Sign in

You're signed outSign in or to get full access.

VG

Venture Global, Inc. (VG)·Q3 2025 Earnings Summary

Executive Summary

  • Q3 2025 delivered record LNG operations and top‐line growth: revenue $3.33B (+260% YoY) and Consolidated Adjusted EBITDA $1.53B (+439% YoY); Q3 EPS was $0.16 as arbitration reserves and swap losses weighed on GAAP earnings .
  • Results vs Street: Revenue beat ($3.33B vs $3.26B*) but EPS missed ($0.16 vs $0.234*); similar pattern in Q2 (rev beat/EPS miss) and Q1 (rev miss/EPS miss)*. Management tightened FY25 EBITDA guidance to $6.35–$6.50B (from $6.40–$6.80B) and cut price sensitivity materially .
  • Operational momentum: 100 cargos in Q3 (372 TBtu), with 64 commissioning cargos from Plaquemines (weighted avg fixed LNG fee $6.79/MMBtu) and 36 cargos from Calcasieu Pass (weighted avg fixed fee $1.76/MMBtu, adjusted for arbitration reserve) .
  • Strategic catalysts: 5.25 MTPA of new 20‑year SPAs in 2H’25; CP2 Phase 1 FID and DOE non‑FTA authorization; $2B corporate revolver and Blackfin pipeline JV monetization bolster liquidity .

Note: All starred items (*) are values retrieved from S&P Global.

What Went Well and What Went Wrong

What Went Well

  • Record volumes and EBITDA: 100 cargos (372 TBtu), Consolidated Adjusted EBITDA $1.53B; YoY step‑change from Plaquemines ramp (34 of 36 trains producing) .
  • Commercial wins: 5.25 MTPA of new 20‑year SPAs in 2H’25 (Naturgy 1.0, Atlantic‑SEE 0.5; PETRONAS 1.0; SEFE +0.75; Eni 2.0), supporting CP2 Phase 2 path to FID .
  • Liquidity and financing: $2B corporate revolver; Blackfin JV raised $1.575B and returned $889M; CP2 Phase 1 project financing $15.1B closed; Plaquemines $4.0B notes .

Select quote: “We are…on track to reach COD at Phase 1 in 54 months…Our record of execution positions Venture Global as an important leader in the LNG market” — CEO Mike Sabel .

What Went Wrong

  • EPS pressure: Despite strong operations, GAAP EPS impacted by swap losses and a $27M non‑cash arbitration reserve at Calcasieu Pass; diluted EPS $0.16 missed consensus* .
  • Guidance trim: FY25 Consolidated Adjusted EBITDA guidance reduced to $6.35–$6.50B (from $6.40–$6.80B) on lower fixed fee assumptions, DES timing, and arbitration reserves .
  • Arbitration overhang: Partial adverse award in BP case (damages not yet determined); remaining customer claims now $4.8–$5.5B (down from $6.7–$7.4B) with aggregate caps of $765M for four proceedings (ex‑BP) .

Financial Results

Headline metrics vs prior periods and estimates

MetricQ1 2025Q2 2025Q3 2025
Revenue (Actual, $B)$2.894 $3.101 $3.329
Revenue Consensus Mean ($B)*$2.969$2.971$3.259
Income from Operations ($B)$1.080 $1.038 $1.320
Net Income Attrib. to Common ($B)$0.396 $0.368 $0.429
Diluted EPS (Actual, $)$0.15 $0.14 $0.16
Primary EPS Consensus Mean ($)*$0.276$0.192$0.234
Consolidated Adjusted EBITDA ($B, non‑GAAP)$1.346 $1.393 $1.525
  • Q3 revenue beat and EPS miss vs consensus; Q2 showed the same pattern; Q1 missed both revenue and EPS*.

LNG operations and pricing KPIs

KPIQ3 2024Q2 2025Q3 2025
Cargos Exported (Total)31 89 100
LNG Volumes Exported (TBtu)110.4 331 371.8
LNG Volumes Sold (TBtu)100.0 329 373.0

Facility breakdown (Q3 2025)

FacilityCargosTBtuWeighted Avg Fixed Fee ($/MMBtu)
Calcasieu Pass36133.0$1.76 (adjusted for reserve)
Plaquemines64238.8$6.79

Additional note: Overall weighted fixed fee in Q3 across facilities was $5.07/MMBtu (company 8‑K interim KPI) .

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Consolidated Adjusted EBITDAFY 2025$6.40–$6.80B $6.35–$6.50B Lowered/tightened
Fee Sensitivity per ±$1/MMBtuFY 2025$230–$240MM $50–$60MM Reduced materially
Calcasieu Pass cargosFY 2025144–149 148 Narrowed
Plaquemines cargosFY 2025227–240 234–238 Narrowed
Fixed fee assumption (remaining unsold cargos)FY 2025$6.00–$7.00/MMBtu $4.50–$5.50/MMBtu Lowered
Total cargos across projectsFY 2025367–389 (prior range) 382–386 (expectation) Updated outlook

Drivers cited: lower assumed fixed fees on unsold cargos (higher Henry Hub vs flat TTF compressing spreads), two DES loadings shifting revenue recognition into early 2026, and arbitration reserve accruals .

Earnings Call Themes & Trends

TopicPrevious Mentions (Q1 & Q2 2025)Current Period (Q3 2025)Trend
ArbitrationQ2: Shell ruled in VG’s favor; multiple cases ongoing .Partial adverse BP liability finding (damages TBD); remaining claims reduced to $4.8–$5.5B; non‑cash reserve $14–$15M/quarter going forward; liquidity ample to manage range of outcomes .Ongoing but quantified; reserve cadence outlined.
Plaquemines ramp & powerQ1/Q2: 18–28 trains producing; 400MW temporary power mitigates power island delays .34 of 36 trains producing; 64 Q3 cargos; Phase 1 power island commissioning to begin 5‑on‑2 in Q1’26; COD Phase 1 Q4’26, Phase 2 mid‑’27 reaffirmed .Execution ahead of plan, visibility improved.
CP2 progress & returnsQ1: DOE non‑FTA authorization; $3B pre‑FID loan; targeting FID mid‑year . Q2: Phase 1 FID $15.1B; contracting momentum .Non‑FTA final authorization; 99% engineering; >98% procurement; illustrative EBITDA $4–$5.2B post‑COD at $4–$6 fees on available capacity; >30% ROE scenario .Strengthening execution and economics.
LNG market & spreadsQ1/Q2: healthy spreads, storage needs, rising Asia demand .Winter spreads compressed vs hub; still supportive; VG’s output mitigated European demand surge; long‑term demand growth thesis intact (AI/data centers, coal‑to‑gas) .Near‑term compression; long‑term bullish.
Contracting/portfolioQ1/Q2: Active 20‑yr SPA pipeline; plan to contract more than previously .5.25 MTPA of new 20‑yr SPAs in 2H; exploring portfolio structures leveraging excess capacity; 89% of Q4 cargoes pre‑sold .Momentum accelerating.
Data/AI ops—Company streaming ~222k datapoints every 10s at CP1; data science used for performance optimization; expect CP2 to hit ~30 MTPA with optimizations .New disclosure; structural efficiency lever.

Management Commentary

  • Prepared remarks emphasized operational execution, contracting momentum, and liquidity: “100 cargoes…$3.3B of revenue…$1.5B of consolidated adjusted EBITDA…we are marginally reducing and tightening the range of our EBITDA guidance” — CEO .
  • On arbitration: “Including BP, the remedies sought…have been materially reduced to $4.8–$5.5 billion…aggregate liability cap…is now $765 million” — CEO .
  • On Plaquemines schedule: “We maintain our expected COD schedule of Q4 2026 [Phase 1]…mid‑2027 [Phase 2]…34 of the 36 liquefaction trains” — CEO .
  • On liquidity: “Cash and restricted cash…over $3.5 billion…new $2 billion corporate revolver…excellent liquidity position” — CFO .
  • On CP2 returns: “Assuming a $4 fee…~$4B EBITDA; $6 fee…$5.2B…imply a return…on equity of greater than 30%” — CEO .

Q&A Highlights

  • Arbitrations and funding: Management outlined non‑cash reserve run‑rate ($14–$15M/quarter), strong liquidity and asset base to manage potential damages over time; damages in BP case not yet determined .
  • Contracting/pricing: No impact from BP ruling on SPA momentum; pricing for remaining 2025 cargos guided to fixed fees $4.50–$5.50/MMBtu; portfolio flexibility across facilities is a differentiator .
  • Operations cadence: Calcasieu maintenance elongated in Q3 but minimal production impact due to modular redundancy; Plaquemines power island commissioning timing supports COD .
  • Strategic positioning: Brownfield expansions prioritized ahead of CP3; large expected excess production capacity enables medium/short‑term sales optionality .

Estimates Context

  • Quarterly comparison to S&P Global consensus:
MetricQ1 2025Q2 2025Q3 2025
Revenue (Actual, $B)$2.894 $3.101 $3.329
Revenue Consensus Mean ($B)*$2.969$2.971$3.259
EPS (Diluted/Primary) Actual ($)$0.15 $0.14 $0.16
Primary EPS Consensus Mean ($)*$0.276$0.192$0.234
  • Interpretation: Q3 revenue beat and EPS miss; Q2 revenue beat and EPS miss; Q1 revenue and EPS both missed*. Likely estimate revisions: modest upward revisions to revenue trajectory given sustained volume ramp; EPS revisions could skew down short‑term given arbitration reserve cadence and swap impacts, but non‑cash nature tempers medium‑term implications .

Note: All starred items (*) are values retrieved from S&P Global.

Key Takeaways for Investors

  • Strong operational delivery is intact: 100 cargos in Q3 and 372 TBtu underscore Plaquemines ramp and support continued top‑line beats even as spreads compressed into winter .
  • Near‑term headwinds to GAAP EPS persist (arbitration reserves, swap marks), but are largely non‑cash; cash/liquidity profile strengthened via revolver and asset monetization .
  • Guidance was prudently tightened, sensitivity to spreads cut materially (from ~$235MM to ~$55MM per $1 fee), reflecting higher contracted coverage and reduced price exposure .
  • Contracting momentum (5.25 MTPA 20‑yr SPAs in 2H) and CP2 execution (99% engineering; DOE non‑FTA) enhance medium‑term EBITDA growth visibility .
  • Watch arbitration milestones: BP damages process timing and outcomes for four remaining cases (with aggregate caps) are key stock narrative variables; management expects staggered timelines into 2026 .
  • Tactical trading lens: Revenue beats vs EPS misses could create mixed reactions on prints; catalysts include additional SPAs, CP2 construction milestones, and arbitration updates.
  • Medium‑term thesis: Scale, modular execution, and portfolio optionality (excess capacity) position VG to deliver structurally advantaged returns across cycles as LNG demand remains robust .

Sources

  • Q3 2025 8‑K (press release and tables) .
  • Q3 2025 earnings call transcript .
  • Earnings slides Q3 2025 .
  • Interim KPI 8‑K (Oct 6, 2025) .
  • Q2 2025 8‑K and call .
  • Q1 2025 8‑K and call .

Note on estimates: Values retrieved from S&P Global.