corporate energy buyers to source renewable energy.

with strong market fundamentals. This makes it a good market for a financial renewable energy PPA. However, government auctions guarantee revenue for 15 years. A corporate buyer looking at Poland should be prepared to look at longer term deals (15 or more years) to secure a competitive contract. Otherwise, suppliers will opt for the subsidy. Where subsidies are strong, suppliers do not need to contract with a corporate buyer to get a deal financed. In countries where subsidies are declining or ending, corporate buyers play a more prominent role in guaranteeing project revenue. This should be a main consideration for any corporation evaluating a PPA in the region.

It is important to note that the European market is not anchored to financial, or commonly referred to as virtual, deals like in North America – historically physical delivery has been the primary PPA structure. Financial contracts for differences are starting to emerge and grow in popularity, particularly among companies reporting under U.S. GAAP accounting standards but even for companies reporting under IFRS accounting standards. Since there are more operational renewable energy projects in the region when compared to the U.S. market, suppliers can offer structures like monthly baseload power or even pay-as-consumed at close to the cost of grid power. Corporate buyers have the option to pair new-build renewables with operational assets to achieve their renewable energy goals and offset facilityspecific load around-the-clock.

Aggregating load in a single market is doable, but not nearly as common as in the United States. A corporation can seek scale by procuring a larger virtual or financial PPA in a market like Spain, where there is a strong pipeline of large projects that compare favorably to the wholesale market. However, this is less common amongst European companies since many see crossing national borders for environmental attribute credits (EACs) or guarantees of origin (GOs) as slightly problematic even if that approach is acceptable by the standards of CDP. Of course, aggregating load in a single market also diminishes the hedge efficacy of one of these contracts as markets are not strongly correlated. Luckily, with a large pool of operational projects across the continent, it is possible to find a variety of structures in most markets to meet in-market load. Projects in some markets also tend to be smaller, in the 10-30 MW range, which can match up well to localized load.

Corporate buyers must compete with government auctions, or subsidies, in many European markets. A good example of this is Poland. Poland has a coal-intensive grid

FINL AND

MW Available: 25.0 MW Contract structure: Pay-as-Generated Average PPA Price: €30.85

MW Available: 125.0 MW Contract structure: Pay-as-Generated Average PPA Price: €46.75

SPAIN

MW Available: 719.0 MW Contract structure: Pay-as-Generated Average PPA Price: €38.16

POL AND

MW Available: 81.5 MW Contract structure: Pay-as-Generated Average PPA Price: €50.00

ITALY

MW Available: 320.0 MW Contract structure: Pay-as-Generated Average PPA Price: €49.33

10 Edison Energy Renewables Market Update

Q2 2020

European Policy Update EU Plans to Delay Adoption of Green New Deal Amid COVID-19 Pandemic Announced in December 2019, Europe’s Green New Deal will invest €1 trillion over the next ten years to achieve carbon neutrality by 2050. A draft document released on April 16, 2020 highlights some initiatives that will be placed on hold due to the COVID-19 outbreak. These delayed initiatives include improvements to sustainable forest management, protection of biodiversity, reforms to farming, customer recycling education and plans to help the bloc adapt to the impact of climate change. However, the European Commission is still set to raise the current 2030 greenhouse gas emission target in September 2020. For reference, the 2030 climate framework includes EU-wide targets of at least 40% cuts in greenhouse gas emissions (from 1990 levels) and at least 32% share for renewable energy.

Despite Calls from 180 Politicians to Use Green Investments to Spur the Post COVID-19 Economy, the European Commission Seeks to Delay Some Green Initiatives

In response to the COVID-19 outbreak, some European governments, such as Germany, France and Ireland, are extending renewable auction timelines and project deadlines. For renewable developers in Europe, government contracts are generally preferred over corporate offtake, despite the growing demand for corporate PPAs. While renewable market activity slows down given current energy market conditions, we anticipate the value of government contracts in some countries will grow as developers and investors seek lower contracting and counterparty risks. This may be a headwind for corporate procurement of renewables in some countries in Europe; however, we still anticipate a growing trajectory of transactions for large and creditworthy buyers.

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Alberta Market Overview Opportunity Emerges for Corporate PPAs in Canada Alberta is a burgeoning market for corporate renewable energy PPAs. Alberta’s power market, AESO, is an energy-only market with a minimum price floor of $0. The AESO territory is very carbon-intensive but boasts a strong wind resource and a growing pipeline of solar projects. Alberta also has a carbon offset program, TIER, that requires large power users to offset carbon emissions tied to their operations. Smaller power users can still participate in the PPA market by taking renewable energy and RECs. Overall, the market offers strong long-term fundamentals for renewable energy PPAs, but the opportunity is tempered by the short-term shock of COVID-19 on regional supply and demand conditions. The market for TIER carbon offsets drives the market for bundled RECs. A project can generate Green-e RECs or carbon offsets under the TIER program, but not both. TIER carbon offsets are more valuable than Green-e RECs, so that increases the price of a bundled product in AESO. For customers that are not required to participate in the TIER program, this can make a bundled PPA expensive. This is particularly true for smaller buyers who do not procure the project’s full capacity and are not required to participate in TIER. They are effectively buying the project REC at the value of a carbon offset plus a premium. The result is a REC price well above the broker market for RECs. Electing a REC swap deal can help a smaller buyer capture value while also fulfilling environmental goals.

There is a wide gap (as high as $12 CAD) between solar and wind pricing. Low solar resource in the province increases the average PPA price, but higher coincidence with on-peak pricing can help offset the gap. Wind is still well-positioned to capture value during tight supply conditions, which typically occur during the winter, but it misses out on summer value. In terms of supply, it is a buyers’ market, but the shortterm economics can dissuade some risk averse buyers. While energy futures were strong through the end of 2019, the COVID-19 shock has dropped 2020 and 2021 energy futures by as much as 80%. Summers have been especially impacted as traders anticipate lagging demand – this is particularly challenging for short-term solar economics. There is also a worry that Alberta will take longer to rebound from an economic downturn as it did in the wake of the ’08-’09 financial crisis. Nonetheless, there remains a healthy pipeline of 2021 and 2022 projects that should begin operation after, of near the end, of the economic downturn, which will have stronger forecasted economics than are seen in the near-term forwards.

Figure 8. Recently Marketed PPA Prices

PPA Price ($CAD/MWh)

Figure 7. Average PPA Price by Technology and Environmental Attribute Product

PPA prices shown above are flat and escalating (2%) unitcontingent offers received since January 2020, but some offers shown may no longer be on the market.

1 2 Edison Energy Renewables Market Update

Q2 2020

COVID-19: Strengthening the Business Case for Renewables Global Pandemic Highlights Link between Pollution and Human Health With nearly one in three people under mobility restrictions across the globe, the unprecedented COVID-19 pandemic has resulted in a dramatic decrease in carbon emissions – a drop larger than what was called for by the Paris Agreement. The impact of our collective global inaction can be seen in real-time as studies directly link pollution to a 15% higher fatality rate for COVID-19 . The business case has never been stronger, or the impacts of inaction more clear, than what we are seeing play out today. In some areas that were densely populated just weeks ago, scientists and researchers have noticed an almost 60% decrease in nitrogen-dioxide and carbon-dioxide emissions. For many cities, this is a direct result of the significant decrease in daily commuter traffic. However, the more significant decreases are linked to the shutdown of coal-fired power plants and industrial facilities, which produce nearly 300 billion tons of CO2 each year and account for about 26 percent of global greenhouse gas emissions (GHG), nearly double the emissions produced by global transportation. Unfortunately, this GHG respite will be temporary if business recovers to the status quo. As factories start to reopen and commuters get back in their cars,

carbon emissions will rebound just as quickly as they fell. However, the short-term benefits of this significant increase in air quality may put pressure on governments and companies to continue to ramp up their efforts to reduce their carbon emissions, not only to combat climate change, but to improve the health of their communities while continuing to battle a virus that affects the respiratory system. Cai Xue’en, delegate of the National People’s Congress and adviser to China’s supreme court on COVID-19 stated, “We paid people’s lives for the lesson, and we should never do it again… I think environmental protection will rank even higher for both the central and local governments.”1 Additionally, Virginia Governor Ralph Northam signed the Virginia Clean Economy Act into law on April 12th, which set new state requirements for energy efficiency and will officially shut down the states remaining coal-fired power plants. These government efforts will continue, and we expect more corporate momentum on clean energy and GHG reduction coming out of the crisis. As more corporations shift towards low carbon solutions, such as electrification and renewable energy procurement, this will not only have lasting long-term impacts on our climate, but also more immediate benefits, as we’ve seen from the devastating effect air pollution can have on one’s respiratory system in the wake of a rampant respiratory virus.

Figure 9. U.S. Offsite Renewable Energy Power Purchases by Sector

Akshat Rathi, "Air Pollution’s Insidious Link to the Pandemic: Green Insight," Bloomberg Law (April 14, 2020), https://news.bloomberglaw.com/environment-and-energy/air-pollutions-insidious-link-to-the-pandemic-green-insight

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COVID-19 Impacts on the Renewable Industry What To Know as a Current or Prospective Buyer

The global pandemic has created unprecedented upheaval to energy markets and renewable project development. Edison has been tracking the key impacts to projects in development and construction. We are assisting clients in adjusting strategies and contracts to address these changes.

IMPACT ON PROJECTS IN CONSTRUCTION ›› Supply Chain: As global supply chains experience disruptions due to COVID-19, renewable developers may see delays in delivery of essential components necessary to complete their renewable projects on schedule. Edison has spoken with some developers who have received notices from manufacturers that there will be delays in delivering components, though many are still determining the exact impacts to their overall project schedules.

To combat these challenges brought on by COVID-19, the U.S. renewable industry is advocating for three immediate relief measures:

›› Workforce: Each project site is subject to local rules regarding travel and essential business. So far, most Edison client projects have been able to proceed with construction, but some are in areas where construction is not allowed to proceed at this time. One has issued a Force Majeure notice and three others have indicated they may need to do so.

2. A direct pay provision equal to 100% of the PTC or ITC value to reduce the risk from a potential downturn in the availability of tax equity; and

›› Permitting: Government offices are not open and not able to perform on-site inspections or to issue construction permits. This will cause delays for projects in the permitting stage of the development process. There is uncertainty on when these offices will open and how delayed they will be in resuming activities. ›› Tax Incentive Qualification: This year is particularly critical for wind projects because the value of the federal production tax credit (PTC) will step down at the end of the year. Wind projects must achieve commercial operation by December 31st in order to qualify for the full value of the PTC. In some instances, supply chain delays, combined with the lack of labor resulting from extended stay-at-home orders, will threaten renewable projects’ ability to meet the U.S. federal tax incentive deadlines.

14 Edison Energy Renewables Market Update

An extension of the “start of construction” and “safe harbor” deadlines to ensure that renewable projects can qualify for the full value of the federal production tax credit (PTC) and investment tax credit (ITC);

3. The formation of a direct pay tax credit for standalone energy storage. Despite earlier reports that energy infrastructure measures will be included in the fourth stimulus package, the House and Senate agreed that the fourth relief package will be similar to the recently-enacted CARES Act. Congressional leaders are also focused on negotiating a smaller piece of legislation to provide support for small businesses. Without a near-term vehicle for relief, the renewable industry is seeking clarity from the U.S. Treasury Department on whether COVID-19 related delays will be considered an “excusable disruption” under the ITC and PTC rules to maintain qualification for the tax credits. The renewable energy industry will continue to lobby Congress for legislative support while concurrently requesting guidance at the U.S. Treasury Department. Through Edison's industry association memberships and relationships across the industry, Edison is getting the most up-to-date information to share with clients on these issues and how they could affect their PPAs.

Q2 2020

COVID-19 Impacts on the Renewable Industry What to Know as a Current or Prospective Buyer IMPACT ON PROJECTS IN DEVELOPMENT Many of Edison’s clients are either in PPA negotiations with projects, have a short list of projects under consideration, or are gearing up to run RFPs to identify a renewable energy project that is the right fit for their company’s needs. Most of these projects would be slated to come online between 2022 and 2023 and the large majority are solar projects. Edison has spoken with developers – ranging from the largest players to smaller firms – over the past several weeks, and they all indicate that their work is continuing as normal. These projects are facing short-term delays to project development including: ›› On-site environmental and cultural resource studies are limited by travel restrictions

›› Because COVID-19 may impact the development process in a number of ways, parties should reassess their obligations and protections under a PPA. ›› During PPA negotiations, Buyers and Sellers are negotiating the outcomes if a Force Majeure does occur, including how long pre-COD delay damages are excused, and potentially contract termination for an event that renders performance impossible for a sustained period.

›› Permitting, which is often subject to hearings from a board of county commissioners, or subject to state approval, is delayed or slowed ›› Interconnection study timelines have slowed due to remote working limitations When it comes to project finance in a down economy, investors are expected to be even more discerning: ›› The pool of tax equity investors is expected to shrink, and those remaining will potentially seek higher returns, which could put upward pressure on PPA pricing.

Projects slated to come online in 2022 and 2023 are still actively seeking offtake and continuing with commercial negotiations:

The world, including the renewable energy industry, looks different today than it did a few months ago. While delays and development issues will arise, developers continue to market projects and corporations continue to find transactions that will meet their long-term energy and sustainability goals. Robust analysis and detailed attention to commercial terms will ensure buyers are well-positioned to continue procuring in this market.

›› Debt financing may be harder to secure as investors may be more cautious with investments during this time. This is another factor that could make project finance more expensive for developers, and again, put upward pressure on PPA pricing.

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Case Study Edison Energy Advises Saint-Gobain on Largest Renewable Energy Deal in Company History Edison is pleased to have helped Saint-Gobain, one of the world’s largest building materials companies and manufacturer of innovative material solutions, significantly reduce its greenhouse gas (GHG) emissions by consulting on a 12-year virtual Power Purchase Agreement (vPPA) – the largest renewable energy deal signed in Saint-Gobain’s 354-year history. The deal positions Saint-Gobain among an elite group of companies that have committed to supporting a more sustainable future. Blooming Grove Wind Farm located in McLean County, Illinois, is currently in construction and is slated for operation in late 2020. Saint-Gobain has contracted 120 megawatts (MW) of the 250 MW wind farm, developed by Invenergy. Saint-Gobain’s long term commitment will provide the revenue certainty needed to develop and construct this new-build renewable energy asset. This transaction will reduce the company’s overall carbon footprint in the U.S. by 21%, making significant progress towards the company’s 2050 net-zero carbon goal. Energy from the Blooming Grove Wind farm will reduce the carbon intensity of the PJM grid, and Saint“This makes North America a significant Gobain will continue to purchase electricity from local utility grids to power its U.S. facilities. contributor in our global network

towards helping meet Saint-Gobain’s “This makes North America a significant contributor in our global network towards sustainability goals, and puts us in helping meet Saint-Gobain’s sustainability goals, the welcome company of some of and puts us in the welcome company of some of the largest, most forward-thinking organizations the largest, most forward-thinking in the world,” said Mark Rayfield, President and organizations in the world." CEO of Saint-Gobain North America and CEO of family company CertainTeed. “The tenacity — MARK RAYFIELD, PRESIDENT & CEO and ingenuity that was needed to make this deal OF SAINT-GOBAIN NORTH AMERICA possible is a testament to how Saint-Gobain trusts and empowers employees across the company to push boundaries each and every day to realize our vision and lead us into a sustainable future.” Edison began working with Saint-Gobain in 2018 to find a renewable energy project that could meet its sustainability goals. Edison worked closely with Saint-Gobain’s energy and sustainability teams as well as other key stakeholders to guide them through the complexities of renewable energy procurement and to establish the project profile criteria that best suited the company. After careful consideration and robust load profiling analysis, Edison supported SaintGobain in going out to market in PJM, ERCOT, and SPP. Throughout the competitive solicitation Edison received bids from more than 25 developers and over 50 projects across these electrical grids’ regions. Edison advised Saint-Gobain through the bid down-selection process, eliminating bids that didn’t conform to the company’s project requirements, or fell outside of the competitive range after the first round of economic analysis. Edison performed deep due diligence on the remaining projects to develop a shortlist of top projects based on project development status, permitting, generation, and developer experience. Edison then utilized our proprietary analytics platform to perform advanced cash flow analysis on the top bids, evaluating how each project related to Saint-Gobain’s energy usage. Ultimately Saint-Gobain chose Invenergy’s Blooming Grove Wind project for its development track record, project maturity, and risk-adjusted economics.

REDUCING US CARBON FOOTPRINT BY 20%

120 MW ILLINOIS WIND 16 Edison Energy Renewables Market Update

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Case Study Edison Energy Advises Saint-Gobain on Largest Renewable Energy Deal in Company History Edison helped to facilitate a vPPA that limits the company’s exposure to price volatility within the energy market, while also complying with international financial standards. “Agreements like this are often difficult for international companies operating in the U.S. to adopt, but working with experts was a key piece in bringing this deal to fruition. Being able to mitigate Saint-Gobain’s financial risk while maximizing returns for renewable energy developers and increasing opportunities for new clean energy is a win-win-win,” said Bob Panaro, Chief Operations Officer at Saint-Gobain North America, who served as an executive sponsor of the initiative. “This deal places us among a select group of pioneers bringing renewables to the forefront of what we hope will become a much more saturated market of companies adopting similar clean energy strategies.” “As a large consumer of energy across the U.S., including in PJM’s grid, we recognize the tremendous positive impact we can make on addressing the climate crisis. This project, and the enthusiasm with which our leadership has supported it, makes me so incredibly proud to work for Saint-Gobain,” said Ryan Spies, Director of Sustainability, Energy & Stewardship, Saint-Gobain North America. This renewable energy investment demonstrates that Saint-Gobain is a global industry leader on sustainability and renewable energy. Companies like Saint-Gobain are paving the way for other global manufacturing companies to enter the corporate PPA space in the U.S., which has historically been occupied largely by the tech industry. Edison is proud to have supported Saint-Gobain on this engagement and continues to find ways to reduce risk for our clients.

“As a large consumer of energy across the U.S., including in PJM’s grid, we recognize the tremendous positive impact we can make on addressing the climate crisis. This project, and the enthusiasm with which our leadership has supported it, makes me so incredibly proud to work for Saint-Gobain." — RYAN SPIES, DIRECTOR OF SUSTAINABILITY, ENERGY & STEWARDSHIP, SAINT-GOBAIN NORTH AMERICA

For more information on Edison Energy's Renewables & Analytics Advisory Services please contact Christen.Blum@EdisonEnergy.com. For more information on Saint-Gobain North America’s recent announcement, click here.

About Saint-Gobain: Saint-Gobain designs, manufactures and distributes materials and solutions which are key ingredients in the wellbeing of each of us and the future of all. They can be found everywhere in our living places and our daily life: in buildings, transportation, infrastructure and in many industrial applications. They provide comfort, performance and safety while addressing the challenges of sustainable construction, resource efficiency and climate change. Pierre-André de Chalendar, Chairman and Chief Executive Officer of Saint-Gobain, announced the company’s commitment to reach net-zero carbon emission by 2050 during the UN Climate Action Summit of September 2019.

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Electric Vehicle (EV) Optimization A New Approach to Quantifying EV Charging Behavior Understanding load impact and expected energy spend from electric vehicle charging is key for corporations as they consider fleet electrification. How do uncertainties in tariff structure, vehicle composition, and charging requirements affect expected economics of EV adoption? Where are the opportunities to reduce total cost of ownership through rightsizing EV charging equipment or optimizing charging behavior? Edison Energyâ&#x20AC;&#x2122;s EV load optimization offerings are built on its market-leading energy analytics platform and probabilistic approach to load forecasting. The platform optimizes load and procurement activities based on strategic, renewable, and financial objectives. This foundation provides the basis for probabilistic EV load analysis and a thorough approach to optimizing fleet electrification plans.

EV infrastructure providers often use static inputs for client operations and then calculate a solution to meet charging needs. Our approach recognizes the inherent uncertainty in variables that drive load impact from fleet electrification. We leverage market projections (e.g. utility tariff structure and growth, forward energy projections, weather), EV equipment specifications (e.g. chargers, vehicle type), and facility data (e.g. card swipes, vehicle miles, dwell time) to reflect possible driving and charging behavior over time. Figure 10 displays an example of one EV charging simulation under uncertain vehicle types, building arrival times, and driving behavior. We then run thousands of unconstrained simulations to understand the full range of load outcomes from fleet charging. These results are aggregated into percentiles to understand expected (e.g. median) and total range (e.g. 1st â&#x20AC;&#x201C; 99th percentile) of possible load each forwardlooking hour, day, month, and year (See Figure 11).

Figure 10. Single Simulation of Impact of Variable Fleet Schedule and Composition on Load

Once charging needs are understood, we develop a plan to optimize schedules and charging stations in a manner that meets the requirements of the client. This process includes rigorous sensitivity analysis to inform opportunities for EV charging schedule improvement. We then evaluate economic viability of pairing onsite solar generation with energy storage to match

18 Edison Energy Renewables Market Update

generation with demand. Results of these analyses can be represented based on net cash flow, dollarsper-vehicle-mile, or dollars-per-megawatt-hour, depending on the commercial structure of the proposed solution. Figure 12 provides an example of onsite energy storage and its potential for peak shaving under a timeof-use tariff.

Q2 2020

Electric Vehicle (EV) Optimization A New Approach to Quantifying EV Charging Behavior Figure 11. Aggregated Load Impact from Five Thousand Simulations of Vehicle Charging at One Client Facility

The Edison Energy method is designed to help clients optimize for the EV solution (e.g., number and location of chargers, onsite solar, energy storage) that minimizes their expected costs of service. We model all these resources together, along with the broader electricity

grid, recognizing the inherent interdependence of these technologies. This fundamentals-based perspective empowers our clients to de-risk their fleet electrification plans.

Figure 12. Demand Reduction and Rate Arbitrage Require Predictable Peaks or Rate Structures or Require Dispatch Flexibility

If you would like to learn more about distributed generation & electric vehicles, please contact Charley.Hildt@EdisonEnergy.com

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U.S. Regulated Market Snapshot Georgia Power’s New Green Tariff Georgia Power’s Customer Renewable Supply Procurement (CRSP) Program Offers Customers the Opportunity to Participate in the Creation of New Renewable Generation in the State. In the southeastern U.S., regulatory and market barriers limit renewable energy opportunities for corporate buyers. We are continuously evaluating new utility programs, such as green tariffs, to support our customers in expanding their geographic options for renewables procurement .

PROGR AM OVERVIEW In July 2019, Georgia Power received approval from the Georgia Public Service Commission to procure 1,000 MW of new renewables for large customers under its new CRSP Program. Through the program, participating corporate buyers purchase a monthly subscription and receive hourly credits on their bill based on the production of the renewable project. Georgia Power retires RECs on behalf of participating customers. The CRSP program will consist of two requests for proposals (RFPs) for power purchase agreements (PPAs) for new build renewable facilities, with the first RFP occurring in 2020 and the second in 2021. Across the two RFPs, the CRSP program will be targeting supply for two subscriber groups: ›› 600 MW for existing customers with aggregate peak demand greater than 3 MW ›› 400 MW for new or existing customers with load additions greater than 25 MW

Georgia Power will administer the RFPs, including negotiations and project selection on the customers’ behalf. The intent is to select facilities with Commercial Operation Dates between 2022 and 2024; there is a minimum term length for participation of 10 years.

PROGR AM CHARGES AND CREDITS The primary cost of the program to the customer is the selected PPA supply cost on a per MWh basis, which will be determined by the outcome of the RFPs. This cost will be passed through by Georgia Power along with the following program charges: a $5,000 non-refundable participation fee required at the time of subscription application, an 8.5% addition to the selected PPA supply cost, and a $0.25/MWh administrative fee. In return, the customer will receive an hourly credit per MWh that represents the utility’s hourly operating costs of incremental generation (also referred to as Southern Company’s Pool Interchange Rate) and this value will fluctuate hourly based on factors such as weather, electricity demand, generation resource availability, fuel/commodity prices, and other system variables.

Figure 13. Georgia Power’s Customer Renewable Supply Procurement Program

Source: Georgia Power’s Customer Renewable Supply Procurement Program webinar on April 21, 2020

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Q2 2020

U.S. Regulated Market Snapshot Georgia Power’s New Green Tariff PROGR AM ANALYSIS The CRSP program follows a model similar to Georgia Power’s prior Renewable Energy Development Initiative (C&I REDI) program, in that the costs or savings the customer will see are dependent on the relationship between the fixed PPA cost from the RFP and Georgia Power’s avoided cost of generation, both of which will be unknown at the time of initial program enrollment. Over the past several years, Georgia Power has seen a steady decline in their avoided cost of solar projections, primarily due to sustained low natural gas prices and renewable build out in the region. This decline has meant that PPA prices that may have projected positive returns in the C&I REDI program previously are no longer expected to result in positive returns. Our analysis shows that PPA prices would need to reduce 20 to 30% for the median return to project positively.

Based on our analysis, we anticipate that this program will not offer attractive cost savings. However, companies with sustainability goals looking to address their Georgia load may want to capitalize on this nearterm opportunity given the overall lack of renewable procurement opportunities in the state. Existing utility customers can submit their application, called a Notice of Intent, to the utility from now until December 4, 2020. Edison Energy can assist our clients in evaluating whether this program is a good fit for your renewable strategy and if pursuing, assist in navigating the enrollment process.

$/MWh

Figure 14. Georgia Power's Annual Solar Avoided Cost Projections

PPA Subscription Price ($/MWh)

C&I REDI - Avoided Solar Cost Projections

CRSP - Avoided Solar Cost Projections

$30

$22,596,248

$6,249,425

$34

$13,345,503

($3,001,320)

$38

$4,094,757

($12,252,066)

If you would like to learn more about utility programs in regulated energy markets, please contact Shannon.Weigel@EdisonEnergy.com.

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Energy Bills We're Watching in 2020 Governments Gear up to Increase Clean Energy Goals As of April 15, 2020, at least 23 U.S. legislatures (Alabama, Alaska, Arizona, California, Colorado, Connecticut, Delaware, Georgia, Guam, Hawaii, Illinois, Iowa, Kansas, Louisiana, Minnesota, Mississippi, Nebraska, New Hampshire, New York, Rhode Island, South Carolina, Tennessee and Virgin Islands) have postponed their legislative session due to COVID-19. Edison Energy is continuing to track legislative developments despite this disruption in energy policymaking. If the coronavirus pandemic worsens, we anticipate meaningful delays in governmental action to transition to a clean energy economy, though this could be remedied by economic stimulus packages that include decarbonization measures.

VIRGINIA GOVERNOR SIGNS VIRGINIA CLEAN ECONOMY ACT On April 12, 2020, Governor Ralph Northam signed the Virginia Clean Economy Act (VCEA), setting the state on a path towards 100% clean energy by 2045. The inventory of available offsite renewable projects in Virginia is limited by high data center and energy retailer appetite for renewable energy as well as developer challenges associated with PJM interconnection and permitting. Compounded by the regulatory uncertainty of PJM’s capacity auction, PPA pricing for offsite renewables has increased from ~$30/MWh to $40/MWh in Virginia, resulting in negative expected cash flows in PPAs. While the VCEA law doesn’t immediately solve the problems associated with corporate offsite renewable procurement in the state, it does pave the way for onsite solar development and behind-the-meter battery storage for companies. If you are looking to reduce greenhouse gas Scope 1 and 2 emissions in Virginia, Edison Energy can help position your company to participate in these future programs.

NEW YORK PASSES LAW TO CREATE THE U.S.’S FIRST OFFICE OF RENEWABLE ENERGY SITING On April 3, 2020, Governor Andrew Cuomo signed into law the state’s annual budget, which included the “Accelerated Renewable Energy Growth and Community Benefit Act” that replaced the state’s Article 10 process in favor of a new streamlined process under Article 23 of the Economic Development Law. This new law will reduce the permitting process for large-scale renewables in NY from about three years under Article 10 to a mandatory oneyear period, allowing renewable projects to be constructed faster and more economically. A newly formed Office of Renewable Energy Permitting will be tasked with reviewing and approving projects over 25 MW within the mandated one-year period. If a final siting permit decision is not made by that deadline, the project will be automatically approved. We estimate it will take approximately one year for the new office to act on new renewable permitting applications. New York has one of the most ambitious renewable targets in the country, seeking 70% renewable electricity by 2030.

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JAPAN’S COVID-19 STIMULUS PACK AGE INCLUDES ONSITE SOLAR FUNDING Adoption of renewable power by corporations in Japan has historically been low due to Japan’s long-term Feed-in Tariff Program favoring direct sale of renewable power to utilities at a fixed price vs. market price contracts to private entities. However, The House of Representatives and House of Councillors passed a 2020 supplementary budget on April 30th, 2020. A portion of the budget that funds emergency measures to support the economy during the pandemic will now provide financial incentives for private businesses looking to install onsite solar PPAs and batteries. As proposed, the government will provide ¥40,00060,000/kW for solar PPAs for businesses and ¥20,000/kWh or ¥30,000/kW for battery storage installations.

GET IN TOUCH Christen Blum Vice President, Renewables & Analytics Advisory +1-857-317-6021 Christen.Blum@EdisonEnergy.com

Edison Energy provides independent, expert advice and solutions to help large corporate, industrial, and institutional clients better understand and navigate the choices and risks of managing energy. We enable decision-makers in organizations to deliver on their strategic, financial and sustainability goals by addressing the three biggest challenges in energy today: cost, carbon, and complex choices. Edison Energy has advised global companies, universities and cities on more than 4,600 MW of renewable energy projects across North America and Europe. For more information about Edison Energy visit www.edisonenergy.com. Edison Energy, LLC and its affiliate, Altenex, LLC, are registered as Commodity Trading Advisors (CTA) with the Commodity Future Trading Commission (CFTC) and additional information on Edison Energy and Altenex is available at https://www.nfa.futures.org.

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