HEADWATER EXPLORATION INC. ANNOUNCES 2025 RESERVES, FOURTH QUARTER PRODUCTION RESULTS AND OPERATIONS UPDATE
HEADWATER EXPLORATION INC. ANNOUNCES 2025 RESERVES, FOURTH QUARTER PRODUCTION RESULTS AND OPERATIONS UPDATE |
| [15-January-2026] |
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.
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:
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
Future Development Costs ("FDC") The following is a summary of the estimated FDC required to bring proved undeveloped reserves and proved plus probable undeveloped reserves on production.
Net Present Value of Future Net Revenue
Pricing Assumptions The following tables set forth the benchmark reference prices, as at December 31, 2025, reflected in the McDaniel Report, using the average of commodity price forecasts from McDaniel, GLJ Ltd. and Sproule Associates Limited effective as at January 1, 2026, to estimate the reserves volumes and associated values in the McDaniel Report. SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
Notes:
Additional corporate information can be found in the Company's corporate presentation and on Headwater's website at www.headwaterexp.com. FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial, "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation; the expectation that 750 bbls/d will be supported under waterflood by mid-February 2026 in the Grand Rapids area; the expectation to follow up the 03/13-22-075-02W5 well with an injection well in the Grand Rapids, which will be placed on injection in mid-February 2026; the expectation to advance additional polymer flood development in 2026, as well as drilling 2-3 untested exploration prospects in the Greater Pelican area; the expectation by year end 2026 that 14,000 bbls/d, equivalent to 60% of Headwater's corporate oil production, will be supported by secondary recovery; the expectation that we will exit 2026 with a decline rate of less than 20% and maintenance capital of approximately 30% of adjusted funds flow from operations at US$60 WTI; the expectation of our ability to be fully funded to maintain production and pay our base dividend at US$46 WTI; and the intent to file our Annual Information Form for the year ended December 31, 2025 on or around March 5, 2026. In addition, all statements relating to "reserves" are also deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approvals, the success of future drilling, development and waterflooding activities, the performance of existing wells, the performance of new wells, Headwater's growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, prevailing commodity prices and certain other guidance assumptions as detailed below under the heading "Future Oriented Financial Information" as set out below. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the Russian-Ukrainian war and the Israel-Hamas war and the impact on the global economy and commodity prices; the impacts of United States interventions in Venezuela; the impacts of inflation and supply chain issues and steps taken by central banks to curb inflation; pandemics and other major health events, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including actions taken by the OPEC + group; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), the impact of tariffs imposed by the United States, Canada and other countries on the Canadian and global economy and the oil and gas industry, commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures, and changes in how management and the Board of Directors of the Company determine to allocate capital. Refer to Headwater's Annual Information Form dated March 13, 2025, on SEDAR+ at www.sedarplus.ca, and the risk factors contained therein. BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term "boe" (or barrels of oil equivalent) and "Mcf" (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value. INITIAL PRODUCTION RATES: References in this press release to initial production ("IP") rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary. PRODUCTION VOLUMES: With respect to the 2025 average fourth quarter production volumes presented herein, such volumes are comprised of: 22,100 bbls/d of heavy oil, 140 bbls/d of natural gas liquids and 12.1 mmcf/d of natural gas. With respect to the 2025 full-year average production volumes presented herein, such volumes are comprised of: 20,700 bbls/d of heavy oil, 160 bbls/d of natural gas liquids and 11.4 mmcf/d of natural gas. NON-GAAP AND OTHER FINANCIAL MEASURES Non-GAAP Financial Measures In this press release, we refer to certain financial measures which do not have any standardized meaning prescribed by IFRS. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this press release contains the term adjusted funds flow from operations, which is considered a capital management measure. Non-GAAP and other financial measures within this press release are calculated consistently with the three months and nine months ended September 30, 2025 reconciliations as outlined below. Capital expenditures Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's interim financial statements.
Capital Management Measures Adjusted Funds Flow from Operations Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the performance of the Company's oil and gas properties. Adjusted funds flow from operations is an indicator of operating performance as it varies in response to production levels and management of production and transportation costs. Management believes that by eliminating changes in non-cash working capital and restricted cash and deducting current income taxes, adjusted funds flow from operations is a useful measure of operating performance.
Non-GAAP Ratios This press release contains the terms adjusted funds flow netback, F&D costs per boe and recycle ratio, which are considered non-GAAP ratios and may also be considered oil and gas metrics. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. Adjusted funds flow netback Adjusted funds flow netback is a non-GAAP ratio and is used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period. F&D costs per boe F&D costs is used as a measure of capital efficiency. The F&D cost calculation includes all capital expenditure (exploration and development) for that period plus the change in future development capital ("FDC") for that period based on the evaluations completed by McDaniel as at December 31, 2025 as compared to the evaluation completed by McDaniel as at December 31, 2024. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period. Total proved developed producing F&D is calculated as follows = ($228.3 million (2025 capital expenditures) - 47 thousand (change in FDC associated with proved developed producing reserves)) / (44,526 mboe – 29,183 mboe + 8,313 mboe) = $9.65 per boe. Total proved F&D is calculated as follows = ($228.3 million (2025 capital expenditures) + $141.8 million (change in FDC associated with total proved reserves)) / (68,278 mboe – 43,075 mboe + 8,313 mboe) = $11.04 per boe. Total proved plus probable F&D is calculated as follows = ($228.3 million (2025 capital expenditures) + $220 million (change in FDC associated with total proved plus probable reserves)) / (104,505 mboe – 67,853 mboe + 8,313 mboe) = $9.97 per boe. Recycle ratio Recycle ratio is used as a measure of profitability. Recycle ratio is calculated as the Company's adjusted funds flow netback divided by F&D costs per boe. Oil and Gas Metrics This press release contains the terms adjusted funds flow netback, RLI, production replacement, F&D costs per boe and recycle ratio, which are considered oil and gas metrics that do not have standardized meanings under the COGE Handbook or under NI 51-101. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. For information related to adjusted funds flow netback, F&D costs per BOE and recycle ratio see "Non-GAAP and Other Financial Measures". Reserve life index ("RLI") (years) RLI is a measure of how long a particular category of reserves will last (in years) at the current rate of production. It is calculated by taking the total quantity of reserves (boe) divided by annualized Q4 2025 production (boe/d). Production replacement Production replacement measures how much annual production has been replaced by new reserve additions. It is calculated by taking the total change in reserves (boe) divided by 2025 annual production (boe). SOURCE Headwater Exploration Inc. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Company Codes: Toronto:HWX | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
