Benefits
Microgrids allow for new levels of resilience (in light of emerging threats to global power grids ranging from extreme weather events, earthquakes, and wildfires to terrorist threats) and reliability to reduce distribution outages and provide for higher power quality.

While high utility rates in certain isolated load pockets have incented development, new technologies have lowered capital costs significantly. Microgrids can help organize mixed asset fleets of DER (distributed energy resources) at the distribution network level. Microgrid deployments include: 1) biomass, 2) CHP (combined heat and power), 3) diesel, 4) battery storage, 5) fuel cells, 6) hydro, 7) solar PV, and 8) wind. Controls for the microgrid can be managed through storage and communication packages internal to the microgrid. Microgrids can increase reliability for site hosts but also provide flexibility to distribution system operators as components can bid directly into wholesale markets if appropriately configured.

Global/US Footprint & Growth
Based on a mid-2019 report, the microgrid market (both planned and installed) identified 4475 projects totaling close to 27GW (26,965 MW) of capacity worldwide. A companion study projected growth in spending from $8.1 Billion currently to $40 Billion in 2028, sporting a CAGR (compound annual growth rate) of 21.4%. US microgrid capacity was nearly 9GW (8.879 MW) in 2019. Globally, on a customer segment basis, remote microgrids and commercial and industrial (C&I) represent nearly 70% of installations.

Asia is the largest overall market, North America is the top market for grid-tied capacity, and Latin America is the fastest growing market, notably because of Puerto Rico’s power restoration efforts post-hurricane Maria in 2017.

In the US, most microgrid projects are custom configured and largely limited to public facilities like schools, hospitals, and military bases, although chip makers represent a solid exception. Many are dependent on fossil fuels and not renewable energy sources.

Overall Market Assessment
The global market for microgrids continues to grow, but is not yet a smooth ride to widespread viability. Although microgrid technologies have dropped in cost, and controls functionality has improved, regulatory barriers and long project development cycles continue to frustrate efforts to move the market fully into the mainstream. 

Market Segments
Segments are generally divided into six major areas: 1) campus/institutional, 2) commercial & industrial, 3) community, 4) remote, 5) utility distribution, and 6) military.

US Utility View—Thumbs Up, Down, or Sideways?
While an optimist or equipment seller can say the power sector is moving from a centralized system to a distributed system, it can be said, at least for incumbent utilities, that the train hasn’t exactly left the station. A broad view would say utilities essentially have three choices, either to obstruct, facilitate, or engage and implement.

On the plus side, utilities see benefit from microgrids in several ways: 1) supporting distribution operations vulnerable to stability issues stemming from high renewable energy penetration, 2) providing a non-wires alternative to areas of growing electricity demand, and 3) deferring or supporting capital upgrade projects. In addition, there are revenue opportunities if they can fully or partially own microgrids.

On the negative side, utilities view on-site generation, battery storage, and microgrids as disruptive technologies. They see declining revenues from decreased sales, conflicts over where microgrid operators can string lines and connect to the distribution system, and worries about reliability when
customers separate themselves from the grid.

In 2019, according to the Edison Electric Institute, 50% of all microgrids had some type of utility involvement compared to 10% several years prior. This defies the perception that utilities are often slow to innovate and resistant to disruptive change.

A lingering question remains, ‘should microgrids and distributed energy resources be coordinated by a central entity, akin to the way ISOs/RTOs coordinate the bulk power market?’ Unfortunately, a lack of market rules and a disjointed regulatory environment are primary factors at play.

In the end, utilities will have to adopt to a changing landscape of fewer entities to pay necessary monies for utility upgrades and expansions. At last count, utilities are collectively investing $100 billion to upgrade their networks. It is therefore incumbent upon State regulators to decide how to share those costs based on the premise that the grid is an essential public resource.

Electric vehicle charging infrastructure comprises components which are installed for private BEV (Battery Electric Vehicles) and PHEV (Plug-in Hybrid Electric Vehicles).  Components include chargers, management of charging, electric utility support for charging, and compliance with local and federal standards/codes. The infrastructure charging market is typically delineated by charger type (slow/fast), by connector protocol (CHAdeMo, CCS, others), by application (commercial/residential), and by charging method (AC/DC).

By application, commercial adoption is expected to gain majority market share by 2026. The segment is expected to grow at a CAGR of 41.0% over the forecast period.

The market size for the globalresidential electric vehicle charging infrastructure segment is anticipated to increase from USD 324.7 million in 2016 to USD 22,430.5 million by 2026, growing at a CAGR of 40.6% from 2018 to 2026.

CHAdeMO is expected to account for the largest market share among the fast charging standards available throughout the forecast period. However, CCS (Combined Charging System/AC and DC) is anticipated to be the fastest growing service segment, with an estimated CAGR of 46.9% over the forecast period, primarily due to strong adoption expected in the western European region. The Asia Pacific (AP) region is expected to stay the predominant region over the forecast period. This is driven by the Japanese auto manufacturers’ focus on developing electric cars. Also, China registered more than 300,000 new electric vehicles (EV) in 2016 and further Chinese government focus has placed a priority on creating favorable circumstances for various EV stakeholders, including investors. The AP region is anticipated to grow at a CAGR 41.0% over the forecast period.

The growth of the commercial and private electric vehicle market is attributed majorly due to initiatives undertaken by the Governments. Based on regions, the market is classified into North America, Europe, and Asia Pacific. While Asia Pacific is expected to remain the largest market, the North America region is anticipated to emerge as the fastest growing region through 2026.  Currently, the Asia Pacific market is roughly 4x larger than the European market, 3x the North American region. The Global market is forecast to rise from $2.118 Billion in 2017 to $56.959 Billion in 2026, signaling rapid adoption of Electric Vehicles, both residential and commercial.

Background Info

On March 8, 2020, Saudi Arabia initiated a price war with Russia, facilitating a 65% quarterly fall in the
price of oil. Over a few weeks, US crude oil fell by 26% and Brent oil fell by 24%. The price war was
triggered by a breakup in dialogue between OPEC (Organization of the Petroleum Exporting Countries)
and Russia over proposed oil production cuts in the midst of the 2019-2020 coronavirus pandemic.
Russia walked out of the discussion, leading to a breakup of OPEC+ (14 OPEC members + 10 other oil
producing nations). Oil prices had already fallen 30% since the start of the year due to a drop in demand.
The price war is one of the major causes and effects of the on-going global stock market correction.
(Wiki).

Short-Term Observations and Long-View Considerations

• The conflict showed little regard for setting off a potential credit crisis among global banks with
• outstanding loans to highly indebted companies (particularly shale producers in the U.S.)
• END GAME SCENARIO. A backdoor attempt to drive competitors into bankruptcy and shore up prices that way
• Saudi’s production cost is estimated to be $8-9, Russia $19, and US Shale/Texas Basins (low-end
• $20s-30s, high end $46-54); US Shale/Bakken Williston Basin (NDakota/Montana) $23-70
• Fossil fuel abundance and climate change policy threaten the future prosperity of the so-called ‘producer economies’
• Recent meetings and publications by international organizations signal that producer economies must change their economic development models
• Recent forecasts and scenarios highlight the uncertainty that exists when it comes to assessing future ‘peak global oil demand’ as opposed to ‘peak oil supply’
• The OECD’s (Organization for Economic Co-operation and Development) oil demand peaked in 2005 and many of the world’s largest oil consumers have since peaked or are now experiencing slowing in demand
• Some see peak demand coming in the 2020s, others in the 2030s (Wood MacKenzie 2036) ExxonMobil is an outlier assuming it won’t have peaked by 2040
• Overturns the assumption that oil producing economies rationed their oil supplies in the belief that a barrel not produced today would be worth more when produced in the future
• Saudi Arabia has a diversification strategy, while Russia is on a path to increase its reliance on oil and gas exports
• To balance their fiscal budgets, Saudi Arabia needs $80/barrel, Russia $45.
• Climate Change mitigation threatens producers’ prosperity and influence
• PRODUCER MANTRA. No country should have to sacrifice economic prosperity or energy security in pursuit of environmental sustainability
• REALITY/NEW OIL ORDER. The shale revolution has heralded an era of ‘fossil fuel abundance’ but the rapid growth of renewable power generation is challenging the role of fossil fuels in the energy mix—particularly coal and gas—and making possible an electrification pathway to low carbon transportation that will negatively impact oil demand
• RECENT DEVELOPMENT. OPEC+, with sparring countries Saudi Arabia, Russia, and Mexico finally reaching a consensus production reduction agreement, agreed to drop daily production by 9.7 million barrels/day. Problem is, from a price support standpoint, that daily usage is forecast to decline as much as 25mm Bbl/day.
• CURRENT US RESPONSE. Shutting wells. Trump administration weighs paying drillers to leave oil in the ground amid glut. Possible addition of 23mm barrels to US Strategic Petroleum Reserve.
• CRYSTAL BALL PROGNOSIS. Lower oil prices ahead where only the most cost-competitive oil will be produced, notwithstanding the impact of geopolitics

Summary

While it is logical on the surface to conclude that Saudi Arabia and Russia are myopically focused on
holding market share, it is far more complex than that. By unifying with other OPEC members to support
the price of oil historically, they in a sense facilitated more US shale development, thereby undermining
their own efforts. Hence, a new more Machiavellian strategy may be in play.

In sum, the falling cost and growth of low carbon energy sources and the emphasis on decarbonization
means that the dominance of fossil fuels is being challenged. And that it may be near-term aided and
abetted by a post-pandemic, slow growth (as opposed to a U-Shaped or V-Shaped) global economic
recovery.

The baseline economic view now assumes a recession for 2020 Q2 to Q4 with a turnaround in Q1 2021 for Gross Domestic Product in the US (Wood Mackenzie estimate).  JP Morgan sees the economy contracting by 40% in Q2 and unemployment reaching 25 million job losses (20% unemployment). Do we repeat the 2008/2009 turnaround for a “V-shaped” economic recovery or do we see a very different shape to the economic recovery? There were differences in the causes of 2008/2009 as opposed to the speed of the coronavirus impact which may delay how quickly we recover.

Wholesale energy demand has slumped since the stay at home order has impacted jobs and the economy.  For example, PJM (which operates a wholesale electricity market in the Northeast) reports weekly energy forecasts are down by 5 to 7% through the end of March and likely lower. Other wholesale electricity operators are reporting similar trends. Since demand is lower, cheaper resources are used to meet demand. This favors an increase in wind and solar transmission connected resources, since the US Energy Information Association reports lower variable costs for these resources. Both the California Independent System Operator and PJM report renewables (from all sources) are 12% of grid dispatch. As the market clears for low cost, less air emitting resources, both pollution and prices should drop in the near term.

• Fossil fuel generators are running less due to lower demand, based on preliminary data from March and April. Experts say it may also slow investment in energy efficiency and clean energy projects.  (RMI)
• In addition to changes in load and energy usage, operators are also seeing shifts in the timing of demand. “One of [the] clearer signals from the past few weeks is a changing load shape as people stay home and office buildings, whose lighting and HVAC loads are a big driver of afternoon peaks, have seen their occupancy fall, This has caused an observable flattening of the load curve in many regions, from one with a twice-daily peak (characteristic of normal springtime shapes) to a flatter, lower peak.”  (RMI)
• The New York Independent System Operator (NYISO) is observing daily peak loads trending about 4% lower than typical for this time of year, officials said.  
• The Electric Reliability Council of Texas (ERCOT) said that while it has seen little impact to daily peaks, morning loads are currently 6% to 10% lower than what forecast models would typically predict.  Based on the data from the weeks of March 22 and 29, weekly energy use is down by approximately 2%. 
• In the Midcontinent Independent System Operator territory, the grid operator says its load shape “continued to shift during the last half of March as more states implemented stay-at-home orders. Morning and evening load levels are lower than normal and morning peaks have moved closer to noon compared to 9 a.m. in previous weeks.”  
• The New England Independent System Operator said it is still seeing load declines of 3% to 5%, similar to what it witnessed two weeks ago.  
• In the Southwest Power Pool (SPP), officials said they are witnessing a 4% to 6% reduction in load, compared to similar days and temperatures for previous years.  
• In California, grid operators from March 17 to March 28 saw load reductions of 5% to 8% on weekdays, and 1% to 4% on weekends, with the heaviest impact occurring over the morning peak hours.  “Based on experiences in Italy and Spain, the ISO expects load reductions to level off about three weeks after the [shelter-in-place] order’s implementation. The California grid operator saw day-ahead market prices decline $5/MWh, when compared to before and after March 17, while real-time market prices saw a reduction of $10/MWh.” 
• And in Florida, immediately after the stay-at-home order went into effect last week,  there was a clear drop-off in demand of more than 10%. However, warmer temperatures in the past few days have pushed air conditioning loads back up.  (RMI)
• Looking ahead, there could be changes to the national fuel mix due to the coronavirus shutdown. “Going forward, we would expect to see coal generation fall faster than gas, as gas fuel prices are depressed due to falling demand and coal plants, especially when gas is cheap, are generally more expensive to operate, We anticipate that even this temporary, near-term drop in load might lead to long-lasting impacts on coal plants, whose economics get worse as they run less, and set off a fresh wave of retirements.” (RMI)
• In addition to changes to load shape, energy usage and the nation’s fuel mix, the pandemic could have longer-term implications for clean energy projects. “But what may be a bigger impact is the long-term effect of paused or slowed investment in both generation projects and behind-the-meter efficiency programs. The present crisis has pushed ‘pause’ on the investment necessary to meet increasingly aggressive climate and clean energy goals set by states across the US.” (RMI)

Early indication from metropolitan transit ridership indicates a substantial drop for ridership on trains and buses. For example, Orange County California bus ridership reported a 40% drop with stay at home orders. While pictures of urban areas show no traffic on city streets, metropolitan operations and maintenance expenses are rising with sanitization efforts, offsetting some of the lower fuel costs. Discretionary ridership may require a long period of recovery as work at home efforts may stall recovery. 

As states begin to open markets after the coronavirus pandemic, there are three areas we are watching closely to determine impacts on consumer electric vehicle purchases and usage. What will happen to funding for EV subsidies/tax relief and the ability of states to enact tighter than federal standards? Why are these incentives important in key metropolitan areas? Will state and metropolitan areas continue to invest in charging infrastructure?

States, cities, and utilities continue to develop comprehensive electric vehicle policy packages.

Various state and local authorities are reducing consumer purchase barriers with policy, incentives, infrastructure buildout, and awareness campaigns. States adopting California’s ZEV regulations catalyze the market, expand model availability, and provide assurance for charging infrastructure investments. In 2018 and 2019, Colorado is adopting similar ZEV regulations, and New Jersey and Washington State have signaled their commitment to electric vehicles by joining the International Zero Emission Vehicle Alliance. Markets like Atlanta, Austin, Columbus, Denver, New York, Portland, Seattle, Washington, DC, and those in California continue to construct and implement their own electric vehicle promotion policies to help reach their emission-reduction goals.

Consumer incentives remain important.

Electric vehicle prices have greatly decreased even as their electric ranges have increased. Yet, incentives remain important to reduce electric vehicles’ upfront cost. Consumer incentives, typically worth $2,000 to $5,000, were available through 2018 in nine of the 11 major metropolitan areas with the highest uptake. The exceptions are Seattle, where the state incentive expired in May 2018, and Washington, DC, where some drivers benefit from nearby Maryland’s state incentive. Incentives like carpool lane access and preferential parking policies benefit electric vehicle drivers in Nashville, Phoenix, Raleigh, Salt Lake City, and many areas in California. As the federal $7,500 electric vehicle tax credit begins to phase out for some manufacturers, continued state, city, and utility incentives will remain important.

Electric vehicles and the charging infrastructure network grow in tandem.

Even though most charging occurs at home, electric vehicle market shares are typically larger where there is greater availability of public regular, public fast, and workplace charging infrastructure. Markets with high electric vehicle uptake have at least 400 public charge points per million people. By contrast, half of the U.S. population lives in markets with charging infrastructure at least 60% below this benchmark. In the top electric vehicle markets, about 10 to 25% of the available public charging is fast charging. The top electric vehicle markets also typically have at least 150 workplace charge points per million people, and San Jose, with the highest electric vehicle share in 2018, had about 9-times this value.

Introduction
The macro operating environment for power companies has changed dramatically in recent years. Renewable energy is increasingly competitive with fossil fuels. Distributed energy (behind-the-meter resources) is unending the economics of the grid. Climate change is presenting new threats to power systems and their regulatory models. Further, companies that outsource supply management face billing surprises through third parties. The standard rate-making regime, with a predictable tariff structure, is being asked to integrate new performance-based metrics into utility revenue models. Examples include standards or metrics for energy efficiency, customer engagement, and sustainability.

Public Power Impact
While Public Power may be somewhat insulated, given its non-profit structure, both Generation & Transmission and Distribution companies are still subject to internal and external changes and threats. This is true for those who take an active or passive risk approach to supply management and for those who manage risks internally or outsource externally. Most importantly, opting for third-party load management doesn’t assure sound risk management by the selected vendors because settlement data is not made available. Significantly, all this is happening against a backdrop of stagnating electricity demand and during a period of weak commodity prices.

Risk Exposures/Impacts by Category

1. Customer Opt-Outs create demand volatility Customer “opting out” can change the public power load profile (either energy or peak load). Risk Managers may increase financial reserves to handle opt-out customers. Risk Managers may adjust risk exposure of open positions (both physical and hedge) to compensate for opt-out customers. Further, marketers and other utilities put pressure on rates for key customers. Not to exceed pricing changes terms and conditions for third party suppliers and the types of price hedges offered in the market. Rather than change rates, public power groups may wish to alter procurement strategies to maintain their competitive rate structure.
2. Market Risk Given new supplies from distributed and renewable resources, there is uncertainty of financial performance due to variable market prices and price relationships (basis risk from different sources). Requires regular management review, approved procurement strategies, and sound limit structures are required to manage these risks.
3. Regulatory Risk Legislative/Regulatory proceedings and directives impact the operating environment. Renewable portfolio standards, distributed resource requirements and storage incentives have triggered different portfolio mixes over time.
4. Volumetric Risk Both supply and demand volume fluctuations require different portfolio tools. Operating reserve increases to manage variable resources may be required, but embedded within third party contracting. Risk managers may need to quantify variability in procurement timing and costs in supplier negotiations. We have found that customers are adopting/modifying formal procurement strategy, monitoring trends in customer onsite generation (distributed energy resources), assessing impacts of economic shifts, and adjusting for changes in customer volume/composition.
5. Model Risk Several customers have developed and re-trained advanced forecast models to account for surprises in energy and capacity. Testing and improving forecast errors have become more complex with demand and supply delivery risks.
6. Operational Risk Uncertainties in the macro environment have led to surprises in operations including human resources, technical resources, systems, and/or operating procedures. This is a big impact to insurance and oversight by third party insurance carriers.
7. Counterparty Credit Risk Suppliers have become cost conscious creating potential controls issues. Control counterparty credit risk is usually controlled through strict limit controls established by credit policy, but many public power groups are seeking further information upstream from system, energy and other third parties in the supply chain.
8. Risk Measurement Methodology Most public power risk managers are reporting identification, measurement and communication of risk to stakeholders. Risk Managers routinely quantify risks associated with procurement-related business activities and performance relative to goals. Some risk managers have been calculating projected procurement costs on an annual basis at various probabilities and “stress testing” for extreme climate conditions such as hurricanes or wildfires. Most Risk Managers will re-evaluate methodologies on a periodic basis to reflect changing/evolving regulatory regime and competitive landscape.

Conclusion
Managing supply and demand in a rapidly changing environment is much more than a daily system and load-balancing challenge. The old adage, you can’t manage what you don’t measure is more applicable than ever. Whether it’s the competing regulatory dissonance between Federal and State mandates, the necessity of carbon transition, the competition for and retention of customers threatened by new entities (community choice aggregation), or customer demand for higher green content, an active approach both to internal and external management of power distribution requires constant vigilance.