Sustainability Atlas
Renewable Energy·14 min read··...

Interview: the builder's playbook for Community solar & shared renewables — hard-earned lessons

A practitioner conversation: what surprised them, what failed, and what they'd do differently. Focus on KPIs that matter, benchmark ranges, and what 'good' looks like in practice.

Community solar installed a record 1.7 GWdc in 2024—a 35% surge that brought cumulative U.S. capacity to 8.6 GWdc and now represents 40% of all non-residential solar deployment. Yet behind these headline numbers lies a more complex reality: subscriber acquisition costs averaging $72-102 per kilowatt, low-income customer churn rates approaching 20%, and a projected 22% market contraction in 2025 as policy deadlines and interconnection bottlenecks reshape the landscape. We spoke with developers, subscription managers, and investors across the sector to understand what's actually working, what's failing, and what they'd do differently if starting today.

The hard truth? Community solar has evolved from a simple democratization play into a sophisticated financial and operational business that demands excellence across subscriber acquisition, utility billing integration, regulatory navigation, and portfolio management. The companies capturing value are those treating operations as seriously as project development. Here's what practitioners have learned on the front lines.

Why It Matters

Approximately 77% of American households cannot install rooftop solar due to rental status, roof conditions, shading, or structural limitations. Community solar bridges this gap by allowing subscribers to purchase or lease shares of offsite solar installations and receive credits on their utility bills. The model unlocks clean energy access for millions of renters, apartment dwellers, and homeowners with unsuitable roofs.

For product and design teams building in this space, the stakes are significant. The Department of Energy's Community Power Accelerator has trained over 150 developers and maintains a marketplace with 140+ verified projects seeking capital. The DOE's National Community Solar Partnership targets 5 million households and 25 GW of capacity by 2030—triple current levels. Twenty-four states plus the District of Columbia have enabling legislation, with 20 states explicitly addressing low-income participation.

The business case extends beyond access. Median subscriber savings deliver a positive net present value of $0.27 per watt-AC, meaning subscribers genuinely save money while developers and investors capture attractive returns. Low-income subscribers now represent 9% of capacity, with state mandates pushing toward 25-40% in key markets. The Inflation Reduction Act's low-income community bonus credits add 10-20 percentage points on top of the base 30% Investment Tax Credit—potentially reaching 50%+ total ITC for qualifying projects.

Yet the model's complexity creates real challenges. New York, Maine, and Illinois accounted for 71% of 2024 installations, revealing extreme geographic concentration. Massachusetts installations dropped 78% year-over-year in early 2025. California has deployed less than 50 MW despite being the nation's largest solar market, due to infeasible program rules. Success requires navigating a patchwork of state policies, utility billing systems, and evolving incentive structures.

Key Concepts

Virtual Net Metering and Billing Credits

Community solar operates through virtual net metering, where subscribers receive credits on their utility bills proportional to their subscription share. Unlike rooftop solar, the physical panels exist at a separate location—often miles away. This creates both opportunity and complexity: opportunity because subscribers don't need suitable roofs, complexity because billing integration with utilities requires sophisticated systems.

"The number one operational challenge isn't building projects—it's managing subscriber allocations and utility credit flows," explains a veteran subscription management executive. "Every utility has different billing cycles, credit calculation methodologies, and data integration requirements. A single project might serve subscribers across three utility territories with three different systems."

Anchor Tenants and Subscriber Mix

Successful projects typically combine commercial anchor tenants with residential subscribers. Commercial customers—municipalities, school districts, corporate buyers—provide predictable demand and lower acquisition costs (approximately $30/kW versus $72-102/kW for residential). Fortune 500 companies including Microsoft, Starbucks, and Wendy's have signed substantial community solar commitments.

"We structure deals with 40-60% anchor tenant capacity," notes a developer with projects across the Northeast. "Anchors de-risk the project, improve financing terms, and create a stable base while we fill remaining capacity with residential subscribers. The worst mistake is trying to go 100% residential in an unproven market."

Low-to-Moderate Income Requirements and Challenges

State programs increasingly mandate low-to-moderate income (LMI) participation, typically 25-40% of project capacity. The Inflation Reduction Act amplifies this through bonus credits: projects delivering 50%+ financial benefits to households below 200% of the federal poverty line or 80% of area median income qualify for a 20 percentage point ITC adder.

However, LMI economics remain challenging. Acquisition costs run 42% higher than non-LMI residential customers ($102/kW versus $72/kW), and churn rates approach 16-20%—nearly double standard residential. Income verification creates friction, and many eligible households remain skeptical of offers that sound "too good to be true."

"We've tested dozens of approaches for LMI acquisition," shares a developer focused on affordable housing partnerships. "What works is embedding subscription offers within trusted relationships—housing authorities, community action agencies, weatherization programs. Cold outreach to LMI households fails almost universally."

What's Working

Nexamp's Scale and Operational Excellence

Nexamp exemplifies the integrated developer model, with 1.5 GW in operation or under construction across 19 states. The company raised $520 million in 2024 and has executed partnerships with major brands including Starbucks (40 MW in Illinois) and T-Mobile (50+ MW across the Northeast). Their success stems from vertical integration: Nexamp handles development, construction, subscriber management, and asset operations internally.

"Nexamp understood early that community solar is fundamentally an operations business," observes an industry analyst. "They invested in subscriber management software, billing integration capabilities, and customer service infrastructure when competitors were still treating operations as an afterthought."

Arcadia's Platform Approach

Arcadia became the first community solar company to reach 2 GW of capacity in January 2024, operating 400 farms across 15 states with over 2,500 business customers. Rather than developing projects directly, Arcadia operates as a platform connecting subscribers with developer-built projects and managing the complex billing and allocation processes.

"The platform model addresses subscriber management at scale," notes a subscriber management executive. "Individual developers struggle to maintain the billing integrations, customer service capabilities, and churn management systems that become essential at 10,000+ subscribers. Aggregation creates operational leverage."

Apollo-Bullrock Joint Venture Model

Apollo Global Management's April 2025 announcement of a $220 million joint venture with Bullrock Energy Ventures represents the maturation of community solar financing. The deal allocates $100 million for development and $120 million for construction and operations, targeting 500 MW of community solar in New York and New England. Bullrock, a Vermont-based vertically integrated developer, provides project execution while Apollo provides institutional capital at scale.

"This structure is becoming the template," explains a project finance advisor. "Developers bring market knowledge and execution capability; institutional capital brings balance sheet strength and lower cost of capital. The combination enables faster deployment than either party could achieve alone."

What's Not Working

Geographic Concentration and Policy Volatility

The community solar market's extreme geographic concentration creates systemic fragility. New York contributed 861 MWdc in 2024—49% of national volume—while Maine's 370 MWdc reflected a rush to meet net metering deadlines rather than sustainable growth. When Maine's policy deadline passed, installations collapsed 85% year-over-year. Massachusetts dropped 78%.

"We built our business around three state markets," admits a developer now restructuring operations. "When policy windows closed in two of them simultaneously, we went from growth mode to survival mode in six months. The lesson is diversification—geographic and customer segment—even when concentration seems more efficient."

California's Regulatory Failure

Despite representing the nation's largest solar market, California has deployed less than 50 MW of community solar through 2024. The state's program rules—complex bill crediting structures, utility resistance, and inadequate incentive levels—have rendered projects economically infeasible.

"California should be a 2-3 GW market," notes a national developer. "Instead, it's essentially zero. The program design prioritized utility concerns over market function. Developers who waited for California to fix its policies wasted years of opportunity in functional markets."

LMI Churn and Acquisition Economics

Low-income subscriber churn rates of 16-20% annually devastate project economics. With acquisition costs of $102/kW for LMI customers, projects require 5+ years of stable subscription to achieve payback. When subscribers churn within 1-2 years, developers face repeated acquisition cycles that consume margins.

"Our early LMI projects modeled 5% annual churn based on industry guidance," recalls a developer. "Actual experience showed 18% in the first year, driven by household mobility, payment issues, and misunderstanding of the program. We now build 15% annual churn into all LMI projections and price accordingly."

Interconnection Delays

Grid interconnection remains the primary physical bottleneck. Projects in queue often wait 18-36 months for utility studies and approval, tying up capital and creating deadline risk for incentive programs. The backlog exists at both distribution (community solar scale) and transmission (utility scale) levels.

"We have 80 MW of shovel-ready projects waiting on interconnection," shares a frustrated developer. "The utility's study process adds 24 months to our timeline. By the time we receive approval, incentive levels have often changed, subscriber commitments have expired, and we're essentially re-developing the project."

Key Players

Established Leaders

  • Nexamp — Leading community solar developer with 1.5 GW in operation or under construction across 19 states. Raised $520 million in 2024. Notable partnerships include Starbucks and T-Mobile.

  • Arcadia — First company to reach 2 GW community solar capacity (January 2024). Platform model connecting subscribers with 400+ farms across 15 states. Over 2,500 business customers.

  • Pivot Energy — Denver-based developer completing approximately 830 projects through 2024. Named 2024 Top Solar Contractor by Solar Power World. Partnerships with Microsoft and Rivian.

  • AES Clean Energy — Major asset owner with substantial community solar portfolio. Part of top 10 asset owners controlling 54% of 2024 capacity.

Emerging Startups

  • Neighborhood Sun — Crowdfunded over $1.9 million via Wefunder in December 2024 from 2,337+ community investors. Operating 136 community solar farms across 7 states. Entering California market in 2025.

  • Bullrock Energy Ventures — Vermont-based vertically integrated developer. Secured $220 million Apollo Global joint venture for 500 MW New York/New England pipeline.

  • 38 Degrees North — Raised $230 million+ in corporate growth capital. Positioned to weather regulatory changes through strong capitalization.

  • Catalyze — Ranked in Solar Power World's 2024 Top Community Solar Contractors. Notable projects include 6.4 MW Amherst Solar Farm serving 1,300 LMI housing units.

Key Investors & Funders

  • Apollo Global Management — $220 million community solar joint venture with Bullrock Energy Ventures announced April 2025.

  • TPG — Announced $2.2 billion acquisition of Altus Power (including debt) through TPG Rise Climate Transition Infrastructure fund.

  • Brookfield — Multiple investments totaling $2.5 billion+ into U.S. community solar sector.

  • Greenprint Capital — $275 million tax equity partnership with Nautilus Solar Energy for 130 MW across Illinois, Maryland, New York, Rhode Island, and Delaware.

  • DOE Community Power Accelerator — Federal program providing training to 150+ developers and maintaining marketplace with 140+ verified projects. $10 million prize program.

Action Checklist

  1. Diversify geographic exposure: Target operations in 4+ state markets to reduce policy concentration risk. Prioritize states with stable, long-term program structures (Illinois, New Jersey, Maryland) over those with expiring incentives.

  2. Build LMI acquisition through partnerships: Develop formal relationships with housing authorities, community action agencies, and affordable housing developers. Budget 40-50% higher acquisition costs and 15-20% annual churn for LMI subscribers.

  3. Secure anchor tenants early: Structure projects with 40-60% commercial anchor capacity before breaking ground. Commercial customers provide financing certainty, reduce blended acquisition costs, and stabilize project economics.

  4. Invest in billing integration infrastructure: Build or license subscriber management systems with robust utility billing integrations. Poor billing execution drives churn and destroys customer lifetime value.

  5. Model interconnection timelines conservatively: Add 12-18 months to utility-provided timeline estimates. Maintain active projects in queue while pursuing expedited interconnection opportunities.

  6. Leverage IRA low-income adders: Structure projects to qualify for 10-20 percentage point ITC bonuses through location, affordable housing partnership, or economic benefit delivery. The adders fundamentally change project economics.

  7. Establish tax equity relationships early: Engage tax equity investors during development, not after construction. The market has capacity constraints, and relationship-based allocation increasingly determines access.

  8. Track subscriber economics rigorously: Implement systems measuring acquisition cost per kW, churn rates by segment, lifetime value by channel, and credit allocation efficiency. Operational excellence increasingly separates winners from losers.

FAQ

Q: What subscriber acquisition cost and churn rate should product teams plan for when modeling community solar economics?

A: Plan for $72/kW acquisition cost for non-LMI residential subscribers and $102/kW for LMI subscribers (42% premium). Commercial anchor tenants run approximately $30/kW. For churn, use 8-10% annually for standard residential and 16-20% for LMI subscribers. These figures reflect 2024 industry benchmarks but vary significantly by market and acquisition channel. Direct mail and digital advertising typically produce higher acquisition costs and churn than partnership-based approaches through employers, housing authorities, or community organizations.

Q: How do the Inflation Reduction Act's low-income community bonus credits work, and what's required to qualify?

A: The IRA adds 10-20 percentage points to the base 30% ITC for qualifying projects under 5 MW. The 10% adder applies to projects located in Census tracts with 20%+ poverty rates or median family income at or below 80% of state median. The 20% adder requires either siting on qualified low-income residential buildings (affordable housing) or delivering 50%+ of financial benefits to households below 200% of federal poverty line or 80% of area median income. The Low-Income Communities Bonus Credit Program allocates 1.8 GW of annual capacity across categories. Tax-exempt entities (nonprofits, cooperatives, CDFIs) can use direct pay to monetize credits, though projects over 1 MW face domestic content requirements beginning 2025.

Q: Why is California's community solar market so small despite being the nation's largest solar market overall?

A: California's community solar program design prioritized utility concerns over market functionality, resulting in complex bill crediting structures and inadequate incentive levels that render most projects economically unviable. Through 2024, the state deployed less than 50 MW of community solar compared to New York's 861 MW in 2024 alone. The fundamental issue is value allocation: California's structure captures too much value for utilities while leaving insufficient margin for developers and subscribers. This contrasts with successful markets like Illinois, New York, and Maryland where program designs balanced stakeholder interests to enable market growth.

Q: What does the 2025 market contraction mean for companies building in community solar?

A: The projected 22% decline in 2025 installations (from 1.7 GWdc to 1.5 GWdc) reflects natural correction after policy-driven surges rather than fundamental market failure. Maine installations crashed 85% after net metering deadlines passed; Massachusetts dropped 78%. However, New York maintains 52% market share and continues growing. Well-capitalized developers with diversified portfolios will gain market share as weaker competitors exit. The contraction period favors operational excellence over aggressive expansion. Companies should focus on completing interconnection queues, optimizing existing subscriber bases, and building capability for when new state programs (Pennsylvania, Ohio, Georgia, Washington, Wisconsin) come online.

Q: How should teams think about the build-versus-buy decision for subscriber management systems?

A: For developers with fewer than 10,000 subscribers across 2-3 utility territories, purpose-built third-party platforms typically outperform custom solutions. The top three subscription management companies handle 56% of all subscribers and 71% of LMI subscribers, reflecting the operational complexity of billing integration, credit allocation, and churn management. Building internally makes sense only at scale (50,000+ subscribers) or when competitive differentiation requires proprietary capability. The migration cost is real—developers shifted 70 million kWh to new platforms in H2 2024 alone—so choose partners carefully and negotiate portability provisions.

Sources

The community solar sector stands at an inflection point. Record 2024 installations demonstrated the model's viability, but 2025's contraction reveals the fragility of policy-dependent growth. Product and design teams building in this space must prioritize operational excellence—subscriber acquisition efficiency, billing integration reliability, churn reduction—over the simpler challenges of project development. The companies that master these operational fundamentals will capture disproportionate value as the market matures toward the DOE's 25 GW target. Those treating community solar as merely another solar deployment model will find margins compressed and market access constrained. The playbook is clear; execution will determine winners.

Topics

communitysolarScope 3inverterfinancingMRVnet metering

Related Articles