The short version.

• DGH is not a regulator with independent licensing power — it's a technical wing of the Ministry of Petroleum & Natural Gas (formed 1993), advisory in function, with no PNGRB-equivalent statutory Act of its own. Actual licensing decisions rest with the government; DGH runs the data, the evaluation, and the process.
• Since 2016, India leases exploration acreage under the Hydrocarbon Exploration and Licensing Policy (HELP), via the Open Acreage Licensing Programme (OALP). OALP's defining feature: a company can nominate any block from open acreage year-round by filing an Expression of Interest against DGH's National Data Repository — there's no need to wait for a scheduled bidding round. The nominated area then goes to competitive bidding, with the original nominator getting a scoring advantage, not an automatic win.
• Contracts run on a Revenue Sharing model, not the old profit-sharing PSC structure — government audits revenue, not costs, eliminating the "cost recovery" disputes that plagued the earlier NELP regime. One license covers conventional and unconventional hydrocarbons (shale, CBM, tight gas) in the same block, and companies get marketing and pricing freedom on what they produce.
• Nine rounds have now run: per PIB's own count, the first seven rounds under HELP awarded 134 blocks across roughly 207,691 sq km spanning 19 basins; adding Round VIII brings the combined total to roughly 144 blocks. Round IX (28 blocks, ~136,596 sq km across 8 basins, 38% in areas previously off-limits as "No-Go") drew just four bidders total — ONGC, Oil India and Vedanta among them — with most individual blocks receiving only two bids. Round X, India's largest single round at 25 blocks and roughly 192,000 sq km (91% offshore), had its bid deadline extended five times since February 2025, eventually unified with Round XI's deadline at 19 June 2026 — a date that has now passed, with still no confirmed award announcement found as of this piece's most recent check in September 2026.
• The real bottleneck sits after the award, not at it. Across roughly 172 OALP blocks awarded through Round IX, backed by an estimated $4.36 billion in committed exploration investment, only 14 discoveries have been reported and just one marginal field has reached production — a finding independently echoed by the government's own answer to Parliament (13 discoveries, one Gujarat gas block at 0.44 MMSCMD, dated March 2025). Vedanta's founder has publicly argued India runs barely 200 active exploration licenses against a need for 2,000; trade coverage from April 2026 notes no foreign exploration company bid on a standalone basis in the most recent round.
• CBM — one of the "unconventional" hydrocarbons folded into HELP's single license — actually runs its own, older, parallel bidding track: four rounds from 2001-2008 plus two special rounds since 2021 have awarded 40 CBM blocks so far, per PIB's own count, with a further Special CBM round (SCBM-2026) still open as of this piece's most recent check, alongside a separate non-competitive right Coal India holds to extract CBM from its own coal-mining-lease land without a further license.

DGH runs the process. It doesn't own the decision.

The Directorate General of Hydrocarbons was set up on 8 April 1993 by a Government of India resolution, sitting under the administrative control of the Ministry of Petroleum & Natural Gas. A common assumption worth correcting directly: DGH is not an independent regulator with its own statutory licensing authority, the way PNGRB is for midstream and downstream infrastructure under the PNGRB Act, 2006. DGH has no equivalent enabling Act. Multiple sources describe it plainly as a "technical wing" or "technical arm" of MoPNG, whose functions are largely advisory, with government retaining the actual decision-making power over exploration licences. Oil & Gas Journal has run industry commentary specifically arguing India's upstream sector needs an independent regulator — a gap directly attributable to DGH's advisory, non-statutory status.

What DGH actually does, concretely: it implements the government's exploration policy on the ground — NELP historically, now HELP/OALP and the small-discoveries Discovered Small Field (DSF) policy — runs the technical evaluation of bids, reviews companies' field development plans and reserve estimates, advises on exploration and exploitation adequacy, and advises on safety norms in coordination with other bodies. Its own stated mandate is to "promote sound management of oil and natural gas resources having a balanced regard for environment, safety, technological and economic aspects." In practice, DGH is the machinery that makes the leasing process run; the government (via bodies like the block-specific Management Committee described in Section 5) is where contractual and commercial decisions formally land.

DGH's 1993 founding date and administrative placement under MoPNG are corroborated across a Tesseract Academy explainer and DGH's own hosted mandate page (reached via search, not a direct fetch in every instance). DGH's advisory, non-statutory characterisation and the contrast with PNGRB's Act-based authority are drawn from secondary industry commentary, including Oil & Gas Journal's piece explicitly arguing for an independent upstream regulator, and a PRS Legislative Research report summary on DGH's functioning (this piece could not load the underlying PRS PDF directly; its specific criticisms should be independently confirmed before being cited further). DGH's concrete functions (bid evaluation, FDP review, safety-norms advisory) are drawn from DGH's own mandate page as indexed by search.

HELP, 2016: what actually changed from the old NELP regime

The Hydrocarbon Exploration and Licensing Policy was approved by the Cabinet on 10 March 2016 and notified later that month, replacing the earlier New Exploration Licensing Policy (NELP). Four design changes define it. First, a Revenue Sharing Contract model replaces the profit-sharing Production Sharing Contract structure NELP used — under a PSC, the government audited and disputed contractors' claimed costs before sharing profits; under RSC, government simply takes an agreed share of gross revenue, regardless of the contractor's actual costs, which removes an entire category of "cost recovery" litigation and disagreement that dogged the NELP era. Second, a single license now covers both conventional hydrocarbons (oil, gas) and unconventional ones (coal-bed methane, shale gas and oil, tight gas, gas hydrates) within the same contract area, rather than requiring separate licenses per resource type. Third, contractors get marketing and pricing freedom on both crude oil and natural gas they produce, rather than being bound to government-administered pricing. Fourth, royalty rates are structured by area category — historically higher onland and in shallow water, and reduced or waived for several years in deepwater and ultra-deepwater blocks to reflect their higher cost and risk — though these original rates were substantially revised in a May 2026 reform covered in Section 6.

HELP's 10 March 2016 Cabinet approval and its four-pillar design (revenue sharing, single license, open acreage, marketing freedom) are corroborated across a Wikipedia summary of the policy and a hosted explainer PDF on the Consulate General of India, Houston's site. The cost-recovery-versus-revenue-audit distinction between PSC and RSC is standard characterisation across multiple secondary sources and reflects the widely-reported rationale for the change, though this piece did not read HELP's own gazette notification text directly. The original area-category royalty structure and its May 2026 revision are covered in Section 6, sourced to psuwatch's coverage of the reform.

OALP: how a company actually gets a block

The Open Acreage Licensing Programme launched in June 2017 as HELP's bidding mechanism, alongside the National Data Repository (NDR) that underpins it. The NDR is a data bank — seismic surveys, well and log data, spatial and geological information, drilling records, reservoir data, gravity and magnetic surveys — that any interested company can consult before deciding where to bid. Feeding that repository is the government-funded National Seismic Program (NSP), a CCEA-approved scheme that began appraising previously unmapped onland basins from September 2016; by this piece's research, roughly 46,960 line-kilometres of 2D seismic survey work had been completed under it, and 11 blocks awarded so far traced directly to NSP-generated data (seven in Rajasthan, two in the Mahanadi basin, two on the Assam Shelf).

OALP's actual defining feature, distinguishing it from NELP's fixed, government-scheduled bidding rounds, is that a company can carve out and nominate any block from India's open acreage at any time of year, by filing an Expression of Interest (EoI) against the NDR data. Nominated areas accumulate and are then periodically bundled into a formal Notice Inviting Offers, opening a roughly 60-day window for competitive bidding by any interested party — not just the company that nominated the block. The nominating company does get a scoring advantage in evaluation (a fixed mark bonus, by this piece's research), but that is a bonus within a competitive process, not an automatic award or a Swiss-challenge right to match the best offer — a rival bidder can and does outbid the original nominator on the substance of its work programme. DGH targets completing evaluation and issuing the award within roughly ten weeks of the bid deadline, though this piece could not independently verify that timeline figure or the exact scoring-bonus size against DGH's own procedure document directly.

Bid evaluation itself shifted meaningfully starting with Round IV in August 2019: rather than weighting bids mainly on the revenue share a company offers government, evaluation moved toward weighting the committed exploration work programme — described in trade coverage as a shift "from revenue maximisation to production maximisation." In India's already-producing basins (Category I), work-programme commitment is weighted more heavily, with revenue-share bids capped at a limited share of the total evaluation score; in less-explored basins (Category II and III), evaluation runs on the exploration work programme alone, with no revenue-share bidding component at all — the logic being that in frontier basins, getting companies to actually drill matters more than squeezing revenue terms out of them upfront.

PIB's own release on Round IX adds detail beyond the headline count: 23 of its 28 blocks trace to Expressions of Interest filed by companies between April 2022 and March 2023, with the remaining 5 carved out directly by DGH; the mix splits into 9 onland, 8 shallow-water and 11 ultra-deepwater blocks. Government messaging around Round X has cited a potential $100 billion in exploration and production investment tied to the round — a figure worth treating as the government's own stated ambition for the round rather than a confirmed, contracted commitment, given that no award result had been announced as of this piece's most recent check. The 144-block/242,056 sq km combined total for Rounds I-VIII is independently confirmed on DGH's own site, and a Lok Sabha unstarred question (No. 4397, answered 27 March 2025) attaches a committed-investment figure to that same scope: $3.137 billion — a smaller, differently-scoped number from the $4.36 billion figure discussed in Section 7, not a contradiction of it.

OALP's June 2017 launch and the NDR's structure are corroborated across a drishtiias policy explainer and DGH's own indexed material. The National Seismic Program's CCEA approval, September 2016 start, ~46,960 line-km completed figure, and the 11 NSP-sourced block awards (7 Rajasthan/2 Mahanadi/2 Assam Shelf) are from a DGH-hosted NSP dashboard PDF, reached via search index rather than a direct fetch. The year-round EoI mechanism as OALP's defining feature versus NELP's fixed rounds is standard characterisation across multiple secondary policy explainers. The scoring-bonus-for-originator mechanism and DGH's roughly ten-week evaluation target were found only in secondary/aggregator sources, not DGH's own procedure document directly (online.dghindia.org's OALP procedure PDF was not reachable in this piece's research), and should be independently confirmed against that primary document before being cited as precise figures elsewhere. The Round IV (August 2019) shift toward work-programme-weighted evaluation, and the Category I/II/III evaluation-structure distinction, are corroborated across multiple secondary policy sources. The Rounds I-VII cumulative figure (134 blocks, ~207,691 sq km, 19 basins) and Round IX's block count, basin count, "No-Go" area share, EoI/DGH-carve split, and onland/shallow/ultra-deepwater breakdown are drawn directly from PIB press releases (pib.gov.in), reached via search index; this is a materially stronger sourcing basis than most of this piece's other figures, which rest on trade coverage (psuwatch, The Statesman, Business Standard, energywatch.in, discoveryalert.com.au) rather than a primary government release. The 144-block/242,056 sq km combined Rounds I-VIII figure is independently corroborated on DGH's own site (dghindia.gov.in, reached via search index) and in a Lok Sabha unstarred question answered by MoPNG on 27 March 2025 (via sansad.in, also reached via search index, direct fetch blocked), which additionally attaches a $3.137 billion committed-investment figure to that scope. Round X and XI's block counts, areas, and the deadline-extension history (five extensions since February 2025, unified to a 19 June 2026 close, with interim closing dates of 18 February and 29 May 2026 independently visible in DGH's own indexed notices) are corroborated across Business Standard, psuwatch, National Herald, discoveryalert.com.au and DGH's own site; no formal government explanation for the extensions was found in any source, and this piece did not find a confirmed award announcement for either round as of its most recent check in September 2026 — that absence is reported as the current state of the record, not as evidence the rounds have failed.

A parallel, older track: Coal Bed Methane bidding

CBM runs its own separate bidding history, predating OALP by well over a decade. Per PIB's own figures, four competitive CBM bid rounds ran in 2001, 2003, 2005 and 2008, together awarding 33 blocks across roughly 16,613 sq km; of those, 8 blocks had reached the production or development phase as of the most recent PIB figures found. A fifth, "Special" CBM Bid Round (SCBM-21) followed in 2021, awarding 4 further blocks across roughly 3,860 sq km, and a subsequent SCBM-2022 round added 3 more blocks — contracts for which were signed in the same ceremony as Round VIII's OALP contracts. A further Special CBM Bid Round — SCBM-2026 — has since been launched, per DGH's own indexed notices, with its bid submission window closing 18 February 2026 alongside OALP-X and DSF Bid Round IV; this piece could not find a confirmed block count or award result for this newest CBM round, and reports it as an open, unresolved round rather than a completed one. CBM blocks in total are spread across 12 states: Andhra Pradesh, Chhattisgarh, Gujarat, Jharkhand, Madhya Pradesh, Maharashtra, Assam, Odisha, Rajasthan, Tamil Nadu, Telangana and West Bengal.

A separate, non-competitive allocation path exists alongside these auctioned blocks. Coal India Limited and its subsidiaries hold a standing right to explore and exploit CBM within any coal-bearing area they already hold under a coal mining lease, under a government notification dated 3 November 2015 and amended 11 April 2018 — the amendment specifically relaxing the Petroleum & Natural Gas Rules, 1959 so CIL doesn't need to separately apply for a CBM license or lease over ground it already holds for coal mining. This is a distinct legal mechanism from the OALP/CBM competitive-bidding track described above, and worth naming because it means not all of India's CBM acreage is allocated through any auction at all.

One further wrinkle complicates Section 2's "single license covers unconventional hydrocarbons" claim, worth flagging directly: that design applies cleanly to new blocks awarded under HELP/OALP since 2016, but pre-existing Production Sharing Contract and CBM-contract holders from the older regime were historically barred from cross-exploiting other hydrocarbon types within their own already-licensed areas — a CBM contractor couldn't touch conventional oil or gas found in its own block, and a conventional PSC contractor couldn't touch CBM. The government only extended unconventional-hydrocarbon rights to these legacy PSC, CBM-contract and nomination-field holders through a separate policy notified 20 August 2018, with cost recovery for the new activity ring-fenced separately from each contract's existing petroleum production. So HELP's single-license design is a from-the-start feature only for acreage awarded after 2016; everything awarded before it needed this specific 2018 policy to catch up.

The resource base behind all this: government's own prognosticated estimate puts India's CBM resources at roughly 92 trillion cubic feet (about 2,600 billion cubic metres) across those 12 states, concentrated in the Gondwana coal-bearing sediments of eastern India, particularly the Damodar-Koel and Son river valleys. Commercial CBM production is already running at three named sites found in PIB's own material: Raniganj (South) in West Bengal, operated by Great Eastern Energy Corporation Limited; Raniganj (East), operated by Essar Oil & Gas Exploration & Production; and Sohagpur (West), operated by Reliance Industries.

The four competitive CBM bid rounds (2001/2003/2005/2008), their 33-block/16,613 sq km total, the 8 blocks in production/development, SCBM-21's 4 blocks/~3,860 sq km, SCBM-2022's 3 blocks, and the 12-state geographic spread are all drawn directly from PIB press releases (pib.gov.in), reached via search index rather than a direct full-page fetch in every case. SCBM-2026's existence and its 18 February 2026 bid closing date are from DGH's own indexed site notices (dghindia.gov.in), also reached via search index; no block count or award result was found for this round. CIL's standing coal-mining-lease CBM right, its 3 November 2015 notification and 11 April 2018 amendment relaxing the PNG Rules 1959 requirement, are similarly from a PIB release on the Cabinet's approval of that amendment. The August 2018 unconventional-hydrocarbons policy extending rights to legacy PSC/CBM/nomination-field holders, its ring-fenced cost-recovery structure, and the historical cross-exploitation restriction it replaced, are from PIB's own release on that Cabinet approval and a drishtiias policy explainer. The 92 TCF prognosticated CBM resource estimate and the three named producing sites (Raniganj South/GEECL, Raniganj East/Essar, Sohagpur West/RIL) are from a PIB release on CBM resources specifically. This section's sourcing is materially stronger than most of this piece, resting on primary government releases throughout rather than trade-press aggregation.

From award to relinquishment: the actual lifecycle of a block

Once a block is awarded, the contract enters an Exploration Phase, split into sub-phases with a Minimum Work Programme attached to each — specific drilling and survey commitments the contractor must meet or forfeit financial guarantees against. One concrete detail confirmed from DGH's own Model Revenue Sharing Contract: Phase II of exploration runs four years and is specifically for drilling exploratory wells. This piece could not fully verify the complete phase-by-phase duration schedule or confirm the exact percentage of contract area a company must relinquish at the end of each exploration sub-phase specifically under HELP/RSC contracts — a 25% relinquishment figure is commonly cited for PSC-style upstream contracts generally, but this piece did not confirm that figure is HELP-specific, and it should be checked against DGH's Model Revenue Sharing Contract directly before being treated as precise.

If exploration finds hydrocarbons, the contractor appraises the discovery and submits a Declaration of Commerciality to the block's Management Committee — the joint government-contractor body that oversees the contract's remaining lifecycle. A Field Development Plan must then follow, submitted within 24 months of the appraisal programme for onshore discoveries or 36 months for offshore ones, and requires Management Committee approval before the block can move into its Development Phase — the period of building out production infrastructure between FDP approval and the start of commercial output. Once production begins, the Production Phase runs under a Petroleum Mining Lease, normally granted for 20 years and extendable by a further 10; royalty and cess terms are typically more concessional during the original 20-year term than during any extension, which is charged at standard rates.

At the end of a block's productive life, or on earlier surrender, relinquishment is governed by MoPNG's Site Restoration and Abandonment Guidelines, 2018. Wells must be permanently plugged; the contractor is required to notify DGH (and, for offshore blocks, OISD, or DGMS for onshore) within 180 days of production ceasing, and to submit a formal abandonment plan within one year of that notification. A mandatory Site Restoration Fund, built up during the block's productive life, is meant to cover the cost of removing equipment and installations once the contract ends or is terminated — the mechanism intended to stop a company simply walking away from a depleted field's physical infrastructure.

The Phase II four-year exploratory-drilling detail is drawn directly from DGH's Model Revenue Sharing Contract, as indexed and reached via search rather than a full direct read of the PDF; the complete phase schedule and the exact relinquishment percentage were not independently confirmed and are flagged as needing verification against that same document. The Declaration of Commerciality, Management Committee, and FDP-submission-timeline details (24 months onshore/36 months offshore) are drawn from secondary summaries of standard RSC contract terms. The 20-year-plus-10-year Petroleum Mining Lease structure and its concessional-versus-standard royalty treatment are similarly from secondary sourcing rather than a primary lease-document read. The Site Restoration and Abandonment Guidelines 2018 details — the 180-day notification window, one-year abandonment-plan deadline, and Site Restoration Fund mechanism — are drawn from a DGH-hosted guidelines PDF as indexed by search.

2025-2026: a new Act, and a substantial royalty cut

The Oilfields (Regulation and Development) Amendment Act, 2025 received Presidential assent on 28 March 2025 and came into force on 15 April 2025. It replaces the older concept of a "mining lease" with a single unified "petroleum lease" covering exploration, production, processing, and — notably — energy-transition-adjacent uses including hydrogen and carbon capture and storage under the same lease structure. A new Section 4A requires a valid petroleum lease for any such operation, and the Act's definition of "mineral oils" was expressly broadened to include shale gas and oil, tight gas and oil, coal-bed methane, oil shale, and gas hydrates — formalising, in statute, ground HELP's single-license design had already covered administratively since 2016.

Following that Act and new Petroleum & Natural Gas Rules, the government rationalised royalty rates substantially on 8 May 2026: onshore crude royalty fell from 16.66% to 10%, offshore/shallow-water crude from 9.09% to 8%, gas royalty from 10% to 8%, deepwater royalty from 5% (after an initial concessional period) to a lower post-concession rate, ultra-deepwater similarly reduced, and royalty on nominated/pre-NELP onshore blocks fell from 20% to 12.5%. Credit rating agency ICRA's own assessment, cited in trade coverage, framed the move as one that should improve upstream project returns — a fairly direct acknowledgment that the prior royalty structure was itself a drag on project economics, alongside whatever role slow conversion from award to production (Section 7) plays.

The Oilfields (Regulation and Development) Amendment Act 2025's assent date, force date, unified "petroleum lease" concept, Section 4A, and broadened "mineral oils" definition are corroborated across TeamLease RegTech's and Legality Simplified's coverage of the Act. The 8 May 2026 royalty rationalisation and its specific rate changes by area category are from psuwatch's coverage, which also cites ICRA's assessment of the reform's likely effect on project returns; this piece did not independently verify the exact rate figures against the underlying government notification.

The real story: blocks awarded, production barely started

Set against the elaborate, genuinely well-designed bidding architecture described above, the outcome data is stark. Across roughly 172 OALP blocks awarded through Round IX, backed by an estimated $4.36 billion in committed exploration investment, this piece's research found only 14 reported discoveries and just one marginal field — in Gujarat — that has actually reached production. That is a strikingly low conversion rate from awarded acreage and pledged capital to any output at all, let alone commercially significant output, and it's the single most important number in this piece: the bottleneck in India's exploration-licensing system is not, on this evidence, primarily at the bidding stage. It's everything that happens after the award. This finding is not resting on one source any longer: a Lok Sabha unstarred question answered by the Ministry of Petroleum & Natural Gas on 27 March 2025 independently states that OALP blocks had yielded 13 hydrocarbon discoveries, with only one — a gas-producing block in Gujarat, output given as 0.44 MMSCMD — actually in production, the rest still under appraisal. The same parliamentary answer separately confirms the 144-block/242,056 sq km/eight-rounds figure used in Section 3, with a committed-investment figure of $3.137 billion attached to that specific scope. Whether this Parliament answer's "eight rounds" figure already folds in Round IX (concluded six months earlier, in September 2024) or refers only to Rounds I-VIII is not something this piece could resolve from the search-indexed material available, so the $3.137bn/144-block figure and the $4.36bn/172-block figure above are reported as two independently-sourced numbers on closely related but not confirmed-identical scopes, rather than treated as reconcilable into one. What both sources agree on, independently, is the qualitative finding that matters most: a small, single-digit-to-low-double-digit number of discoveries, and essentially one block that has reached actual production.

Independent commentary points at a few specific frictions. Vedanta's founder, Anil Agarwal, has publicly argued India runs only around 200 active exploration and production licenses against what he characterises as a need for roughly 2,000, attributing the gap to "protectionism and government red tape" — a characterisation from an interested industry party, not an independent audit, but consistent directionally with the conversion-rate problem above. Trade press coverage from April 2026 reports that no foreign exploration company bid on a standalone basis in the most recent OALP round, suggesting the acreage on offer, the terms, or both, aren't drawing international majors the way the government would presumably like. Round X's bid deadline was extended five separate times between February 2025 and its eventual unification with Round XI at 19 June 2026 — a far more persistent pattern of weak uptake than a single extension would suggest. No source found for this piece carries a formal government explanation for those extensions; the most specific reporting attributes cooled investor appetite to "geopolitical volatility and other market factors," without further detail from any official statement. This piece also found solid evidence of exploration being blocked by defense and environmental clearance conflicts — DRDO missile-testing plans and a proposed Navy port holding up ONGC's exploration activity in the KG Basin — but that evidence dates to the pre-2016 NELP era specifically, and this piece could not confirm the same clearance-delay pattern is an active, documented problem for current OALP-era blocks. It's a plausible contributing factor given the broader conversion-rate problem, but it should be treated as an open question for this specific policy era, not a confirmed cause.

The ~172 blocks/$4.36 billion pledged-investment figure, the 14-discoveries count, and the single-marginal-field-in-Gujarat production figure are from Whalesbook's trade coverage of OALP outcomes. The 13-discoveries figure, the Gujarat gas block's 0.44 MMSCMD output, and the $3.137 billion/144-block/242,056 sq km/eight-rounds figures are from a Lok Sabha unstarred question (No. 4397, answered 27 March 2025) by the Ministry of Petroleum & Natural Gas, reached via search-indexed content on sansad.in (India's Parliament website, blocked from direct fetch in this piece's research environment) — a considerably stronger, primary government source than most of this piece relies on, and one that independently corroborates Whalesbook's qualitative finding even though the precise block-count scope between the two sources could not be fully reconciled. Anil Agarwal's 200-versus-2,000-license comparison and "protectionism and red tape" characterisation are his own public statement as reported in trade coverage, not an independently verified figure, and are presented here explicitly as an interested party's view. The April 2026 finding that no foreign company bid standalone in the latest round is from BusinessToday's coverage. Round X's five-extension deadline history and the "geopolitical volatility and other market factors" characterisation are drawn from discoveryalert.com.au's coverage, cross-checked against the same sourcing as Section 3's round-by-round table; no primary government statement explaining the extensions was located. The defense/environmental clearance-delay evidence for ONGC's KG Basin activity is dated to the pre-2016 NELP era specifically in the sourcing this piece found, and its applicability to current OALP-era blocks is explicitly flagged as unconfirmed rather than assumed to carry over.

What doesn't follow from any of this

None of this should be read as evidence that OALP's bidding mechanism itself is poorly designed — the year-round nomination system, the National Data Repository, and the shift toward work-programme-weighted evaluation all read as genuine improvements on the older NELP regime's fixed-round, revenue-focused structure, and nothing found for this piece contradicts that. What doesn't follow is treating a large block count and a large pledged-investment figure as evidence of a healthy exploration sector on their own; the 14-discoveries/one-field conversion data says the meaningful bottleneck sits downstream of the award, in exploration execution, clearances, and development timelines this piece could not fully trace block-by-block. It also doesn't follow that the pre-2016 NELP-era clearance conflicts this piece found are still an active problem under OALP specifically — that connection is plausible but unconfirmed, and is reported as an open question rather than an established cause. And several of the more precise procedural figures in this piece — the exact relinquishment percentage, the originator's scoring bonus, DGH's evaluation timeline — rest on secondary sourcing because DGH's own procedure and model-contract documents were not directly reachable in this piece's research; a reader relying on any of those figures for an actual bid or compliance decision should verify them against DGH's own current primary documents first.

Sources and caveats