🇩🇪Germany

Fehlende Transparenz in Terminierungsentscheidungen und Spread-Monitoring

1 verified sources

Definition

Gas supply procurement teams must nominate (Terminierung) gas into storage and distribution networks based on expected spreads and price forecasts. Current market spreads (€1.42/MWh Summer-Winter differential) are insufficient to justify injections. Yet manual monitoring of TTF contracts, cross-exchange spreads, and regulatory constraints (90%/95% filling mandates) creates decision delays and missed opportunities. INES publicly questioned whether market signals are sufficient—indicating that operators themselves lack visibility into optimal nomination strategies.

Key Findings

  • Financial Impact: 2–5% of procurement efficiency loss = €2.3–5.8 billion × 0.02–0.05 = €46–290 million annually (estimated German market procurement volatility)
  • Frequency: Daily (nomination cycles); Weekly (strategic reviews)
  • Root Cause: Fragmented data sources (TTF, PEGAS, THE, EEX); Manual spread analysis and forecasting; Regulatory compliance overhead obscuring economic signals; No integrated procurement decision-support system

Why This Matters

This pain point represents a significant opportunity for B2B solutions targeting Natural Gas Distribution.

Affected Stakeholders

Gas Procurement Specialists, Portfolio Managers, Nomination Clerks, Risk Managers

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Financial Impact

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Current Workarounds

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Methodology & Sources

Data collected via OSINT from regulatory filings, industry audits, and verified case studies.

Evidence Sources:

Related Business Risks

Erzwungene Speicherauffüllung unter unwirtschaftlichen Bedingungen

€145–290 million annually (€0.58/MWh × 250,000 GWh ÷ 2 conservative absorption factor); Variable by winter severity and spread trajectory

Regulatorische Gebühren und Konversionsneutraliätsgebühr

€6–8 million annually across German gas market (estimated at 1,500 TJ/d average demand; ~547 bcm/year)

Kontrahierungsverluste durch erzwungene Spotmarkt-Beschaffung

Uniper: 'large losses accumulating on a daily basis' (exact amount not disclosed in source but characterized as 'huge'; estimated €100M-500M+ annually based on typical spot-price premium multiples × 200 TWh exposure)

Genehmigungsverzögerungen und Kapazitätsabbau bei Kraftwerksausbau

€150–300M in sunk planning costs + 12-month expansion delay; equivalent to ~2–5% of planned capex

Administrative Lasten aus neuen Verteilernetzentwicklungsplänen (VNEP)

€5–15M annual operational burden; estimated 40–80 FTE hours per operator per VNEP cycle (600+ distribution operators nationally)

Fehlentscheidungen bei Gasturbinen-Ausbau durch unzureichende Szenarioanalyse

€2–5B potential subsidy/capex misallocation; €50–100M annual planning inefficiency across sector

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