QEC: Questerre third quarter 2026 report

President's Message 
One year ago, we acquired PX Energy, an integrated oil shale business in
southern Brazil built around a 35-year-old processing facility. Our goal is to
turn it into a business that generates free cash flow and to use it as the
platform to prove our Homogeneous Charged Continuous Oxidation ("HCCO")
technology. We have made real progress on both fronts this year. We are on track
for $11 million in cost savings in Brazil and are targeting a similar amount in
2027. We also successfully tested the HCCO technology in a commercial scale
vessel at the facility.
In the third quarter, the plant and the team were tested. A furnace failure shut
the plant from late July until August 18. It cost us 19 days of production while
our costs continued over the period. Customers also took delivery of product
they had paid for earlier in the year. Together, these reduced adjusted funds
flow from operations to $2.3 million from $18.3 million in the second quarter.
The team completed the repairs on schedule and on budget with no recordable
safety incidents, and the retort is back to running at over 90% efficiency.
Since then, a minor gas release and the failure of a silo in October have shown
how much maintenance the previous owners of the facility deferred. We are
sharpening our focus on maintenance and corrective action. Next year's scheduled
turnaround will go further than a routine overhaul, with the aim of running the
plant longer between turnarounds.
A solid base is also a financial one. PX Energy's bonds are ring-fenced:
Questerre has not guaranteed them and is not required to repay them. But
ring-fenced is not the same as right-sized. With a larger turnaround and a
prudent contingency for unexpected maintenance next year, we believe PX Energy's
debt should be restructured to fit its cash flow and investment cycle. This is
one of our main objectives for the coming months. We will support a
restructuring only if we believe it is in the interests of Questerre's
shareholders.
Restructuring PX Energy right matters well beyond next year. Twenty years ago,
shale gas and tight oil were thought too costly to produce, until technology
changed that4 and revolutionized North American production. We believe oil shale
could be next, and PX Energy is where we are proving the technology. We plan to
run an extended test of the HCCO technology in 2027.
We have spent the better part of this year refocusing the operations of PX
Energy on our key objectives of safety, efficiency and profitability. Next year
our goal is a stronger base and a more optimal debt structure.
In Quebec, the debate on local natural gas has reopened as the province weighs
how to meet its energy needs while imported and renewable gas becomes more
expensive. Public opinion is moving too. In a recent Ipsos poll, more than
two-thirds of Quebecers supported developing the province's own natural gas. 
During the quarter, the Government approved our carbon storage pilot near
Bécancour. We also signed a mediation protocol with the Attorney General of
Quebec and the Ministry of the Economy, Innovation and Energy. We look forward
to working with the new Government. In Nova Scotia, we were the successful
bidder in the province's first bid round and are negotiating a Petroleum
Exploration Agreement for lands in the onshore Cumberland Basin.
We are also building our base of conventional production in Western Canada with
a four-well drilling program this winter. 

 Highlights
-	Completed the unscheduled turnaround at PX Energy on schedule and on budget,
with no recordable safety incidents
-	Received approval from the Government of Quebec for our carbon storage pilot
-	Signed a mediation protocol with the Attorney General of Quebec and the
Ministry of the Economy, Innovation and Energy
-	Selected by the Province of Nova Scotia as the successful bidder, and
negotiating a Petroleum Exploration Agreement
-	Average daily production of 4,634 boe per day
-	Adjusted funds flow from operations of $2.3 million, after $4.8 million of
idle capacity costs during shutdown and a $5.6 million reduction in contract
liabilities as customers took delivery of pre-paid product, and net cash from
operating activities of $1.7 million

Oil Shale
When we acquired PX Energy, it was breaking even before maintenance capital.
Since taking full management control in January, we have strengthened the local
team. Our new Chief Operating Officer in Brazil also serves as President of our
subsidiary, Red Leaf Resources Inc. We also reorganized management and
introduced contracting discipline. We have also made safety our first priority,
recording one recordable incident this year compared to eight last year. That is
encouraging, and there is more to do.
In late July, a pipe failed in the furnace that heats the retort, and we shut
the plant until August 18. The repair demonstrated our operational capability.
There were no recordable incidents, compared to five during the last scheduled
turnaround. We also removed the buildup in the retort left by an improper
restart after last year's turnaround. Efficiency recovered from about 75% to
over 90%, and internal fuel use fell by more than 25%.
The quarter also showed how much remains to be done. Since the restart, we have
had a minor gas release and, on October 1, the failure of a silo that stores
processed shale from the retort. No one was injured, and production fell by less
than 10% for the month. Repairs are expected to cost about US$4.0 million, most
of it in the fourth quarter. Like the furnace, both incidents trace back to
deferred maintenance.
We are sharpening management's focus on maintenance and on acting quickly once a
problem is found. We are investing in the people who run the plant and assessing
critical equipment before it fails. The 2027 turnaround will go further than a
routine overhaul. By addressing structural integrity, we aim to extend the
interval between turnarounds from 24 months to 30 to 36 months. Fewer
turnarounds mean more production days and lower maintenance costs over time.
Commercially, higher Brent prices have attracted cheaper, lower-quality fuels
into our local market, where demand for high-sulphur fuel oil is shrinking. So
far, higher oil prices have more than offset lower sales volumes and wider
discounts. Through September, PX Energy's operating results were in line with,
or slightly ahead of, its budget. Repairs in the fourth quarter will reduce some
of that margin. We are enforcing our sales contracts for our minimum sales
volumes. Our commercial team is working hard to diversify our markets and
broaden our customer base.
PX Energy's bonds were issued by its holding company and are secured against the
Brazilian business. No principal is due before the bonds mature in April 2028,
and two one-year extensions to 2030 are available. Interest for 2026 is being
paid in kind. From 2027, it is payable in cash unless Brent is below US$65 per
barrel. Most of its costs are fixed, so its cash flow would fall if oil prices
return to more normal levels. The scope of next year's scheduled turnaround has
grown, and its cost could exceed our original estimate of US$10 million.
Together with a prudent contingency for unexpected maintenance, that spending
comes ahead of the cash flow it will generate. That is why we believe the debt
should be restructured to fit its cash flow and investment cycle. 
The resource behind the opportunity is enormous. The Green River Formation in
the western United States alone holds an estimated 4.3 trillion barrels of oil
in place2, more than twice the oil in place in Alberta's oil sands3. The shale
revolution helped make the United States the world's largest crude oil
producer4. We believe HCCO can help oil shale follow the same path.
Our test of HCCO in a commercial-sized vessel at PX Energy's facility earlier
this year cost a fraction of a greenfield pilot because we used an existing
facility. The next step is an extended test with continuous oxygen injection,
which we estimate could reduce internal fuel use by up to 15%. We plan to run it
in 2027, while keeping our first priority on executing the scheduled turnaround
safely and to plan.

Quebec
The Government of Quebec's long-term energy plan, published in June, relies on
natural gas at least through 2050, including to ease winter pressure on the
electricity grid and to meet industrial demand5. In October, outgoing Finance
Minister Eric Girard said the province needs more natural gas6.
Quebec produces almost none of the gas it uses, which leaves consumers exposed
to imported supply and its costs7. Énergir, the provincial gas distributor, has
proposed a 16% increase in balancing rates included in the price of gas supply,
citing a supply deficit on the TC Energy pipeline system8.
The province is also turning to renewable natural gas. Hydro-Québec intends to
use TC Energy's 350 MW Bécancour plant during winter peaks, supplied with
renewable natural gas, starting around 2028 or 20299. In 2025, only about 18% of
Énergir's renewable gas came from Quebec projects, and much of the rest was
bought in the United States10. Its latest rate filing increased the renewable
gas costs spread across customers by $228.3 million, raising the average bill by
7.6% and industrial bills by 13.5%11. Renewable gas costs roughly 3.4 times as
much as conventional gas13. If Bécancour is supplied the same way as Énergir is,
Quebec's insurance for its peak demand days may come at a steep price to
ratepayers.
These pressures have reopened the debate on local production, and public opinion
is shifting with it. In an October poll by Ipsos for the Montreal Economic
Institute, 68% of Quebecers supported developing the province's own natural gas
to meet its needs and export any surplus, while 20% were opposed13. The Globe
and Mail reported in October that Quebec was having second thoughts about its
oil and gas bans12. Energy expert Yvan Cliche said Quebec should keep natural
gas open as an option beyond 203514. Rising heating oil costs have also
strengthened the case for a more diverse energy supply, including natural gas15.
We believe our Utica discovery is part of the answer. It is local supply less
than ten kilometres from Bécancour and well positioned to supply natural gas at
peak demand. Paired with carbon storage, it could have lower emissions than
imported gas.
We see the approval of our carbon storage pilot as confirmation of our strategy
to pursue a business and political solution. The pilot is authorized for five
years and may be extended for two more years16. It will evaluate the subsurface
near the Bécancour industrial park for long-term carbon dioxide storage. We are
seeking funding from the provincial and federal governments and talking with
potential partners. 
Alongside this business and political path, we continue to protect our
shareholders' rights through the legal process. On September 3, we announced
that we had signed a mediation protocol with the Attorney General of Quebec and
the Ministry of the Economy, Innovation and Energy17. The next steps in the
court timetable will be deferred by a minimum of 120 days from the date of
signature. The mediation is voluntary and non-binding and no party is obliged to
reach an agreement. The process is confidential. We will not comment further on
the proceedings or the mediation while it continues, except as required by
securities laws.

Nova Scotia
Nova Scotia ended its ban on hydraulic fracturing17 in 2025. We believe the
lands we are negotiating for in the onshore Cumberland Basin are a large-scale,
early-stage exploration opportunity, much like Quebec when we acquired our land
position over 25 years ago. We expect to finalize the Petroleum Exploration
Agreement in the coming months.

Operating & Financial
With lower production in Brazil due to the shut-in, production averaged 4,634
boe per day in the third quarter, compared to 5,694 boe per day in the second
quarter and 2,926 boe per day in the same period last year. Year-to-date
production averaged 5,496 boe per day (2025: 2,587 boe per day). Production for
the month of October has averaged approximately 5,300 boe per day.
This year's volumes include PX Energy in Brazil, which we acquired at the end of
the third quarter of 2025. Canadian volumes declined year over year because of
the sale of Kakwa Central effective May 1, 2026, and no new wells were brought
on production this year. Last year, we brought on three (1.5 net) wells at Kakwa
North. We plan to drill four wells in Saskatchewan before year-end.
Revenue was $50.8 million for the quarter and $143.9 million year to date.
Higher commodity prices improved our realized prices, partly offset by a $0.5
million realized loss on commodity hedges. Operating costs in Brazil increased
by $5.7 million over the prior quarter, including $4.8 million of idle capacity
costs during the plant shutdown. General and administrative expenses decreased
to $5.0 million from $7.3 million in the second quarter.
We reported a net loss of $27.6 million for the quarter and $17.6 million year
to date. The quarter included net finance expense of $24.2 million, most of it
non-cash. Of that, $15.7 million came from higher forward Brent prices, which
increased the value of the derivative based on Brent-linked interest on PX
Energy's bonds. No cash interest is due or has been paid on the bonds this year.
Adjusted funds flow from operations was $2.3 million for the quarter compared to
$18.3 million in the second quarter, and $41.4 million year to date. Two things
explain the drop. The first is the shutdown. The plant was down for 19 days
while its costs carried on, including $4.8 million of idle capacity costs. The
second is timing. In the second quarter, minimum sales contracts added $6.9
million to adjusted funds flow. The third quarter included a $5.6 million
reduction in contract liabilities as customers took delivery of product they had
paid for earlier in the year, which brought in no new cash relative to sales.
The working capital deficit improved to $13.3 million at September 30, 2026,
from $19.1 million at June 30, 2026 and $52.0 million at December 31, 2025. The
Company holds $42.9 million in cash and cash equivalents. 

Outlook
Our priorities for 2027 are to:
-	Complete a more comprehensive turnaround at PX, aimed at more production days
between turnarounds;
-	Restructure PX's debt to fit its cash flow and investment cycle;
-	Run the extended HCCO test;
-	Finalize the Petroleum Exploration Agreement in Nova Scotia; and
-	Continue the mediation process and meet with the new Government of Quebec.

Just over 20 years ago, the U.S. Congress passed the Energy Policy Act of 2005.
It declared oil shale and other unconventional fuels "strategically important
domestic resources that should be developed to reduce the growing dependence of
the United States on politically and economically unstable sources of foreign
oil imports"18. Twenty years later, oil shale is still largely undeveloped. We
are building the platform to change that. 
We believe we have the technology to help unlock one of the largest undeveloped
oil resources in the world, and we hold a giant natural gas discovery in a
province that needs more energy. We remain focused on turning both into value
for our shareholders.
 
Michael Binnion 
President and Chief Executive Officer
tform to change that. \
We believe we have the technology to help unlock one of the largest undeveloped\
oil resources in the world\, and we hold a giant natural gas discovery in a\
province that needs more energy. We remain focused on turning both into value\
for our shareholders.\
 \
Michael Binnion \
President and Chief Executive Officer\