CALGARY, AB, Jan. 15, 2026 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) is pleased to report fourth quarter average production volumes of approximately 24,250 boe/d, 2025 reserves information and an operations update.
Exceptional results across our asset base positioned Headwater for strong fourth quarter production volumes of approximately 24,250 boe/d and 2025 annual production volumes of approximately 22,750 boe/d, representing 12% year over year production per share growth. Adjusted funds flow from operations (1) is estimated to be approximately $326 million (unaudited) providing an estimated adjusted funds flow netback (2) of approximately $39.25 per boe.
During 2025, Headwater executed a capital expenditure program (3) of approximately $228 million (unaudited) including $60 million of waterflood capital, $58 million on land and exploration and $110 million of development capital. The development capital of $110 million (34% of adjusted funds flow from operations), generated 12% production per share growth.
(1) Capital management measure. Refer to "Non-GAAP and
Other Financial Measures" within this press release.
(2) Non-GAAP ratio. Refer to "Non-GAAP and Other Financial
Measures" within this press release.
(3) Non-GAAP financial measure. Refer to "Non-GAAP and
Other Financial Measures" within this press release.
2025 RESERVE HIGHLIGHTS
Reserve additions for the year end 2025 were exceptional. Our continued success with our exploration efforts and secondary recovery implementation have resulted in the following positive changes to our evaluated reserves:
-- Proved developed producing reserves increased by 53% to 44.5 mmboe from
29.2 mmboe, resulting in production replacement (1) of 285% and a
reserves life index ("RLI") (1) of 5.0 years.
-- Total proved reserves increased by 59% to 68.3 mmboe from 43.1 mmboe,
resulting in production replacement of 403% and a RLI of 7.6 years.
-- Total proved plus probable reserves increased by 54% to 104.5 mmboe from
67.9 mmboe, resulting in production replacement of 541% and a RLI of 11.7
years.
-- Achieved finding and development ("F&D") costs (2), including changes in
future development capital of $9.65 per boe on a proved developed
producing basis, $11.04 per boe on a total proved basis and $9.97 per boe
on a total proved plus probable basis.
-- Based on a 2025 adjusted funds flow netback (2) of $39.25/boe, Headwater
achieved recycle ratios (2) of 4.1 on a proved developed producing basis,
3.6 on a total proved basis and 3.9 on a total proved plus probable
basis.
(1) Oil and gas metric that does not have any standardized
meaning under the Canadian Oil and Gas Evaluation
Handbook (the "COGE Handbook") or under National Instrument
51-101 -- Standards of Disclosure for Oil and Gas
Activities ("NI 51-101") and therefore may not be
comparable with the calculation of similar measures
of other entities. Refer to "Oil and Gas Metrics"
within this press release.
(2) Non-GAAP ratio and oil and gas metric that does not
have any standardized meaning under IFRS, the COGE
Handbook or under NI 51-101 and therefore may not
be comparable with the calculation of similar measures
of other entities. Refer to "Non-GAAP and Other Financial
Measures" and "Oil and Gas Metrics" within this press
release.
OPERATIONS UPDATE
Grand Rapids Formation in Marten Hills West
Results from the Grand Rapids are crushing our expectations. Our first production commenced from the Grand Rapids in May 2025, and this zone now contributes over 2,000 bbls/d of production, of which more than 750 bbls/d will be supported under waterflood by mid-February 2026.
In the fourth quarter of 2025, Headwater drilled a 3-mile step-out to the northwest at 03/13-22-075-02W5. This 6-leg well which continues to improve, has achieved a 15-day initial production rate of 300 bbls/d of 19 API oil. The excellent reservoir quality encountered while drilling inspired the team to immediately follow-up with an injection well, which will be placed on injection in mid-February 2026. Success from the 03/13-22-075-02W5 test has expanded the main pools boundaries to an estimated 20 sections.
Greater Pelican Area
In the fourth quarter of 2025, Headwater drilled two development wells following up on the successful 04/04-19-079-22W4 well, which produced 120,000 bbls of oil in its first eight months. The two 4-leg lateral wells at 03/14-31-079-22W4 and 03/3-19-079-22W4 have achieved 30-day initial production rates of 382 and 470 bbls/d, respectively. Polymer injection wells were drilled to support these producers, and they have been on polymer injection at encouraging rates since mid-December.
A 6-leg Wabiskaw exploration test was drilled at 13-34-079-23W4. The well encountered excellent reservoir while drilling, however it also encountered a structural low at the toes of its laterals. The 30-day initial production rate of this well is 80 bbls/d of oil at a 70% water cut. Although this is an economic result, the higher water cut resulted in some adjustments to our geotechnical model. To validate the revised model, a follow-up single lateral well was drilled immediately offsetting the original well and was stopped short of the structural low. This 3/4 length single lateral well has achieved a 20-day initial production rate of 37 bbls/d, which is consistent with the inflow, on a per meter basis, of our other successful Wabiskaw drills.
Production from the Greater Pelican has grown to 1,500 bbls/d, with more than 850 bbls/d supported by secondary recovery. With encouraging early results from the polymer flood, Headwater is enthusiastic about advancing additional polymer flood development in 2026, as well as drilling 2-3 untested exploration prospects.
Secondary Recovery
Headwater finished 2025 with a total of 10 sections and 11,500 bbls/d supported by secondary recovery, representing more than 50% of the Company's oil production. Headwater has proved commerciality of secondary recovery across multiple formations including the Clearwater sandstone, Clearwater E, Grand Rapids and Wabiskaw.
By year end 2026, it is estimated that 14,000 bbls/d, equivalent to 60% of Headwater's corporate oil production, will be supported by secondary recovery.
Our unwavering commitment to the implementation of secondary recovery continues to result in industry leading sustainability and asset duration. With the continued focus on secondary recovery, we anticipate that we will exit 2026 with a decline rate of less than 20% and maintenance capital of less than 30% of adjusted funds flow from operations at US$60 WTI. Headwater currently estimates that it is fully funded to maintain production and pay its base dividend at US$46 WTI.
2025 RESERVES INFORMATION
Headwater currently has reserves primarily located in the greater Marten Hills area of Alberta and reserves in the McCully Field near Sussex, New Brunswick. McDaniel & Associates Consultants Ltd. ("McDaniel") assessed the Company's reserves in its report dated effective December 31, 2025 ("McDaniel Report") which was prepared in accordance with standards of the COGE Handbook and NI 51-101 and is based on the average forecast prices as at January 1, 2026, of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information will be included in Headwater's Annual Information Form for the year ended December 31, 2025, expected to be filed on SEDAR+ on or around March 5, 2026.
The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by McDaniel, effective December 31, 2025. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates provided herein. Reserves information may not add due to rounding.
Reserves Summary
Heavy Shale Conventional Oil
Oil Gas Natural Gas NGL Equivalent
Mbbls MMcf MMcf Mbbls MBOE
Proved developed producing 40,734 719 21,035 166 44,526
Proved developed non-producing 268 1,498 17 2 523
Proved undeveloped 22,455 - 4,203 74 23,229
Total proved 63,458 2,217 25,255 242 68,278
Total probable 34,272 681 10,263 131 36,227
Total proved plus probable 97,730 2,898 35,518 372 104,505
(1) Reserves have been presented on a gross basis which
are the Company's total working interest share before
the deduction of any royalties and without including
any royalty interests of the Company.
(2) Based on the average of GLJ Ltd., McDaniel and Sproule
Associates Limited price forecasts effective as at
January 1, 2026.
(3) Pursuant to the COGE Handbook, reported reserves should
target at least a 90 percent probability that the
quantities actually recovered will be equal to or
exceed the estimated proved reserves and that at least
a 50 percent probability that the quantities actually
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