Locator: 52043B.
WTI: $101.10.
New wells reporting:
- Sunday, November 1 2026: 0 for the month, 66 for the quarter, 565 for the year,
- Saturday, October 31, 2026: 66 for the month, 66 for the quarter, 565 for the year,
- Friday, October 30, 2026: 66 for the month, 66 for the quarter, 565 for the year,
- Thursday, October 29, 2026: 66 for the month, 66 for the quarter, 565 for the year,
- Wednesday, October 28, 2026: 66 for the month, 66 for the quarter, 565 for the year,
RBN Energy: Shell returns to production growh with focus on Deepwater, LNG, and Montney. Link here. Archived.
Shell’s two major September developments — the closing of its
C$26 billion (US$16.4 billion) acquisition of Canadian conventional
producer ARC Resources and its final investment decision (FID) for the
C$33 billion doubling of LNG Canada capacity — mark strategic milestones
in its resumption of upstream growth after an extended reshaping of its
portfolio since 2020. Shell’s cautious, returns-driven approach to the
energy transition and the pandemic price shock have led it to refocus on
core LNG growth, augmented by deepwater and onshore natural gas
production. In today’s RBN blog, we analyze how Shell’s upstream
strategy has taken a different path from fellow supermajors ExxonMobil
and BP.
The severe downturn triggered by the onset of
the pandemic in 2020 marked a major inflection point for all oil and
gas producers, including the major international integrateds. As we
outlined recently in Gimme Three Steps,
ExxonMobil stayed committed to investing through the cycle in large,
long-life, low-cost resources. Instead of investing in renewable energy
generation, Exxon focused on reducing emissions from operations and
lower-carbon solutions such as carbon capture and sequestration (CCS).
In
stark contrast, BP in 2020 announced a strategy to cut oil and gas
production by 40% and direct investment to renewable power such as
offshore wind and solar. Three years later, BP did a strategic U-turn,
walking back renewable investment and refocusing on upstream growth, as
we described in Back in the High Life Again.
Shell
struck a middle path. The company rebased its dividend in 2020 and
undertook major portfolio reviews that led to asset sales, which reduced
output in the short term, but it did not commit to long-term production
cutbacks. In terms of the energy transition, Shell maintained its
net-zero target but explicitly capped investment in lower-carbon
platforms to a relatively small share of capital employed.
Now,
after several years of asset sales and declining output, Shell is
returning to upstream growth. At its 2025 Capital Markets Day, the
company targeted about 1% annual growth in combined Conventional Gas and
Integrated Gas (primarily LNG) production through 2030 while keeping
liquids output near 1.4 MMbbl/d. The strategy centers on deepwater oil,
LNG and low-cost gas rather than rebuilding the broad asset base Shell
sold off earlier in the decade.
Projects starting
between 2025 and 2030 were expected to provide more than 1 MMboe/d of
peak capacity at an average breakeven of about $35/bbl. The Whale platform in the offshore Gulf
and the Mero-4 project offshore Brazil began producing in 2025. The
next wave of projects includes Bonga North (offshore Nigeria), Crux
(offshore western Australia), Gato do Mato (offshore Brazil), Manatee
(offshore Trinidad and Tobago), the North Field expansions (Qatar),
Rosmari/Marjoram (offshore Malaysia), and Sparta (U.S. Gulf). Shell owns
only partial interest in many of those projects. New volumes must also
offset natural declines, maintenance and production-sharing contract
effects, which is why more than 1 MMboe/d of project capacity initially
translated into only about 1% annual companywide growth.
The September acquisition of ARC Resources
(yellow bar segment at right in Figure 1 above) changed the outlook.
The transaction added about 370 Mboe/d of output, more than 1.5 million
net Montney acres and roughly 2 billion boe of proved-plus-probable
reserves. Shell now expects its new projects and Canadian assets to
provide about 1.4 MMboe/d of peak capacity by 2030, while combined
Conventional Gas (orange bar segments) and Integrated Gas (gray bar
segments) production is now expected to grow about 4% annually from
2025, while crude oil, synthetic oil and NGLs (blue bar segments) fall
by about 16%.
