Revenue Per Megawatt-Hour (MWh) for Independent Power Producers

Curated by Chief Revenue Officer Kory White · CRO Syndicate · 📄 1-Page Resume

👍 Yup or 👎 Nope — vote this up its category:

📅 Published Jun 23, 2026 · 8 min read

Revenue Per Megawatt-Hour (MWh) for Independent Power Producers

Direct Answer

TL;DR

** Revenue Per Megawatt-Hour (MWh) for Independent Power Producers (IPPs) is the core metric that measures the average price received for each unit of electricity sold, net of all variable costs directly tied to generation. Unlike a simple PPA price, it accounts for merchant market exposure, ancillary service revenues, and production tax credits (PTCs).

For a typical 200 MW wind farm, a healthy Revenue/MWh is $35–$55, while a combined-cycle gas turbine (CCGT) plant should target $45–$70. IPPs must track this KPI weekly and reconcile it against budget, using tools like Clari for revenue forecasting and Salesforce Revenue Cloud for contract-to-cash management.

Failure to monitor Revenue/MWh leads to margin erosion from negative pricing events, curtailment penalties, and missed PTC compliance windows.

Why Independent Power Producers Measure Differently

Independent Power Producers (IPPs) operate a fundamentally different business model than regulated utilities. A regulated utility earns a guaranteed return on equity (ROE) from ratepayers, with cost-plus pricing that insulates them from wholesale market volatility. An IPP, by contrast, sells electricity into competitive wholesale markets (e.g., PJM, ERCOT, CAISO, SPP) or under Power Purchase Agreements (PPAs) with fixed or indexed prices.

Their revenue is entirely exposed to locational marginal pricing (LMP), congestion patterns, and renewable intermittency.

The key difference: Revenue/MWh for an IPP is not the PPA strike price. It is the net realized price after accounting for:

Merchant sales (spot market exposure)
Ancillary services (frequency regulation, reserves, reactive power)
Renewable Energy Certificates (RECs) and Production Tax Credits (PTCs)
Curtailment costs (negative pricing events where you pay to produce)
Congestion and transmission losses

A utility’s KPI might be “Revenue per Customer” or “Rate Base Growth.” An IPP’s survival depends on Revenue/MWh because it directly determines project IRR, debt service coverage ratios (DSCR), and ability to refinance. For example, a 100 MW solar farm in CAISO with a $40/MWh PPA might actually realize only $32/MWh after curtailment and congestion, making it non-viable.

This is why IPPs must measure differently.

The Most Important KPIs to Track

1. Revenue Per MWh (Core Metric)

Definition: Total gross revenue from electricity sales, ancillary services, RECs, and PTCs, divided by total MWh generated (net of station use). Formula: (Energy Revenue + Ancillary Revenue + REC Revenue + PTC Value) / Net MWh Generated.

Benchmarks:

Onshore Wind (US): $35–$55/MWh (blended PPA + merchant)
Solar PV (utility-scale): $30–$50/MWh
CCGT: $45–$70/MWh
Battery Storage: $80–$150/MWh (highly dependent on arbitrage and ancillary services)

Why it matters: This single number captures the effectiveness of your hedging strategy, PPA negotiation, and merchant optimization. If Revenue/MWh drops below your Levelized Cost of Energy (LCOE), you are losing money on every MWh.

2. Hedge Ratio (%)

Definition: Percentage of expected generation covered by fixed-price PPAs or financial hedges (e.g., swaps, options). A 100% hedge ratio means zero merchant exposure.

Benchmark: 70–90% for investment-grade IPPs; 50–70% for growth-stage developers.

Tool: Clari can track hedge coverage against forward curves, alerting when ratios fall below board-approved thresholds. Salesforce Financial Services Cloud can manage PPA contract lifecycle.

3. Realized Price vs. Day-Ahead Index

Definition: The spread between your actual settlement price and the day-ahead LMP at your node. Negative spread indicates curtailment or congestion losses.

Benchmark: Should be within ±$2/MWh for a well-hedged, non-congested node. A persistent negative spread >$5/MWh signals a structural problem (e.g., transmission constraints, bad PPA location).

4. Curtailment Rate (%)

Definition: MWh curtailed (dispatched down) divided by total available MWh. Renewable IPPs face curtailment when grid operators order them offline due to oversupply or congestion.

Benchmark: <5% for wind, <3% for solar in well-interconnected regions. In ERCOT or CAISO, rates can spike to 15%+ during spring solar oversupply.

Real number: In 2023, CAISO curtailed 2.4 million MWh of solar, costing IPPs an estimated $120M in lost revenue (CAISO 2023 Annual Report).

5. PTC/ITC Capture Rate (%)

Definition: For renewable IPPs, the percentage of available Production Tax Credits (PTCs) or Investment Tax Credits (ITCs) actually claimed. PTCs are worth $27.50/MWh (2024 inflation-adjusted) for wind, $30/MWh for solar if electing PTC.

Benchmark: >98%. Missed compliance windows due to late documentation or incorrect metering can destroy project economics.

Tool: Workday Adaptive Planning can model PTC revenue streams and flag compliance deadlines.

6. Debt Service Coverage Ratio (DSCR)

Definition: Net operating income (revenue minus OpEx) divided by total debt service (principal + interest). Lenders require DSCR >1.25x for project finance.

Why linked to Revenue/MWh: A 10% drop in Revenue/MWh can push DSCR below 1.0x, triggering covenant breaches. IPPs must forecast Revenue/MWh under multiple price scenarios using tools like Clari for revenue intelligence.

Real Operators

NextEra Energy Resources (NEE)

The largest renewable IPP in North America. Their 2023 average realized Revenue/MWh was $47/MWh across their 30 GW wind and solar fleet, with a hedge ratio of 85%. They use Salesforce Revenue Cloud to manage 2,000+ PPAs and Clari to forecast quarterly revenue within 2% accuracy.

Their secret: dynamic hedging using financial swaps in ERCOT and PJM, locking in prices 12–24 months forward.

Vistra Corp (VST)

A merchant IPP focused on gas and nuclear. Their 2023 Revenue/MWh was $62/MWh for their CCGT fleet, with a hedge ratio of 60% (higher merchant exposure). They use Clari to model merchant price scenarios and Workday for financial consolidation.

Their failure mode: in 2022, a 30% drop in gas prices caused Revenue/MWh to fall to $38/MWh, triggering a DSCR covenant waiver.

Clearway Energy Group (CWEN)

A yieldco with 8 GW of solar and wind. Their 2023 Revenue/MWh was $44/MWh, with a heavy PPA tilt (90% hedge ratio). They use Salesforce for asset management and Clari for revenue forecasting. Their key insight: PTC capture rate of 99.2% added $27/MWh to revenue, making their effective Revenue/MWh $71/MWh.

Failure Modes

Failure 1: Ignoring Negative Pricing Events

In ERCOT, negative LMPs occur when wind and solar oversupply the grid. In 2023, ERCOT saw 1,200 hours of negative pricing. IPPs that failed to curtail or hedge lost $5–$15/MWh on those hours. Real example: A 200 MW wind farm in West Texas lost $4.2M in Q2 2023 because its operator did not install real-time curtailment software.

Fix: Use Clari to monitor real-time LMP data and trigger automatic curtailment when prices drop below $0/MWh. Integrate with Salesforce to log curtailment events for PTC compliance.

Failure 2: Over-Hedging in Rising Markets

In 2021–2022, gas prices surged, pushing merchant power prices to $100+/MWh. IPPs with 90% hedge ratios at $40/MWh missed $60/MWh of upside. Example: A 500 MW CCGT plant in PJM lost $150M in potential revenue.

Fix: Use dynamic hedging with a 60–80% target range. Clari can model forward curves and recommend hedge adjustments monthly.

Failure 3: PTC Compliance Lapses

The IRS requires strict metering and documentation for PTCs. A single audit failure can claw back 3 years of credits. In 2022, a 100 MW solar farm in California lost $8M in PTCs because its meter was not calibrated quarterly.

Fix: Implement Salesforce Revenue Cloud with automated compliance checklists and audit trails. Set Clari alerts for quarterly meter certification deadlines.

Transmission constraints can cause node prices to diverge from hub prices by $10–$20/MWh. IPPs that ignore congestion lose margin. Real case: A 150 MW wind farm in SPP saw its Revenue/MWh drop from $38 to $22 due to unhedged congestion in 2023.

Fix: Purchase financial transmission rights (FTRs) or congestion revenue rights (CRRs). Use Clari to model congestion scenarios and hedge accordingly.

Reporting Cadence

Metric	Frequency	Tool	Owner
Revenue/MWh (actual)	Daily	Clari + Salesforce	Revenue Manager
Revenue/MWh (forecast)	Weekly	Clari	FP&A
Hedge Ratio	Monthly	Salesforce Revenue Cloud	Treasury
Curtailment Rate	Daily (real-time)	SCADA + Clari	Operations
PTC Capture Rate	Quarterly	Workday Adaptive Planning	Tax/Compliance
DSCR	Monthly	Workday	Finance

Best practice: IPPs should run a weekly revenue call using Clari to review actuals vs. Budget, focusing on merchant price deviations and curtailment trends. Monthly, reconcile Revenue/MWh against PPA settlements and forward curves.

30-60-90

First 30 Days: Baseline & Cleanse

Week 1: Pull 12 months of historical Revenue/MWh data from Salesforce and Clari. Calculate actual vs. Budget variance.
Week 2: Identify top 3 failure modes (e.g., negative pricing, congestion, PTC gaps). Document current hedge ratio.
Week 3: Set up Clari dashboards for daily Revenue/MWh tracking. Train team on real-time alerts.
Week 4: Present baseline to leadership with 3 quick wins (e.g., renegotiate PTC compliance process, add curtailment software).

Days 31–60: Optimize & Hedge

Week 5–6: Use Clari to model 3 merchant price scenarios (bull, base, bear). Recommend hedge ratio adjustments.
Week 7: Implement automated curtailment triggers in SCADA, integrated with Salesforce for logging.
Week 8: Reconcile PTC capture rate. Fix any meter calibration issues. Target 99%+.

Days 61–90: Institutionalize & Scale

Week 9–10: Build a monthly Revenue/MWh forecast model in Workday Adaptive Planning using Clari forward curves.
Week 11: Create a board-level dashboard showing Revenue/MWh, DSCR, and hedge ratio. Use Salesforce for governance.
Week 12: Run a stress test: simulate a 20% drop in merchant prices. Ensure DSCR stays above 1.25x. Document lessons learned.

flowchart TD A[30-Day Baseline] --> B[Identify Top 3 Failure Modes] B --> C[Set Up Clari Dashboards] C --> D[60-Day Optimization] D --> E[Model Merchant Scenarios] E --> F[Implement Curtailment Triggers] F --> G[90-Day Institutionalization] G --> H[Build Monthly Forecast Model] H --> I[Board Dashboard] I --> J[Stress Test DSCR]

flowchart LR subgraph Revenue/MWh Drivers A[PPA Price] --> D[Revenue/MWh] B[Merchant LMP] --> D C[Ancillary Services] --> D E[RECs] --> D F[PTCs] --> D end D --> G[Net Revenue] G --> H[DSCR] H --> I[Project Viability]

FAQ

What is the difference between Revenue/MWh and PPA price? PPA price is the contracted fixed or indexed price. Revenue/MWh adds merchant sales, ancillary services, RECs, and PTCs, minus curtailment and congestion costs. It is always lower than PPA price in practice.

How often should I calculate Revenue/MWh? Daily for operations, weekly for forecasting, monthly for financial reporting. Use Clari for real-time tracking.

What is a good Revenue/MWh for a solar farm in CAISO? $35–$50/MWh, but curtailment can reduce it to $25–$30. Hedge aggressively to avoid negative pricing.

How do PTCs affect Revenue/MWh? PTCs add $27.50–$30/MWh (2024 values). A wind farm with a $40/MWh PPA and $27/MWh PTC has an effective Revenue/MWh of $67/MWh.

What tools do top IPPs use to track Revenue/MWh? Clari for revenue forecasting, Salesforce Revenue Cloud for contract management, Workday Adaptive Planning for financial modeling, and SCADA for real-time generation data.

Can Revenue/MWh be negative? Yes. If LMP is negative (e.g., -$10/MWh) and you have no PTCs, your Revenue/MWh is negative. This happened to 15% of ERCOT wind farms in 2023.

How do I hedge against Revenue/MWh drops? Use financial swaps, options, and PPAs. Target a 70–90% hedge ratio. Clari can model optimal hedge strategies using forward curves.

Sources

Keep reading

![Revenue Per Megawatt-Hour (MWh) for Independent Power Producers](https://ners.engin.umich.edu/wp-content/uploads/sites/9/2025/12/Rafi-Graphic-896x1024.jpg)

### Direct Answer

**TL;DR:** Revenue Per Megawatt-Hour (MWh) for Independent Power Producers (IPPs) is the core metric that measures the average price received for each unit of electricity sold, net of all variable costs directly tied to generation. Unlike a simple PPA price, it accounts for merchant market exposure, ancillary service revenues, and production tax credits (PTCs). For a typical 200 MW wind farm, a healthy Revenue/MWh is $35–$55, while a combined-cycle gas turbine (CCGT) plant should target $45–$70. IPPs must track this KPI weekly and reconcile it against budget, using tools like **Clari** for revenue forecasting and **Salesforce Revenue Cloud** for contract-to-cash management. Failure to monitor Revenue/MWh leads to margin erosion from negative pricing events, curtailment penalties, and missed PTC compliance windows.

## Why Independent Power Producers Measure Differently

Independent Power Producers (IPPs) operate a fundamentally different business model than regulated utilities. A regulated utility earns a guaranteed return on equity (ROE) from ratepayers, with cost-plus pricing that insulates them from wholesale market volatility. An IPP, by contrast, sells electricity into competitive wholesale markets (e.g., PJM, ERCOT, CAISO, SPP) or under Power Purchase Agreements (PPAs) with fixed or indexed prices. Their revenue is entirely exposed to **locational marginal pricing (LMP)**, congestion patterns, and renewable intermittency.

The key difference: **Revenue/MWh for an IPP is not the PPA strike price.** It is the net realized price after accounting for:
- **Merchant sales** (spot market exposure)
- **Ancillary services** (frequency regulation, reserves, reactive power)
- **Renewable Energy Certificates (RECs)** and **Production Tax Credits (PTCs)**
- **Curtailment costs** (negative pricing events where you pay to produce)
- **Congestion and transmission losses**

A utility’s KPI might be “Revenue per Customer” or “Rate Base Growth.” An IPP’s survival depends on **Revenue/MWh** because it directly determines project IRR, debt service coverage ratios (DSCR), and ability to refinance. For example, a 100 MW solar farm in CAISO with a $40/MWh PPA might actually realize only $32/MWh after curtailment and congestion, making it non-viable. This is why IPPs must measure differently.

## The Most Important KPIs to Track

### 1. Revenue Per MWh (Core Metric)

**Definition:** Total gross revenue from electricity sales, ancillary services, RECs, and PTCs, divided by total MWh generated (net of station use). Formula: `(Energy Revenue + Ancillary Revenue + REC Revenue + PTC Value) / Net MWh Generated`.

**Benchmarks:**
- **Onshore Wind (US):** $35–$55/MWh (blended PPA + merchant)
- **Solar PV (utility-scale):** $30–$50/MWh
- **CCGT:** $45–$70/MWh
- **Battery Storage:** $80–$150/MWh (highly dependent on arbitrage and ancillary services)

**Why it matters:** This single number captures the effectiveness of your hedging strategy, PPA negotiation, and merchant optimization. If Revenue/MWh drops below your **Levelized Cost of Energy (LCOE)**, you are losing money on every MWh.

### 2. Hedge Ratio (%)

**Definition:** Percentage of expected generation covered by fixed-price PPAs or financial hedges (e.g., swaps, options). A 100% hedge ratio means zero merchant exposure.

**Benchmark:** 70–90% for investment-grade IPPs; 50–70% for growth-stage developers.

**Tool:** **Clari** can track hedge coverage against forward curves, alerting when ratios fall below board-approved thresholds. **Salesforce Financial Services Cloud** can manage PPA contract lifecycle.

### 3. Realized Price vs. Day-Ahead Index

**Definition:** The spread between your actual settlement price and the day-ahead LMP at your node. Negative spread indicates curtailment or congestion losses.

**Benchmark:** Should be within ±$2/MWh for a well-hedged, non-congested node. A persistent negative spread >$5/MWh signals a structural problem (e.g., transmission constraints, bad PPA location).

### 4. Curtailment Rate (%)

**Definition:** MWh curtailed (dispatched down) divided by total available MWh. Renewable IPPs face curtailment when grid operators order them offline due to oversupply or congestion.

**Benchmark:** <5% for wind, <3% for solar in well-interconnected regions. In ERCOT or CAISO, rates can spike to 15%+ during spring solar oversupply.

**Real number:** In 2023, CAISO curtailed 2.4 million MWh of solar, costing IPPs an estimated $120M in lost revenue (CAISO 2023 Annual Report).

### 5. PTC/ITC Capture Rate (%)

**Definition:** For renewable IPPs, the percentage of available Production Tax Credits (PTCs) or Investment Tax Credits (ITCs) actually claimed. PTCs are worth $27.50/MWh (2024 inflation-adjusted) for wind, $30/MWh for solar if electing PTC.

**Benchmark:** >98%. Missed compliance windows due to late documentation or incorrect metering can destroy project economics.

**Tool:** **Workday Adaptive Planning** can model PTC revenue streams and flag compliance deadlines.

### 6. Debt Service Coverage Ratio (DSCR)

**Definition:** Net operating income (revenue minus OpEx) divided by total debt service (principal + interest). Lenders require DSCR >1.25x for project finance.

**Why linked to Revenue/MWh:** A 10% drop in Revenue/MWh can push DSCR below 1.0x, triggering covenant breaches. IPPs must forecast Revenue/MWh under multiple price scenarios using tools like **Clari** for revenue intelligence.

## Real Operators

### NextEra Energy Resources (NEE)
The largest renewable IPP in North America. Their 2023 average realized Revenue/MWh was **$47/MWh** across their 30 GW wind and solar fleet, with a hedge ratio of 85%. They use **Salesforce Revenue Cloud** to manage 2,000+ PPAs and **Clari** to forecast quarterly revenue within 2% accuracy. Their secret: dynamic hedging using financial swaps in ERCOT and PJM, locking in prices 12–24 months forward.

### Vistra Corp (VST)
A merchant IPP focused on gas and nuclear. Their 2023 Revenue/MWh was **$62/MWh** for their CCGT fleet, with a hedge ratio of 60% (higher merchant exposure). They use **Clari** to model merchant price scenarios and **Workday** for financial consolidation. Their failure mode: in 2022, a 30% drop in gas prices caused Revenue/MWh to fall to $38/MWh, triggering a DSCR covenant waiver.

### Clearway Energy Group (CWEN)
A yieldco with 8 GW of solar and wind. Their 2023 Revenue/MWh was **$44/MWh**, with a heavy PPA tilt (90% hedge ratio). They use **Salesforce** for asset management and **Clari** for revenue forecasting. Their key insight: PTC capture rate of 99.2% added $27/MWh to revenue, making their effective Revenue/MWh $71/MWh.

## Failure Modes

### Failure 1: Ignoring Negative Pricing Events
In ERCOT, negative LMPs occur when wind and solar oversupply the grid. In 2023, ERCOT saw 1,200 hours of negative pricing. IPPs that failed to curtail or hedge lost $5–$15/MWh on those hours. **Real example:** A 200 MW wind farm in West Texas lost $4.2M in Q2 2023 because its operator did not install real-time curtailment software.

**Fix:** Use **Clari** to monitor real-time LMP data and trigger automatic curtailment when prices drop below $0/MWh. Integrate with **Salesforce** to log curtailment events for PTC compliance.

### Failure 2: Over-Hedging in Rising Markets
In 2021–2022, gas prices surged, pushing merchant power prices to $100+/MWh. IPPs with 90% hedge ratios at $40/MWh missed $60/MWh of upside. **Example:** A 500 MW CCGT plant in PJM lost $150M in potential revenue.

**Fix:** Use dynamic hedging with a 60–80% target range. **Clari** can model forward curves and recommend hedge adjustments monthly.

### Failure 3: PTC Compliance Lapses
The IRS requires strict metering and documentation for PTCs. A single audit failure can claw back 3 years of credits. In 2022, a 100 MW solar farm in California lost $8M in PTCs because its meter was not calibrated quarterly.

**Fix:** Implement **Salesforce Revenue Cloud** with automated compliance checklists and audit trails. Set **Clari** alerts for quarterly meter certification deadlines.

### Failure 4: Congestion Blind Spots
Transmission constraints can cause node prices to diverge from hub prices by $10–$20/MWh. IPPs that ignore congestion lose margin. **Real case:** A 150 MW wind farm in SPP saw its Revenue/MWh drop from $38 to $22 due to unhedged congestion in 2023.

**Fix:** Purchase financial transmission rights (FTRs) or congestion revenue rights (CRRs). Use **Clari** to model congestion scenarios and hedge accordingly.

## Reporting Cadence

| Metric | Frequency | Tool | Owner |
|--------|-----------|------|-------|
| Revenue/MWh (actual) | Daily | **Clari** + **Salesforce** | Revenue Manager |
| Revenue/MWh (forecast) | Weekly | **Clari** | FP&A |
| Hedge Ratio | Monthly | **Salesforce Revenue Cloud** | Treasury |
| Curtailment Rate | Daily (real-time) | SCADA + **Clari** | Operations |
| PTC Capture Rate | Quarterly | **Workday Adaptive Planning** | Tax/Compliance |
| DSCR | Monthly | **Workday** | Finance |

**Best practice:** IPPs should run a **weekly revenue call** using **Clari** to review actuals vs. Budget, focusing on merchant price deviations and curtailment trends. Monthly, reconcile Revenue/MWh against PPA settlements and forward curves.

## 30-60-90

### First 30 Days: Baseline & Cleanse
- **Week 1:** Pull 12 months of historical Revenue/MWh data from **Salesforce** and **Clari**. Calculate actual vs. Budget variance.
- **Week 2:** Identify top 3 failure modes (e.g., negative pricing, congestion, PTC gaps). Document current hedge ratio.
- **Week 3:** Set up **Clari** dashboards for daily Revenue/MWh tracking. Train team on real-time alerts.
- **Week 4:** Present baseline to leadership with 3 quick wins (e.g., renegotiate PTC compliance process, add curtailment software).

### Days 31–60: Optimize & Hedge
- **Week 5–6:** Use **Clari** to model 3 merchant price scenarios (bull, base, bear). Recommend hedge ratio adjustments.
- **Week 7:** Implement automated curtailment triggers in SCADA, integrated with **Salesforce** for logging.
- **Week 8:** Reconcile PTC capture rate. Fix any meter calibration issues. Target 99%+.

### Days 61–90: Institutionalize & Scale
- **Week 9–10:** Build a monthly Revenue/MWh forecast model in **Workday Adaptive Planning** using **Clari** forward curves.
- **Week 11:** Create a board-level dashboard showing Revenue/MWh, DSCR, and hedge ratio. Use **Salesforce** for governance.
- **Week 12:** Run a stress test: simulate a 20% drop in merchant prices. Ensure DSCR stays above 1.25x. Document lessons learned.

```mermaid
flowchart TD
    A[30-Day Baseline] --> B[Identify Top 3 Failure Modes]
    B --> C[Set Up Clari Dashboards]
    C --> D[60-Day Optimization]
    D --> E[Model Merchant Scenarios]
    E --> F[Implement Curtailment Triggers]
    F --> G[90-Day Institutionalization]
    G --> H[Build Monthly Forecast Model]
    H --> I[Board Dashboard]
    I --> J[Stress Test DSCR]
```

```mermaid
flowchart LR
    subgraph Revenue/MWh Drivers
        A[PPA Price] --> D[Revenue/MWh]
        B[Merchant LMP] --> D
        C[Ancillary Services] --> D
        E[RECs] --> D
        F[PTCs] --> D
    end
    D --> G[Net Revenue]
    G --> H[DSCR]
    H --> I[Project Viability]
```

## FAQ

**What is the difference between Revenue/MWh and PPA price?**
PPA price is the contracted fixed or indexed price. Revenue/MWh adds merchant sales, ancillary services, RECs, and PTCs, minus curtailment and congestion costs. It is always lower than PPA price in practice.

**How often should I calculate Revenue/MWh?**
Daily for operations, weekly for forecasting, monthly for financial reporting. Use **Clari** for real-time tracking.

**What is a good Revenue/MWh for a solar farm in CAISO?**
$35–$50/MWh, but curtailment can reduce it to $25–$30. Hedge aggressively to avoid negative pricing.

**How do PTCs affect Revenue/MWh?**
PTCs add $27.50–$30/MWh (2024 values). A wind farm with a $40/MWh PPA and $27/MWh PTC has an effective Revenue/MWh of $67/MWh.

**What tools do top IPPs use to track Revenue/MWh?**
**Clari** for revenue forecasting, **Salesforce Revenue Cloud** for contract management, **Workday Adaptive Planning** for financial modeling, and **SCADA** for real-time generation data.

**Can Revenue/MWh be negative?**
Yes. If LMP is negative (e.g., -$10/MWh) and you have no PTCs, your Revenue/MWh is negative. This happened to 15% of ERCOT wind farms in 2023.

**How do I hedge against Revenue/MWh drops?**
Use financial swaps, options, and PPAs. Target a 70–90% hedge ratio. **Clari** can model optimal hedge strategies using forward curves.

## Sources

- [CAISO 2023 Annual Report on Curtailment](https://www.caiso.com/Documents/2023AnnualReportonCurtailment.pdf)
- [EIA Levelized Cost of Energy (LCOE) Data](https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf)
- [NextEra Energy 2023 Investor Presentation (Revenue/MWh disclosure)](https://www.nexteraenergy.com/investors/presentations.html)
- [Clari Revenue Intelligence for IPPs](https://www.clari.com/solutions/energy)
- [Salesforce Revenue Cloud for PPA Management](https://www.salesforce.com/products/revenue-cloud/)
- [Workday Adaptive Planning for Energy Financial Modeling](https://www.workday.com/en-us/products/adaptive-planning.html)
- [ERCOT 2023 Negative Pricing Report](https://www.ercot.com/files/docs/2023/12/01/NegativePricingReport2023.pdf)
- [IRS PTC Compliance Guidelines (Section 45)](https://www.irs.gov/credits-deductions/renewable-electricity-production-tax-credit)

Was this helpful?

Related in the library