Commercial Models: SaaS, Shared Savings, and Capacity Lease Structures

🎯 Learning Objectives

✓ Analyze and compare revenue risk exposure across SaaS, Shared Savings, and Capacity Lease models using cash flow sensitivity metrics
✓ Design a hybrid commercial model that combines SaaS base fee with Shared Savings upside for a 5-MW solar+storage aggregation portfolio
✓ Calculate annualized customer acquisition cost (CAC) and lifetime value (LTV) under each model to assess unit economics viability
✓ Apply FERC Order No. 2222 compliance criteria to evaluate whether a Capacity Lease structure qualifies as a 'market participant' service

📖 Why This Matters

In DER aggregation, technical performance means little without a viable business model—and regulators increasingly require transparency in how aggregators earn revenue. A poorly structured commercial model can violate FERC/NERC rules, fail to attract capital, or misalign incentives between customers and aggregators. Understanding these three core models isn’t just about pricing—it’s about designing systems that are technically sound, financially sustainable, and regulatorily defensible.

📘 Core Principles

SaaS models decouple revenue from physical asset performance: they charge per site, per MW aggregated, or per API call—emphasizing scalability and low marginal cost. Shared Savings models embed performance accountability: compensation is contingent on verified savings (e.g., reduced demand charges), requiring rigorous metering, baseline methodology (e.g., CalTRACK), and third-party verification. Capacity Lease models treat aggregated DERs as dispatchable capacity resources—revenue flows from capacity markets (e.g., PJM RPM) or utility contracts, demanding reliability guarantees (e.g., ≥95% availability), telemetry SLAs, and dispatch responsiveness (<2 sec latency). All three must comply with FERC Order No. 2222’s non-discrimination and transparency requirements—and avoid classifying DERs as 'utility-owned' assets.

📐 Shared Savings Payout Calculation

The Shared Savings payout quantifies compensation based on measured savings relative to a statistically validated baseline and agreed-upon split. It ensures fair reward for value delivered while protecting against gaming or baseline manipulation.

Shared Savings Payout

P = (D_b − D_a) × T × M × S

Compensation paid to aggregator under Shared Savings model

Variables:

Symbol	Name	Unit	Description
P	Payout	USD/year	Annual compensation to aggregator
D_b	Baseline peak demand	MW	Statistically derived pre-intervention demand level
D_a	Actual peak demand	MW	Measured post-aggregation demand
T	Tariff rate	USD/kW-month	Applicable demand charge or capacity rate
M	Months of savings period	months	Duration over which savings apply
S	Savings share	fraction	Aggregator’s negotiated percentage of gross savings

Typical Ranges:

C&I solar+storage: $30,000–$120,000/MW-year

Residential VPP pilot: $500–$2,500/home-year

💡 Worked Example

Problem: A 3-MW battery aggregation reduces peak demand by 1.2 MW during 4 summer months. Baseline peak demand = 3.8 MW; post-aggregation peak = 2.6 MW. Utility tariff: $15/kW-month demand charge. Savings share = 70%. Measurement & verification follows CalTRACK Option B.

1. Step 1: Calculate monthly demand reduction = 3.8 MW − 2.6 MW = 1.2 MW

2. Step 2: Compute monthly demand charge savings = 1.2 MW × $15/kW-month = $18,000/month

3. Step 3: Annualize over 4 months = $18,000 × 4 = $72,000

4. Step 4: Apply savings share = $72,000 × 0.70 = $50,400

Answer: The aggregator receives $50,400 for the year. This falls within typical Shared Savings payouts of $30k–$120k/year per MW aggregated in commercial & industrial portfolios.

🏗️ Real-World Application

In 2023, Stem Inc. deployed its Athena™ platform under a hybrid SaaS + Shared Savings model for Southern California Edison’s DR program. Customers paid $150/month per site (SaaS) plus 60% of verified demand charge savings. The model passed CPUC Rulemaking (R.20-08-013) scrutiny because: (1) SaaS fee was capped at 20% of total program value, (2) savings were verified via interval meter data and CalTRACK-compliant baselines, and (3) no capacity lease obligations were assumed—avoiding FERC jurisdictional triggers for wholesale market participation.