Phase 2 Needs 2.1 Bcf/d More Montney Gas, and 91% of Its Full-Interval Logs Predate 2009

The Montney wells that will feed LNG Canada's second phase and the wells that describe the Montney from top to base were drilled about 15 years apart. In the BC Energy Regulator's open drilling files, 8,607 wells have a Montney completion; 7,255 of them were rig-released in 2009 or later, and 98% of those are horizontal. Only 1,472 non-horizontal wells carry a porosity log and a resistivity log that each run across the whole formation, and 1,342 of them, 91%, had both by the end of 2008. The median full-interval well was logged in 2001. The median completion was released in 2016. A partner sizing its share of Phase 2 supply will rank new blocks on production data from the young wells and correlate them on logs from the old ones, and the old ones are the part of the record most likely to exist only as a scanned image.

What Phase 2 asks of the Montney

LNG Canada is the liquefaction plant at Kitimat, on the north coast of British Columbia. Its gas comes from the Montney, a tight-gas formation under north-eastern British Columbia and north-western Alberta, through the 670 km Coastal GasLink pipeline from Dawson Creek. On 28 September 2026 the joint venture participants, Shell (40%), PETRONAS (25%), PetroChina (15%), Mitsubishi (15%) and KOGAS (5%), took the final investment decision on Phase 2 [1]. It adds two trains and doubles capacity from 14 to 28 million tonnes a year, with operations expected in the early 2030s; Coastal GasLink adds five compressor stations, with construction from 2027 [1][2][3]. The plant runs under an equity-lifting structure: each participant takes its proportionate share of the LNG and supplies its share of the feed gas [2].

IEEFA puts the feed gas for Phase 1's two trains at 2.1 Bcf/d and expects Phase 2 to take the project to around 4.2 Bcf/d [4]. That is 150 MMscfd of inlet gas for each million tonnes a year. A common shortcut, about 130 MMscfd per Mtpa, describes something else: a tonne of LNG holds about 1,360 standard cubic metres of gas [5], or 132 MMscfd per Mtpa, which is the gas that leaves in the ships. The difference is what the plant burns and removes on the way. Applied to the inlet, the shortcut gives 1.8 Bcf/d for Phase 1 and understates the call by about an eighth.

At 150, Shell's 40% of the two new trains is 0.84 Bcf/d, and 1.68 of the full plant; KOGAS's 5% is about 0.1 and 0.21. For scale, the Canada Energy Regulator reports that British Columbia produced 7.4 Bcf/d in 2025 and Alberta 11.3, out of 19.0 Bcf/d for Canada, with the growth coming particularly from the Montney [6]. The Phase 2 increment alone is 28% of British Columbia's 2025 output. In the regulator's own production file, Montney completions supplied 93% of the raw gas British Columbia's wells reported in the first half of 2026 [7].

IEEFA frames the supply question as drilling and price [4]. There is a third constraint before either. The basin has the gas; each partner has to find which Montney intervals, in which blocks, can deliver its lifting share at a cost and decline its contract can carry. That is a correlation and ranking problem across thousands of wells, and the well record it runs on is split between decades.

What the regulator publishes, and what needs a login

The BC Energy Regulator's Data Centre offers a complete well index, a drilling data archive, directional surveys and production by well, as downloads with no login [7]. The drilling archive is richer than its name suggests: it includes formation tops, completion events and a table of the logs run in each well, with the log type and the depth interval of each run. Log images and curve files are not among the downloads. The Well Lookup and Reports system, where a well's file can be opened, needs credentials [7]. Today's submission manual asks operators for a TIFF or PDF of every log and one or more LAS files with all curves [8], so the regulator receives digital curves for current wells; the open downloads do not say which wells have them.

On reuse, the site's terms of use state that the material on the website is the Province's copyright and may not be reproduced without prior written permission [9]. The regulator also publishes an Open Data Licence, based on version 2.0 of the Open Government Licence for British Columbia, which allows copying and publishing with attribution for the information it releases as open data [10]. The Data Centre page does not say which of its downloads fall under that licence, and nothing we found puts log images under it. A licence may be available on request. Raster logs for western Canada are also sold commercially.

So the run we planned, digitising public Montney logs, cannot be done on open data. What can be done on open data is to count the record those logs belong to, and the count is the first readiness question a Phase 2 partner should be asking anyway.

Counting the record from the open files

We took the Data Centre downloads with history to 10 October 2026 and counted three things [7].

Montney completions. Every well with a completion event in the Montney, including the three commingled Montney codes: 8,607 wells, the first released in 1974. We call a well horizontal if its directional survey reaches 80 degrees; 7,119 do. A well with no survey counts as vertical.

Full-interval wells. These are the wells that sample the formation from top to base, which is what a regional correlation framework is built on. A well qualifies if it is not horizontal, has a Montney top and a deeper formation top within 600 m of it, and has a porosity log (neutron, density or sonic) and a resistivity log (induction or laterolog) whose run intervals each span from the Montney top to that deeper top. Any well qualifies, whatever it produced from. There are 1,472, dated by the year both logs existed.

The end of the open log index. The logs-run table records 540 wells logged in 2014, 11 in 2015 and one after that. From 2015 the open files stop saying which logs were run.

Cutoff year: 2009 (horizontals overtake verticals for good)Inlet gas per Mtpa: 150 MMscfd (IEEFA)

feed gas for:Phase 2 trains, 14 Mtpafull plant, 28 Mtpa

Before 2009: 1,342 of 1,472 full-interval wells were logged. From 2009: 7,255 of 8,607 Montney completions, 98.1% horizontal. Median full-interval well: logged 2001. Median completion: released 2016. The open log index stops in 2015, before 4,943 completions (57.4%). Phase 2, 14 Mtpa at 150 MMscfd per Mtpa: 2.10 Bcf/d, 28% of BC's 7.4 Bcf/d in 2025. Gas in the LNG itself: 1.84.

The exhibit opens on 2009, the year horizontal completions overtook vertical ones for good, 163 to 67. Before it, 91.2% of the full-interval wells had been logged. From it, 84.3% of the completions were released. Drag the cutoff and look for a year that splits the two records more evenly. There is none: move it back to 2000 and only 45% of the framework is older while 96% of the completions are still younger; move it forward to 2012 and the framework is 99% older. The two records do not overlap in time so much as hand over, and the handover happened over about three years.

The definition matters less than one might expect. Requiring only a porosity log, or accepting any open-hole log across the interval, or loosening the depth match from 1 m to 10 m, changes the count from 1,472 to as many as 2,189 wells, and keeps the share logged before 2009 between 90.5% and 91.3% and the median year between 2001 and 2003.

Two further lines on the timeline carry the access question. The first is 1989, the year the Canadian Well Logging Society introduced the LAS format [11]. 304 full-interval wells, 21%, were logged before it. Some of those logs were recorded to tape in proprietary formats, and some exist only on paper and film; the open files cannot say which. The second is 2015, where the open log index ends. 4,943 Montney completions, 57%, were released after it. For them the open record does not even list the logs. It does not follow that they were not logged, only that the inventory of their logs is behind the login.

The record splits three ways, with counts

The Montney has plenty of data. The useful record is split three ways, and the open files now let us put numbers on each.

The modern horizontal wells are the gas. For the 2,186 horizontal completions released before 2015, where the open log index still runs, 1,990 have a measurement-while-drilling gamma ray log on record, while only 535 have any porosity log and 449 any resistivity log, over any interval. A lateral logged with gamma ray tells you where the bit was in the stratigraphy; it says little about the rock above and below it.

The older vertical wells give the regional framework. They are the 1,472; half of them were logged between 1991 and 2006, and the oldest fifth predate LAS.

Production by well is public and clean. It is the most complete of the three, and the one a type curve is fitted to.

A Phase 2 partner needs to know whether those three can be joined for its blocks, and how long that takes. We would ask for three counts, block by block:

1. How many wells in the block have digital curves across the Montney interval, and how many have only images. The open files give the denominator: which wells have full-interval logs at all, and when they were run.
2. How many wells have a correlation into a framework someone has checked.
3. For each candidate interval, whether the type curve is a fit with a confidence band or a number from a slide.

The second count is the hard one on a mature unconventional play. The correlation framework often exists in many versions, one per operator and vintage, and the formation tops in the open file are operator picks, one set per well, from whoever drilled it. No shared file records how one operator's picks join another's. A knowledge graph can hold the same well under each operator's name, datum and pick set, and that makes the join repeatable.

EarthScan 360 does the upstream part of this today: it digitises raster logs, correlates them well to well, and holds each well across formats in that graph. It has not been tested on British Columbia logs, because we do not have them; the accuracy test we want to run compares digitised images against the operator's own digital curves for the same wells, and needs a dataset where both exist. On the Texas archive we have worked with, scanned logs outnumber LAS files by about 17.6 to 1 [12], and the question a digitising programme turns on is how much of an archive is raster and how fast it can be read [13].

A supply case is a set of drilling scenarios

Each development option a partner considers is a scenario on the basin model: a drilling programme, with an expected rate and decline for each block. On the Montney, new well results arrive weekly, and every one of them can confirm or contradict some of those scenarios. The useful question to put to a supply case is how many days pass between a well result landing and the team knowing which scenarios it has contradicted. The answer depends on the join between the three records above. The forecasting half, a per-well gas fit with a band, is the part we are still building.

Key takeaways

1. 1LNG Canada's participants took the Phase 2 decision on 28 September 2026: 14 to 28 Mtpa, early 2030s, each participant supplying its own share of feed gas.
2. 2IEEFA's 2.1 Bcf/d for 14 Mtpa is 150 MMscfd per Mtpa at the inlet; 130 to 132 is the gas leaving as LNG, and using it at the inlet understates the call by about an eighth.
3. 3At 150, Shell's 40% of the new trains is 0.84 Bcf/d and of the full plant 1.68; the Phase 2 increment is 28% of British Columbia's 7.4 Bcf/d in 2025.
4. 4Of 8,607 wells with a Montney completion in the BCER's open files, 7,255 were released from 2009, 98% of those horizontal; median release year 2016.
5. 5Of 1,472 non-horizontal wells logged with porosity and resistivity across the whole Montney, 91% were logged before 2009; median 2001; 21% predate LAS.
6. 6The open log index ends in 2015, before 57% of the completions; log images and curves sit behind the regulator's login.

Where this count is weakest

Everything here is counted from tables operators submitted and the regulator transcribed. A wrong depth, a missing log record or a well with no directional survey moves a well between groups. A well with no survey counts as vertical, which is right for most old wells and wrong for a few.

The full-interval test uses the logged interval of each run. A run whose interval spans the Montney may still have gaps, washouts or a curve that was not recorded over part of it. The count says the log was run there, not that it is usable.

The open files do not say whether a log exists as a digital curve. The dates are a proxy for the likelihood, and LAS in 1989 is a marker, not a boundary: some older logs survive on tape, and some later ones may only have been filed on paper.

The logs-run table stops in 2015, so the framework count cannot include any well logged since. Few full-interval verticals were drilled after 2009, so the effect on the 91% is probably small, but the count is an inventory of the open record, not of the logs that exist.

This is British Columbia only. The Montney continues into Alberta, whose regulator publishes its records differently, and participants hold acreage on both sides of the border.

Participant interests are those published at the decision. IEEFA reports that PETRONAS sold 20% of the entity holding its stake to MidOcean Energy in 2025, and that Shell and Mitsubishi have considered selling down [4]; the equity split of the gas obligation follows whatever the final interests are.

References

1. LNG Canada. LNG Canada announces Phase 2 final investment decision, CNW release datelined Vancouver, 28 September 2026, reprinted by BOE Report: participants, 670 km pipeline, five new compressor stations, gas from the Montney: boereport.com.
2. M. Adams. Shell takes FID to double LNG Canada capacity. Oil and Gas Journal, 29 September 2026: 14 to 28 million tpy, early 2030s, equity lifting, construction from early 2027: ogj.com.
3. Prime Minister of Canada. Prime Minister Carney welcomes LNG Canada Phase 2, 29 September 2026: participant interests, 28 Mt a year, Coastal GasLink construction from next year: pm.gc.ca.
4. M. Kalegha (IEEFA). LNG Canada Phase 2: After FID key questions remain, September 2026: Phase 1 requires 2.1 Bcf/d, Phase 2 likely doubles it to around 4.2 Bcf/d; participant interests and divestments: ieefa.org.
5. Snam. Energy units and conversion factors: 1 tonne of LNG is 1,360 standard cubic metres of gas: snamatlas.it.
6. Canada Energy Regulator. Market Snapshot: Canada's natural gas production kept climbing in 2025, 20 May 2026: Canada 19.0, Alberta 11.3 and British Columbia 7.4 Bcf/d: cer-rec.gc.ca.
7. BC Energy Regulator. Data Centre: well index, drilling data for all wells (completions, formation tops, logs run), directional surveys and production, downloaded 19 October 2026 with history to 10 October 2026; Well Lookup and Reports require logon credentials: bc-er.ca/data-reports/data-centre.
8. BC Energy Regulator. Well Data Submission Requirements Manual, version 1.3, November 2023, section 2.2, logs: bc-er.ca.
9. BC Energy Regulator. Terms of use, copyright information: bc-er.ca/terms.
10. BC Energy Regulator. Open Data Licence, based on the Open Government Licence for British Columbia version 2.0: bc-er.ca.
11. Kansas Geological Survey. Log ASCII Standard (LAS) file help: the LAS standard was introduced by the Canadian Well Logging Society in 1989, version 2.0 in September 1992: kgs.ku.edu.
12. What a public archive of 136,771 scanned logs and 7,781 LAS files teaches about real data: What 136,771 TIFs and 7,781 LAS Files Teach You About Real Data.
13. How the raster share of an archive sets how long it takes to become readable: Fully Deployed Is Not Machine-Readable.