ERCOT Costs & Deliverability

ERCOT GIM Cost Framework

1

FDS Study Fee

$350/MW for large generators (>20 MW). Non-refundable. ERCOT recovers full study cost. Included in Application package. GIM application deposit: $5,000. Queue position set at application receipt.

PUCT Subst. R. 25.174

2

Direct Facilities (DF)

Generator lead, step-up transformer, protection relay, revenue metering at POI substation. Directly assigned to developer. Developer bids and selects contractor — not TSP-managed. Typical cost: $3–30M depending on distance to POI and interconnection voltage.

ERCOT Nodal Protocols §5.3.2

3

Network Upgrades (NU)

Transmission upgrades triggered by the project beyond the POI substation. If shared with other projects, TSP allocates pro-rata. Not security-backed like DF costs. Typical: $10–150M in congested West Texas areas.

ERCOT Nodal Protocols §5.3.3

4

CPCN Costs (if applicable)

If project requires a new transmission line >60kV, developer must fund or co-fund PUCT CPCN filing. Legal, engineering, PUC docket: $500k–$2M. Timeline: 12–18 months for PUCT approval. No FERC filing required.

PURA §37.051 — CPCN

5

Construction Security

Posted with TSP before construction authorization. Must cover 100% of Direct Facilities (DF) costs. Not required for Network Upgrades (TSP-socialized). Refunded within 60 days of commercial operation, net of cost overruns.

PUCT Subst. R. 25.192

ERCOT Cost Benchmarks by Technology & Zone

Technology	Zone	FDS Fee	Direct Facilities	Network Upgrades (est.)	Total Range
Onshore Wind	WEST	$350/MW	$5–15M	$15–60M	$20–75M
Onshore Wind	NORTH	$350/MW	$3–10M	$5–30M	$8–40M
Utility Solar	WEST / FAR WEST	$350/MW	$4–12M	$20–80M	$24–92M
Utility Solar	NORTH / SOUTH	$350/MW	$3–10M	$8–35M	$11–45M
Solar + BESS	WEST / NORTH	$350/MW	$5–18M	$20–90M	$25–108M
Standalone BESS	All zones	$350/MW	$2–8M	$3–20M	$5–28M
Gas Peaker	Any	$350/MW	$5–20M	$5–30M	$10–50M

Technology

Zone

FDS Fee

Direct Facilities

Network Upgrades (est.)

Total Range

Onshore Wind

WEST

$350/MW

$5–15M

$15–60M

$20–75M

Onshore Wind

NORTH

$350/MW

$3–10M

$5–30M

$8–40M

Utility Solar

WEST / FAR WEST

$350/MW

$4–12M

$20–80M

$24–92M

Utility Solar

NORTH / SOUTH

$350/MW

$3–10M

$8–35M

$11–45M

Solar + BESS

WEST / NORTH

$350/MW

$5–18M

$20–90M

$25–108M

Standalone BESS

All zones

$350/MW

$2–8M

$3–20M

$5–28M

Gas Peaker

Any

$350/MW

$5–20M

$5–30M

$10–50M

Negative LMP Risk & Basis Management

Basis Risk

West Texas Basis Discount

WEST zone LMP averages $22/MWh vs. NORTH hub at $42/MWh — a $20/MWh basis differential. For a wind project in far West Texas, effective realized price after congestion rent can be $5–15/MWh. PPA structures must account for nodal vs. hub pricing differentials. Hub-settled PPAs common but leave basis risk with developer.

ERCOT Historical LMP Analysis 2023

Hedging

Congestion Revenue Rights (CRRs)

ERCOT's CRR market allows generators to hedge nodal basis risk. CRRs are financial instruments that pay the difference between the project's settlement node LMP and a zone hub. Annual CRR auctions are competitive — capacity often insufficient to fully hedge basis. Typically available in 1- and 10-year strips.

ERCOT CRR Protocols §7.5

Curtailment

Negative LMPs — West Zone

WEST zone experiences negative LMPs approximately 15% of annual hours. Wind curtailment or negative price periods can significantly reduce project revenue — wind projects in far West Texas can see realized values near $0/MWh during congested periods. Co-locating BESS is the dominant mitigation strategy for new projects.

ERCOT CDR Congestion Data 2022–2024

Pricing

Zone Hub vs. Settlement Node

ERCOT has 4 zone settlement hubs (NORTH, SOUTH, WEST, HOUSTON) and ~8,500 generation settlement nodes. Contracts typically reference zone hubs. Nodal price at a specific substation can differ $5–30/MWh from zone hub due to local congestion. Projects should model both hub and node price paths in financial models.

ERCOT Nodal Protocols §4.5 — Settlement

ERCOT vs. FERC-Regulated ISOs — Key Differences

Timeline

Fastest Interconnection in the US

ERCOT FDS (Facilities Design Study): ~45 days. GIA execution: 30 days. Total time from application to signed agreement: 3–6 months. Compare: PJM or MISO cluster study process: 18–36 months. This speed advantage is a significant competitive benefit for Texas-based projects.

ERCOT GIM Process Guide 2024

Appeals

Regulatory Appeal — Texas Courts Only

ERCOT disputes go to PUCT ALJ (Administrative Law Judge), then PUCT Commission, then Texas District Court and Texas Supreme Court. No FERC appeal possible. Developers who disagree with interconnection cost allocations or study results have no federal recourse — Texas-only judicial review.

PURA §39.151 — PUCT Appeals Process

Transparency

Cost Data Publicly Available

ERCOT publishes FDS results and Network Upgrade cost estimates on its public portal (ercot.com/services/comm/queuemgmt). More transparent than most ISO/RTOs. Developer community can view aggregate cost data by substation. Historical FDS results are searchable by project.

ERCOT GIM Portal — ercot.com

Market Risk

No Capacity Market — Pure Energy Risk

Unlike FERC-regulated ISOs, ERCOT has no capacity market safety net. Project economics depend entirely on energy + ancillary service revenues. High LMP volatility ($-100 to $5,000/MWh) creates significant merchant risk. Revenue stacking (energy + AS + CRRs) is essential for project viability. PPA structures more complex as a result.

ERCOT Market Information 2024