Capex ramped, earnings stumbled; transmission delays push renewables to FY28

Adjusted thermal PBT down ₹123 Cr YoY; merchant sales & LNG trading lower ₹87 Cr; LNG at USD20/MMBtu constraining sales to 2–3 hrs/day peak market

₹41 Cr from regulatory carrying cost, ₹19 Cr from operations (ROE/ROCE boost, tariff increases), ₹11 Cr from new transmission; volumes up 4% YoY (guidance was 5–6% demand growth)

Down from prior guidance of 1.2–1.5 GW; now 1.0–1.2 GW. Reason: transmission line ROW delays (external). Phased to FY28 (1.4–1.6 GW). Multi-year plan (4.6 GW) intact

Q1 capex ₹2,300 Cr (6.5x YoY vs ₹355 Cr Q1 FY26); ₹10,000 Cr guided for FY27 RE projects (vs ₹1,200 Cr in Q4 FY26). Capex acceleration validated

Management projects gas variable cost ₹4–4.5 (at $6–$8/MMBtu) vs ₹5–5.5 battery (₹2–2.5 solar + ₹3 battery). But current LNG USD20 makes only high-DAM sales viable for 2–3 hrs/day

Prior guidance 1.2–1.5 GW → now 1.0–1.2 GW. Phased to FY28 (1.4–1.6 GW) due to transmission line delays (ROW issues, PGCIL-led). Multi-year (4.6 GW) intact.

LNG prices remain elevated (USD20/MMBtu). Market access limited to high-DAM peak hours (2–3 hrs/day). Structural headwind, not a quarter-specific anomaly.

Section 80-IA tax holiday expired for some units. Permanent increase from 25% → 28%. No offset announced.

Closed June 25, 2026; ₹15 Cr profit in 5 days (immaterial in Q1). Expected ₹1,000 Cr EBITDA annually on steady state. Material accretion (₹250 Cr quarterly run-rate).

Q1 capex ₹2,300 Cr (6.5x YoY); ₹10,000 Cr guided for FY27. In line with prior 'accelerated run rate' guidance. Execution strong.

UP franchise now expected post-election (was originally targeted earlier). Possible Maharashtra traction. No concrete near-term closures.

5 days operation = ₹15 Cr profit booked. Gross debt added ₹6–6.5 Cr (₹3 Cr Nabha book, ₹3.8 Cr Torrent book). Steady-state EBITDA ₹1,000 Cr annually.

Prior year Q1 had ₹47 Cr LPS (late payment surcharge) income, unavailable this quarter. Excluding that, EBITDA up ₹66 Cr on standalone basis.

Ahmedabad benchmark to national average. Surat/Dahej industrial, growth naturally lower. DNHDD exceptional (one-off). AT&C losses up in Agra (prior year had special collections reducing loss).

Peak demand always present; period prolonging. Summer demand supports merchant sales for untied capacity. Long-term gas at $6–$8/MMBtu competitive vs battery. Current USD20 temporary.

Transmission line availability is bottleneck (ROW issues, PGCIL delays). After factoring these issues, 1.2 GW target is reasonable estimate; will update quarterly if risks materialize.

Q1: 70 MW. Q2: ~400 MW. H2: ~800 MW. Total ~1.2 GW on track.

Land not yet finalized, may not be Gujarat. Coal allocation pending central govt approval. Work-in-progress; firm plan once coal approved.

Participate almost all bids but restrict to mid-teen IRR minimum. Benchmark is IRR, not capacity acquisition. Disciplined approach continues.

Variable cost ₹4–4.5 (at $6–$8/MMBtu) vs ₹5–5.5 battery (solar + storage). Gas competitive long-term. Cannot hedge gas prices long-term, so no PPA strategy with C&I/data centers.

Q1 LPS ₹46 Cr; same for full FY26. All ₹46 Cr was in Q1 FY26. Unlikely full-year FY27.

Transmission line availability is primary driver. Plan execution around transmission line commissioning to avoid capex ahead of transmission.

Nabha typically 85% PLF. Salary cost reduction likely one-off from capitalization of salary costs, not structural.

3 cargos for summer demand acquired and being used. Spot cargo USD20 (not affordable). FY27+ have 10-cargo contract linked to Brent (not spot). Import selectively for price/demand alignment.

₹2,300 Cr total. RE: ₹1,550 Cr. Thermal coal: ₹125 Cr. Transmission: ₹120 Cr. Distribution: ₹500 Cr.

UP expected post-election. Maharashtra possibly. No concrete franchises right now.

USD20 variable cost ₹13; regular market capped ₹10. Only high-DAM viable, 2–3 hrs/day, not continuous. Very challenging. Flexibilization investments enable this model.

4.6 GW renewable pipeline + Nabha (₹1,000 Cr EBITDA) + distribution growth; overall capacity mix supports mid-single-digit revenue CAGR, but LNG prices and merchant power headwinds offset.

OPM likely stable 18–19% (distribution high-margin, thermal pressured). NPM capped by 28% tax rate; PAT conversion weaker than prior years despite operational improvements.

Accelerated run-rate validated by Q1 (₹2,300 Cr all capex). Transmission ₹120 Cr, distribution ₹500 Cr, thermal ₹125 Cr; RE bulk.

LNG spot at USD20/MMBtu; variable cost ₹13 vs regular market cap ₹10. Only viable in high-DAM 2–3 hrs/day. Merchant sales ₹87 Cr lower YoY. Battery competition rising.

FY27 renewable target reduced 1.5 GW → 1.2 GW due to transmission line delays (ROW issues, PGCIL-led). SECI 12, SECI 16 wind projects extended to FY28. Capex is committed but timing slipped.

Section 80-IA tax holiday expired for some units; effective tax rate stepped from 25% to 28%. Permanent structural headwind on PAT conversion; no mitigation announced.

UP franchise tender expected post-election (timeline vague). Maharashtra traction unclear. Limits near-term distribution growth acceleration above +4% volume growth.

Distribution volumes +4% YoY vs prior guidance of 5–6% power demand growth. Ahmedabad (10%) is benchmark; industrial areas (Surat, Dahej) showing muted growth. Risk if national demand disappoints.