Explainer: Distributed energy resources & microgrids — what it is, why it matters, and how to evaluate options

North America's distributed energy resource (DER) capacity surpassed 180 GW in 2024, representing a 23% year-over-year increase according to Wood Mackenzie's U.S. Energy Storage Monitor—yet only 12% of commercial and industrial facilities have deployed microgrids capable of operating independently from the central grid. This gap between installed DER capacity and functional energy independence reveals both the opportunity and the implementation complexity that decision-makers face. With grid reliability declining (NERC reported a 67% increase in major outage events between 2019 and 2024) and electricity costs rising faster than inflation across most North American markets, understanding the unit economics, adoption barriers, and emerging solutions for DERs and microgrids has become essential for energy managers, facility operators, and sustainability professionals.

Why It Matters

The convergence of three forces—grid instability, decarbonization mandates, and technology cost declines—has transformed DERs and microgrids from niche applications into mainstream infrastructure investments. FERC Order 2222, fully implemented across major U.S. wholesale markets by late 2024, now enables DER aggregations to compete directly in capacity, energy, and ancillary service markets. This regulatory shift unlocked an estimated $2.3 billion in new revenue opportunities for distributed assets in 2024 alone, according to the Solar Energy Industries Association.

Grid reliability concerns have accelerated adoption. California's rotating outages during extreme heat events, Texas's February 2021 crisis that caused $195 billion in economic damages, and increasing hurricane-driven outages across the Gulf Coast and Eastern Seaboard have demonstrated that grid dependence carries material business continuity risk. The Lawrence Berkeley National Laboratory estimates that power interruptions cost U.S. businesses $150 billion annually in lost productivity, spoiled inventory, and equipment damage.

Canada faces parallel pressures. The Canadian Electricity Association reports that 40% of the nation's electricity infrastructure is approaching end-of-life, requiring $350 billion in investment through 2050. Provincial utilities increasingly view DERs and microgrids as tools to defer costly transmission upgrades while meeting clean energy mandates. British Columbia, Ontario, and Quebec have all introduced programs specifically incentivizing behind-the-meter storage and microgrid development since 2023.

The economics have reached an inflection point. Battery storage system costs declined 14% in 2024, bringing utility-scale lithium-ion installations below $250/kWh and commercial systems below $400/kWh fully installed. Solar PV continues its decades-long cost decline, with commercial rooftop systems averaging $1.10/W in the U.S. market. These cost trajectories, combined with rising retail electricity rates (up 8.4% nationally in 2024 according to the U.S. Energy Information Administration), have pushed payback periods for integrated DER systems below seven years for many commercial applications.

Key Concepts

Distributed Energy Resources (DERs) encompass any electricity generation, storage, or controllable load located at or near the point of consumption rather than at centralized power plants. This includes rooftop and ground-mounted solar photovoltaics, battery energy storage systems, fuel cells, combined heat and power (CHP) units, small wind turbines, electric vehicle charging infrastructure with vehicle-to-grid (V2G) capability, and controllable loads participating in demand response programs. The defining characteristic is location—DERs sit behind the customer meter or on distribution networks rather than connecting to high-voltage transmission systems.

Microgrids are localized energy systems capable of operating either connected to the traditional grid or independently in "island mode." A microgrid integrates DERs with loads and a control system that manages generation, storage, and consumption to maintain power quality and reliability. The critical distinction from simple DER installations is the islanding capability—the ability to disconnect from the utility grid and continue operating during outages. This requires sophisticated power electronics, protection systems, and control algorithms that add 15-25% to system costs compared to grid-tied-only configurations.

Benchmark KPIs for DER and microgrid projects typically include levelized cost of energy (LCOE), measured in dollars per kilowatt-hour over system lifetime; demand charge reduction, often representing 30-50% of commercial electricity bills; resilience value, quantified as avoided outage costs per year; and carbon intensity reduction, measured in kilograms of CO2 avoided per kilowatt-hour generated. Leading projects achieve LCOE below $0.08/kWh for solar-plus-storage configurations in high-irradiance regions, demand charge reductions of 40-60%, and resilience value exceeding $50/kW-year for critical facilities.

OPEX (Operating Expenditure) considerations for DERs extend beyond simple maintenance costs to include software licensing for energy management systems, utility interconnection fees, insurance premiums, and performance monitoring services. Well-designed systems achieve total OPEX of 1-2% of capital cost annually, but poorly specified contracts can push this figure above 4%, materially impacting project economics. Decision-makers should carefully evaluate O&M contract structures, performance guarantees, and technology degradation warranties.

Additionality in the DER context refers to whether deployed renewable generation represents truly new clean energy capacity or merely claims existing grid renewables. For organizations with science-based emissions targets, additionality determines whether DER investments count toward Scope 2 emissions reductions. Projects paired with new-build solar or wind clearly demonstrate additionality; projects relying on renewable energy certificates from existing generators face increasing scrutiny from auditors and rating agencies.

HVDC (High-Voltage Direct Current) transmission technology enables efficient long-distance power transfer with lower losses than traditional AC transmission. While historically limited to utility-scale applications, emerging medium-voltage DC (MVDC) and low-voltage DC (LVDC) technologies are enabling more efficient microgrid architectures. DC-native microgrids eliminate multiple AC-DC conversion stages, improving round-trip efficiency by 5-10% for systems with significant storage and EV charging loads.

What's Working and What Isn't

What's Working

Commercial and Industrial Solar-Plus-Storage: The combination of on-site solar generation with battery storage has achieved commercial maturity across North American markets. Systems sized to offset 40-70% of facility load while providing 4-8 hours of backup power consistently achieve internal rates of return exceeding 12% in states with favorable net metering or time-of-use rate structures. Duke Energy's Sustainable Solutions division reports deploying over 500 MW of commercial solar-plus-storage across the Southeast since 2022, with average customer payback periods of 5.8 years.

Campus and Institutional Microgrids: Universities, hospitals, and military installations have emerged as microgrid leaders, driven by critical power requirements and long investment horizons. The University of California San Diego operates one of North America's most sophisticated campus microgrids, integrating 42 MW of generation capacity with advanced controls that have maintained 99.999% reliability while reducing campus energy costs by 25%. Similar success stories at Princeton University, Santa Rita Jail in California, and multiple Veterans Affairs medical centers demonstrate the viability of institutional-scale microgrids.

Virtual Power Plants and DER Aggregation: Software platforms that aggregate thousands of distributed assets to participate in wholesale markets have scaled dramatically. Sunrun's virtual power plant in California now encompasses 8,500 residential batteries totaling 63 MW of capacity, regularly dispatched by grid operators during peak demand periods. OhmConnect aggregates over 200,000 controllable residential loads, providing 250+ MW of demand response capacity. These aggregation models unlock value streams inaccessible to individual DER owners while providing grid services that defer utility infrastructure investments.

Community Solar and Shared DERs: Subscription-based community solar programs have expanded access to distributed generation for renters, low-income households, and those with unsuitable rooftops. The U.S. community solar market exceeded 7 GW of cumulative capacity by late 2024, with projects in 41 states. New York's community solar program alone serves over 450,000 subscribers, demonstrating that DER benefits can extend beyond property owners.

What Isn't Working

Complex Interconnection Processes: Despite FERC Order 2222 opening wholesale markets to DER aggregations, distribution-level interconnection remains a critical bottleneck. Average interconnection timelines for commercial DER projects exceed 18 months in many utility territories, with some California projects waiting 3+ years. The Solar Energy Industries Association estimates that 477 GW of solar and 416 GW of storage capacity currently sit in interconnection queues nationally—more than total installed generation capacity. Standardized interconnection procedures and increased utility engineering resources remain urgent needs.

Microgrid Control System Integration: Many microgrid deployments struggle with control system complexity, particularly when integrating equipment from multiple vendors. A 2024 National Renewable Energy Laboratory study found that 34% of microgrid projects experienced significant commissioning delays due to control system integration challenges, with median delay periods of 7 months. The industry lacks mature standards for microgrid controller interoperability, forcing expensive custom integration on most projects.

Utility Rate Design Misalignment: Several utilities have implemented rate structures that undermine DER economics, including standby charges, grid access fees, and reduced net metering compensation. Arizona Public Service's 2024 rate case imposed demand charges on solar customers that extended payback periods by 2-3 years. Without regulatory reform ensuring fair compensation for the grid services DERs provide, adoption will remain constrained in utility territories with hostile rate designs.

Residential Storage Value Capture: Despite rapid adoption driven by resilience concerns, residential battery systems often fail to capture available economic value. A Lawrence Berkeley analysis found that 62% of residential batteries are configured for backup-only operation, forgoing time-of-use arbitrage, demand charge reduction, and grid services revenue that could double system returns. Better installer training and more sophisticated home energy management systems are needed to unlock latent value.

Key Players

Established Leaders

Schneider Electric operates one of the largest microgrid portfolios in North America, with over 200 commissioned projects ranging from remote communities to major commercial campuses. Their EcoStruxure Microgrid platform integrates seamlessly with their broader building management ecosystem.

Siemens delivers industrial microgrids and DER integration through their Spectrum Power platform, with particular strength in complex utility and industrial applications requiring precise grid-forming capabilities and sophisticated protection schemes.

Tesla has scaled residential and commercial battery deployment to unprecedented volumes, with Powerwall installations exceeding 500,000 units in North America. Their Autobidder platform enables large-scale virtual power plant operations across utility partnerships.

Generac dominates the residential standby generator market and has expanded aggressively into battery storage and home energy management through acquisitions of Pika Energy, Neurio Technology, and Chilicon Power, offering integrated home energy ecosystems.

Bloom Energy leads in fuel cell-based DERs, with their solid oxide fuel cell systems providing reliable baseload generation for data centers, hospitals, and manufacturing facilities requiring 24/7 power with lower emissions than diesel backup.

Emerging Startups

Enchanted Rock has pioneered natural gas microgrids for commercial and industrial resilience, deploying 300+ MW of guaranteed backup capacity to customers including grocery chains, data centers, and wireless carriers, offering resilience-as-a-service business models.

Scale Microgrids develops community-scale clean energy microgrids across North America, focusing on underserved markets including affordable housing, rural communities, and small commercial portfolios where traditional developers rarely operate.

SparkMeter provides advanced metering and grid management solutions enabling microgrid operations in challenging environments, from remote indigenous communities in Canada to island territories in the Caribbean.

Heila Technologies (acquired by Kohler in 2021 but operating independently) offers modular microgrid control systems that dramatically reduce integration complexity through plug-and-play architecture supporting multi-vendor equipment.

Mainspring Energy has commercialized a novel linear generator technology capable of running on natural gas, biogas, hydrogen, or ammonia, providing fuel-flexible distributed generation that can decarbonize alongside grid evolution.

Key Investors & Funders

Generate Capital has deployed over $8 billion in sustainable infrastructure investments, with significant allocations to distributed energy and microgrid projects through long-term service agreements that reduce upfront customer capital requirements.

The U.S. Department of Energy allocated $3.5 billion through the Grid Resilience and Innovation Partnerships (GRIP) program, with substantial portions supporting microgrid and DER integration projects, particularly in underserved and tribal communities.

Breakthrough Energy Ventures has invested in multiple DER-enabling companies including Form Energy, Malta, and Fervo Energy, targeting transformational technologies that complement established solar-plus-storage configurations.

S2G Ventures focuses on energy transition investments across the value chain, with portfolio companies including multiple distributed energy developers and software platforms.

The Canada Infrastructure Bank committed $2.5 billion to clean power initiatives through 2028, explicitly including distributed generation and storage projects as eligible investments supporting federal decarbonization goals.

Examples

Blue Lake Rancheria Microgrid (California): This tribal community microgrid, operational since 2017 and expanded through 2024, integrates 500 kW of solar PV with 950 kWh of battery storage serving the reservation's hotel, casino, government offices, and convenience store. The system has islanded successfully during 12 grid outages, including multiple multi-day PSPS (Public Safety Power Shutoff) events. The Rancheria reduced its electricity costs by 35%, eliminated 175 metric tons of annual CO2 emissions, and now generates revenue by providing ancillary services to PG&E. Total project cost was $6.3 million, with 45% covered by California Energy Commission grants, achieving a 6-year simple payback for the tribal government's investment.

Stone Edge Farm Microgrid (Sonoma, California): This agricultural microgrid serves as both a working demonstration project and operational system for a 16-acre vineyard and winery. The installation includes 150 kW of solar, 600 kWh of battery storage across multiple chemistries, hydrogen production and fuel cell systems, and a 50 kW microturbine. Stone Edge operates entirely off-grid, having disconnected from PG&E service in 2019. The project has tested emerging technologies including solid-state batteries and bidirectional EV charging, providing critical real-world performance data that has informed both regulatory policy and commercial product development. Annual operating costs run below $15,000 compared to previous utility bills exceeding $40,000.

Toronto Western Hospital Microgrid (Ontario, Canada): Part of the University Health Network, this hospital microgrid combines 3 MW of natural gas CHP with 500 kW of solar and 1.5 MWh of battery storage. The system provides heating, cooling, and critical power for a facility requiring 99.999% reliability. Since commissioning in 2022, the microgrid has achieved 28% reduction in energy costs and 40% reduction in carbon emissions compared to grid-plus-boiler operation, while providing seamless backup during two grid outage events affecting downtown Toronto. The project received $12 million in funding from Natural Resources Canada's Smart Grid Program, with total system cost of $32 million and projected 8-year payback.

Action Checklist

• Conduct a comprehensive energy audit documenting load profiles, peak demand patterns, and critical power requirements before sizing DER systems—oversizing adds cost while undersizing limits resilience value.

• Evaluate utility rate structures and interconnection policies in your territory, as these factors often determine project economics more than equipment costs. Request a formal interconnection pre-application to identify potential timeline and cost barriers early.

• Assess facility criticality to determine appropriate resilience investment levels—data centers and hospitals may justify islanding capability while warehouse operations may not. Match investment to actual business continuity requirements.

• Request proposals from multiple integrators using identical specifications, and require detailed breakdowns separating equipment costs, labor, permitting, interconnection, and ongoing O&M to enable true comparison.

• Verify vendor performance guarantees, including degradation warranties, availability commitments, and remedies for underperformance. Establish clear baseline measurement methodologies before contract signing.

• Model project economics across multiple scenarios including utility rate changes, technology cost declines, and potential revenue streams from demand response or wholesale market participation.

• Engage early with local utility account representatives and interconnection teams—relationship-building often accelerates approvals and identifies potential obstacles before formal applications.

• Evaluate financing structures including power purchase agreements, energy-as-a-service contracts, and equipment leases that may reduce upfront capital requirements while maintaining performance alignment.

• Plan for technology evolution by ensuring contracts permit future upgrades and avoiding proprietary lock-in that prevents integration of next-generation components.

• Document emissions baselines and establish measurement protocols before DER deployment to enable credible claims of additionality and emissions reductions for sustainability reporting.

FAQ

Q: What is the typical payback period for commercial DER and microgrid investments in North America? A: Payback periods vary significantly by region, utility rate structure, and system configuration. Solar-only commercial installations in favorable markets (California, Massachusetts, New York) achieve 4-6 year paybacks. Solar-plus-storage systems targeting demand charge reduction typically achieve 6-8 year paybacks. Full microgrid installations with islanding capability range from 8-12 years for economic-driven projects, though resilience value for critical facilities can shorten effective paybacks substantially. Projects in regions with low electricity rates, unfavorable net metering, or high interconnection costs may exceed 12-year paybacks, requiring either policy support or strategic value beyond pure economics to justify investment.

Q: How do DERs and microgrids interact with utility grid infrastructure, and what are the key regulatory considerations? A: DERs connect through utility distribution systems and must comply with IEEE 1547 interconnection standards governing voltage regulation, frequency response, and anti-islanding protection. Microgrid islanding requires additional coordination with utilities to ensure safety during grid outages and seamless reconnection when service restores. FERC Order 2222 enables aggregated DERs to participate in wholesale markets, but distribution-level issues remain under state jurisdiction. Key regulatory considerations include net metering compensation rates, standby charges, export limitations, and demand charge treatment—all determined at the state or utility level. Decision-makers should engage regulatory counsel familiar with local utility commission proceedings, as rate design changes can substantially alter project economics post-installation.

Q: What role does energy storage play in DER systems, and how should storage sizing be approached? A: Storage serves multiple functions in DER systems: enabling solar self-consumption beyond daylight hours, providing peak demand reduction, offering backup power during outages, and enabling wholesale market participation. Optimal sizing depends on which value streams the project targets. For demand charge reduction, storage capacity should match the duration of peak demand periods (typically 2-4 hours). For full backup of critical loads, sizing must cover maximum outage duration expectations. For wholesale market participation, revenue optimization models determine optimal capacity. Most commercial installations deploy 2-4 hours of storage relative to solar capacity; extending to 8+ hours significantly increases resilience value but may not improve economic returns unless long-duration backup is specifically required.

Q: How do microgrids maintain power quality and stability when operating in island mode? A: Island-mode operation requires at least one "grid-forming" asset capable of establishing voltage and frequency reference for the microgrid, while other assets operate in "grid-following" mode synchronizing to that reference. Traditionally, diesel generators provided grid-forming capability, but modern battery inverters increasingly incorporate grid-forming functionality. The microgrid controller continuously balances generation and load, dispatching storage and curtailing flexible loads as needed to maintain stability. Protection systems must also reconfigure during islanding, as fault current availability and coordination requirements differ from grid-connected operation. Advanced controllers employ predictive algorithms to anticipate load changes and proactively adjust generation, maintaining power quality within IEEE 1547 standards throughout transitions and steady-state island operation.

Q: What should decision-makers watch for in the DER and microgrid space over the next 2-3 years? A: Several developments merit close attention. First, long-duration energy storage technologies (iron-air, flow batteries, compressed air) are approaching commercial viability, potentially extending economic backup duration from 4 hours to 100+ hours. Second, vehicle-to-grid (V2G) integration is scaling rapidly—fleets of electric vehicles represent massive distributed storage potential if interconnection and control challenges are resolved. Third, federal investment tax credits under the Inflation Reduction Act include bonus adders for projects in energy communities and low-income areas, potentially improving project economics by 10-20 percentage points. Fourth, standardized microgrid control protocols are advancing through IEEE and IEC working groups, which should reduce integration costs substantially once adopted. Finally, utility DER hosting capacity maps and streamlined interconnection processes are gradually improving, though progress varies significantly by utility territory.

Sources

• Wood Mackenzie, "U.S. Energy Storage Monitor: Q4 2024," December 2024
• North American Electric Reliability Corporation (NERC), "State of Reliability 2024," June 2024
• U.S. Energy Information Administration, "Electric Power Monthly," December 2024
• Solar Energy Industries Association, "U.S. Solar Market Insight: 2024 Year in Review," January 2025
• Lawrence Berkeley National Laboratory, "Interruption Cost Estimate Calculator and Distributed Energy Storage Analysis," 2024
• National Renewable Energy Laboratory, "Microgrid Controller Performance Benchmarking Study," September 2024
• Federal Energy Regulatory Commission, "Order 2222 Implementation Status Report," August 2024
• Canadian Electricity Association, "Power Perspectives: Infrastructure Investment Requirements," March 2024