# 1. Financial Performance ## A. Key Figures * **Realized Gas Price:** **$7.54/MMBtu** (vs. $8.45/MMBtu prior) * Stand-alone Revenue: **₹83.48 Cr** (vs. ₹142.61 Cr prior, including ₹46.98 Cr and ₹12.25 Cr in adjustments) * Consolidated Revenue from Operations: **₹85.5 Cr** (vs. ₹85.54 Cr prior, post-adjustments) * **Consolidated EBITDA:** **₹35 Cr** (ex. adjustments, vs. ₹39 Cr prior) * Standalone EBITDA: **₹27.24 Cr** (vs. ₹24.38 Cr prior, adj.) * Standalone PAT: **₹48.21 Cr** (vs. ₹130 Cr prior, including year-end adjustments) * Consolidated PAT: **₹43.87 Cr** (vs. ₹51.16 Cr prior, including adjustments) ## B. Revenue & Adjustments * **Revenue Impact from Structural Changes:** Stand-alone and consolidated revenues declined sequentially, primarily due to elimination of intercompany B-80 revenues and prior-period adjustments totaling **₹123 crores**. * **Adjustment Normalization:** Q1 FY26 performance is more reflective of core operations, with minimal adjustment impact and stable production volumes. * **Ownership Consolidation:** HOEC now holds 100% of B-80, leading to full consolidation and removal of intercompany facility revenue and costs. ## C. EBITDA & Profitability * **Core EBITDA Resilience:** Consolidated EBITDA remained stable on an adjusted basis, reflecting operational consistency despite lower revenue. * **Profit Volatility Explained:** Sharp decline in standalone PAT driven by absence of prior quarter’s significant year-end adjustments; consolidated PAT surged due to lower base with adjustments. ## D. Cost Trends * **Mixed Cost Dynamics:** Standalone operating and statutory costs declined meaningfully, but total standalone cost increased due to non-operating components. * **Consolidated Cost Pressure:** Total consolidated expenses rose sharply, largely influenced by **stock movement impacts**. ## E. Balance Sheet & Cash Flow * **Targeted Capital Raise:** **₹250 Cr** in debt capital raised via internal accruals, ring-fenced for drilling capex, signaling continued investment in production growth. * **Credit Profile Strengthened:** India Ratings upgraded outlook to **'positive'** on **₹50 Cr bank loan**, citing strong cash position and adequate borrowing headroom. --- # 2. Production & Volume Trends ## A. Key Figures * **Kharsang Production:** **350 bbl** total field output · **35%** company’s working interest * **Inventory Volume:** **410,000 bbl** unsold oil from Block B-80 ## B. Gas & Oil Output * **100% Drilling Success Rate:** All wells drilled in Kharsang field are productive, with no dry wells reported, reflecting strong geological confidence. * **Controlled Output Share:** Company benefits from 35% working interest in total Kharsang production, leveraging full operational yield without ownership of entire volume. ## C. Inventory & Offtake * **Near-Term Cash Realization:** Disposal of **410,000 bbl** inventory underway via M-junction auction, with technical evaluations complete and price bidding active. * **Imminent Offtake:** Physical offtake expected within **10 to 15 days** of final price acceptance, signaling near-term liquidity event. --- # 3. Drilling & Capacity Expansion ## A. Key Figures * **Planned Wells:** **18 shallow + 3 deep** Kharsang · **4** Dirok · **2 each** Greater Dirok, North Balol, Asjol · **10 offshore** (3 PY-1, 3 B-80, 4 B-15) * **Drilling Progress:** **4 wells completed**, **5th underway** in Kharsang * **Project Costs:** **~$10M** per B-80 well (excl. platform) · **~$2M** per Kharsang well ## B. Onshore Drilling Progress * **Phased Ramp-Up:** Drilling advancing in phases at Kharsang, with early execution on track and management targeting sustained momentum toward full asset monetization. * **Expansion Pipeline:** Capacity augmentation underway in North Dirok and Dirok field, with additional wells planned pending partner approvals and rig mobilization. * **Execution Timeline:** First new well drilling expected before year-end, contingent on securing rig, long-lead items, and environmental clearances; full commissioning anticipated from Q3 onward. ## C. Offshore Drilling Plans * **Structured Offshore Campaign:** 10-well offshore program set to begin with B-80 workover in November 2025, followed by PY-1 drilling in Q4 FY26, excluding monsoon windows. * **Production Target:** Combined drilling of **~30 onshore and 10 offshore wells** aimed at achieving **10,000 barrels per day (company’s share)** as part of strategic growth. * **Partner Alignment:** PetroVietnam has confirmed a 4-well development plan including exploration and appraisal activity near existing infrastructure, indicating de-risked execution path. ## D. Rig Availability & Timing * **Procurement Momentum:** Expression of interest issued for 1,000 HP and 2,000 HP rigs; contractor and subsea equipment (trees, risers, IWOCs) under evaluation to enable last-quarter rig finalization. * **Workover Schedule:** B-80 workover to take **20–30 days**, with full project completion expected within **about one year** post-workover. --- # 4. Project & Infrastructure Readiness ## A. Platform & Facility Status * **Headline:** Evaluation ongoing for minimum facility platform to drill **3 new wells** and optimize block value. * **Headline:** Cauvery Offshore well plan leverages existing platform for 3 wells, with **1 exploration well outside**; all processing and gas transport infrastructure already in place. * **Headline:** **Compressor station at Guwahati** required for Urja Ganga pipeline integration; current status not disclosed. ## B. Pipeline & Grid Connectivity * **Headline:** **Northeastern Gas Grid** expected operational in **FY'26**, linking Dirok to National Gas Grid, though timeline remains uncertain. * **Headline:** Commercial operations dependent on third-party pipeline progress; final field connections targeted **by year-end**, pending resolution of **common carrier discussions**. * **Headline:** Gas flow to **Numaligarh** and onward to **Guwahati** via **IGGL’s common carrier infrastructure** mitigates DNPL operational risk. ## C. Environmental Clearances * **Headline:** Environmental clearance secured for **40 development and 3 exploration wells** in the **Kharsang block** (Northeast). * **Headline:** **Block 19 (AA-ONHP-2017/19)** cleared for development with **one-year extension** expected; drilling prep to begin upon **bank guarantee approval** by Government of India. --- # 5. Segment & Asset Performance ## A. Key Figures * **Northeast Production:** **350 bopd** added from 3 hooked-up wells · **450 bopd** average in Kharsang (Q1 FY'26) * **Dirok Output:** **2 MMscf/day** gas sales · **8,893 barrels** condensate produced * Dirok Revenue: **₹36.97 Cr** (up from ₹31.47 Cr) driven by **490 mmscf** gas and **8,893 bbl** oil sales * B-80 Production: **48,406 bbl oil** and **0.37 Bcf gas** (quarterly) · **$11.4/MMBtu** avg. gas price * B-80 Revenue: **₹38.58 Cr** gas revenue (down from ₹44.15 Cr prior) on **402 mmscf** production ## B. Northeast Region Output * **Rapid Production Ramp-Up:** Three new wells now online, delivering output equivalent to legacy 28-well base, with fourth well showing **strong gas rates** in Upper Girujan sands, validating GCA’s gas volume forecast. * **Kharsang Momentum:** Output increased significantly QoQ, reflecting successful well hook-ups and reservoir performance. * **Dirok Volume & Revenue Surge:** Sharp increase in both gas and condensate volumes drove **over 100% revenue growth**, highlighting operational gains and improved monetization. * **Umatara Drilling Initiated:** First well spudded by IOCL under 10% participating interest; environmental clearances secured, signaling progress across Northeast portfolio. ## C. Offshore Block Activity * **B-80 Production Stabilized:** Output and pricing declined QoQ, but production is expected to remain **stable over 12–15 months**, with upside potential from workovers and expansion. * **Commercial Discipline in Oil Sales:** Decision to sell below $75 target based on near-term price outlook of **$65–$70**, reflecting proactive risk management despite storage availability. * **Economically Resilient at $60/bbl:** B-80 remains viable at lower oil prices, with planned 5,000 bopd production not triggering disproportionate royalty escalations. * **New Offshore Development Launched:** Revenue Sharing Contract signed for **B-15 (Mumbai High)**, a small discovered field; development plan underway leveraging existing seismic data, targeting two discoveries with exploration upside in shallow waters. * **PY-3 Appraisal Progress:** PetroVietnam proposed **4-well campaign** (2 infill, 1 appraisal, 1 exploration), indicating confidence in reserve growth; arbitration delay persists with no tribunal formed. * **Production & Reserve Growth Catalyst:** Offshore drilling initiatives across blocks are positioned to expand both near-term output and long-term reserve base. ## D. Cambay & Umatara Status * **Cambay Drilling Revival:** Environmental clearances secured for **4 wells** (2 each in North Balol and Asjol); first development well spudded after **17-year pause**, marking a key operational restart. * **Near-Term Drilling Roadmap:** Sequential execution planned—North Balol first, then Asjol—while awaiting **final PSC ring-fencing and Palej extension**, which could unlock material value. * **No Current Production Change:** Despite activity uptick, Cambay output remains flat, with impact expected post-well completions. --- # 6. Operational & Weather Risks ## A. Monsoon Disruptions * **Production Interruption:** Block B-80 operations were suspended in mid-June 2025 due to monsoon conditions, requiring FSO de-mooring; production resumed in August after re-mooring. * **Recurring Weather Risk:** Monsoon-related disruptions expected annually; ability to maintain production during adverse weather remains uncertain despite operational improvements. * **Drilling Timing Exposure:** Well drilling in current quarter contingent on rig availability during monsoon; otherwise, activity will be deferred to next season. * **Post-Monsoon Work Program:** Workover operations in B-80 set to commence immediately after monsoon ends, with contractors being finalized for execution. * **Regulatory Headwind:** DNPL’s conversion to a common carrier not yet addressed in regulator’s proposals, though government intervention is anticipated due to strategic interest from Oil India and stranded gas utilization goals. ## B. Production Downtime * **Demand-Limited Output:** Dirok’s production capacity remains underutilized due to weak offtake demand, despite progress on common carrier status and DNPL line augmentation. * **Well Performance Issues:** D1 well output constrained by mechanical and wax-related challenges, prompting planned workover post-monsoon; both D1 and D2 wells currently flowing. --- # 7. Guidance & Outlook ## A. Key Figures * **Capex Plan:** **₹1,250 Cr** over two years (+₹250 Cr vs. prior) · **$50 Mn** total for 4 offshore wells * **Production Target:** **+1,000 bopd** by Dec-2025 · **P90 output ≥10,000 bopd** post-capex * **Auction Value:** **~₹220 Cr** (~$25–26 Mn) estimated project value * **Inventory Volume:** **410,000 barrels** to be liquidated post-auction ## B. Capex & Funding Plan * **Accelerated Investment:** Capex increased by ₹250 Cr to fund aggressive drilling in the Northeast and offshore, targeting completion within two years despite potential 6-month delays. * **Funding Strategy:** Program fully funded with debt capped at **₹250 Cr**, aiming for debt-free status within two years post-capex. * **Cost Environment Tailwind:** Lower oil prices reducing input and drilling costs, creating a favorable window for capital deployment. ## C. Production Targets * **Near-Term Volume Ramp-Up:** 9 wells targeted for completion by December 2025, driving significant daily production addition. * **Gas Offtake Inflection:** Increased gas offtake expected in Q3 FY26, contingent on regulatory framework and grid connectivity. * **Longer-Term Stability:** Seasonal volatility expected to decline as infrastructure matures, improving reliability of quarterly performance comparisons. ## D. Auction & Revenue Timing * **Immediate Monetization Pathway:** Auction to commence before August 31, with inventory liquidation expected within 1–5 months; revenue realization tied to final auction pricing. * **Low-Cost, High-Speed Production:** Cauvery Offshore project requires marginal capital and allows immediate production hook-up, with **no gas sales constraints anticipated** due to GAIL coordination.