Company Announcements

CALGARY, AB , Sept. 8, 2025 /CNW/ - Headwater Exploration Inc. ("Headwater" or the "Company") (TSX: HWX) is excited to announce an increase to 2025 production guidance, in conjunction with updated operational results. In addition, Headwater will be attending the Peters & Co. Limited 29th Annual Fall Energy Conference in Toronto, Ontario on September 9^th -11^th, 2025. An updated corporate presentation is available on Headwater's website at www.headwaterexp.com.

GUIDANCE UPDATE

Exceptional results across our portfolio including exploration in Greater Pelican and in the Grand Rapids formation in Marten Hills West, backstopped by improving declines from secondary recovery, have positioned Headwater to increase production guidance and re-allocate capital to additional exploration and sustainability initiatives.

Fourth quarter production is expected to now average 23,500-24,000 boe/d representing a year over year increase of 11%. This results in annual production guidance increasing to 22,600 boe/d from 22,250 boe/d. Headwater's production increase is expected to be achieved with 33% less development wells and $35 million less capital than originally budgeted due to exceptional results and a sustainable downward trend towards half cycle well costs.

The available capital within our current budget has allowed Headwater flexibility to focus on accelerating sustainability initiatives including:

• $10 million of incremental secondary recovery spending including two water injection pilots in the Grand Rapids formation and a polymer pilot in Greater Pelican.
• $10 million of incremental exploration drilling including two additional step-out locations in Greater Pelican and three incremental Grand Rapids step out tests in Marten Hills West.
• $15 million of incremental land expenditures allowing us to continue to build high quality drilling inventory for the future.

OPERATIONAL UPDATE

Grand Rapids Formation in Marten Hills West

The Grand Rapids discovery well drilled at 07/4-18-075-01W5 has now achieved a 120-day initial production rate of 342 bbl/d and continues to produce at rates over 300 bbl/d.

Headwater has recently brought on production two additional Grand Rapids tests in Marten Hills West. The 06/12-07-075-01W5 well has achieved a 30-day initial production rate of 300 bbl/d of 18.7 API oil. This 6-leg multi-lateral was drilled in a configuration for secondary recovery and will be one of two planned secondary recovery pilots commissioned prior to year end. The second well, 04/03-17-075-01W5 has recently finished recovering load fluid and is currently producing 250 bbl/d.

The balance of 2025 will include 5 additional Grand Rapids tests including 3 exploration tests intended to expand the boundaries of the current pool estimated to be 15 sections in size.

Greater Pelican Update and Expansion

Results from the 04/04-19-079-22W4 Wabiskaw discovery well continue to be exceptional, cumulative production from the well which commenced on April 26, 2025, is over 63,000 bbls and daily rates continue to exceed 500 bbl/d.

The balance of 2025 will be focused on a combination of exploration and sustainability activity including two step-out multi-lateral tests and commissioning of our first muti-lateral polymer pilot.

Committed to continued land expansion, Headwater has entered into an agreement to acquire 10 sections of land in the Greater Pelican area adjacent to the Bigstone Cree Nation block where our 04/04-19-079-22W4 discovery well was drilled. As consideration for the land acquisition, Headwater will issue 1 million common shares. The agreement also provides Headwater an 18-month option to acquire an additional offsetting 8 sections of land for an additional 750,000 common shares. The issuance of common shares pursuant to the agreement is subject to Toronto Stock Exchange approval and the transaction is expected to close mid September 2025.

Secondary Recovery

With the newly discovered Grand Rapids pool, Marten Hills West offers secondary recovery opportunity within the Clearwater sandstone, Clearwater E and Grand Rapids zones. The accessibility to high volumes of original oil in place, stacked formations from one surface location in addition to increased reserve life from secondary recovery provides half cycle cost structures and a long-term sustainable development strategy in Marten Hills West.

Combining secondary recovery from three zones in Marten Hills West, in addition to 7,000 bbl/d of stabilized production in the core area and the Company's first polymer pilot at Greater Pelican, Headwater expects to have more than 50% of its corporate oil production supported under secondary recovery by year end 2025.

OUTLOOK

Timely capital allocation adjustments in response to changing market conditions provide Headwater the ability to continually optimize return on invested capital.

Headwater remains focused on sustainability and maximizing total shareholder returns through organic expansion, enhanced oil recovery, dividends and strategic buybacks under its ongoing NCIB.

Additional corporate information, including the Company's updated corporate presentation, can be found 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: 2025 production and capital guidance and the breakdown thereof; expected adjusted funds flow from operations, expected dividends, and expected exit adjusted working capital; expected fourth quarter 2025 production; the expectation that the production increase will be achieved with 33% less development wells and $35 million less capital than originally anticipated; the expectation to spend $10 million on incremental secondary recovery spending including two water injection pilots in the Grand Rapids formation and a polymer pilot in Greater Pelican; the expectation to spend $10 million of incremental exploration drilling including two additional step-out locations in Greater Pelican and three incremental Grand Rapids step out tests in Marten Hills West; the expectation to spend $15 million of incremental land expenditures allowing Headwater to continue to build high quality drilling inventory for the future; the expectation the Company will drill 5 additional Grand Rapids tests including 3 exploration tests intended to expand the boundaries of the current pool estimated to be 15 sections in size; the expectation the balance of 2025 in Greater Pelican will be focused on a combination of exploration and sustainability activity including two step-out multi-lateral tests and commissioning of our first muti-lateral polymer pilot; the expected closing timing of the land transaction in Greater Pelican; the expectation Headwater will have more than 50% of its corporate oil production supported under secondary recovery by year end 2025; and the expectation that Headwater remains focused on sustainability and maximizing total shareholder returns through organic expansion, enhanced oil recovery, dividends and strategic buybacks under its ongoing NCIB. 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 secondary recovery 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 and prevailing commodity prices. 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; risks associated with wildfires in areas in which the Company operates including safety of personnel, asset integrity and potential disruption of operations which could affect the Company's results, business, financial conditions or liquidity; the impact of tariffs and other trade retaliatory measure imposed by the United States, Canada and other countries; disruptions to the Canadian and global economy resulting from major public health events, the Russian-Ukrainian war and the conflict in the Middle-East and the impact that such events may have on the global economy and commodity prices; the impacts of inflation and supply chain issues and steps taken by central banks to curb inflation; pandemics, 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); commodity price and exchange rate fluctuations; changes in legislation affecting the oil and gas industry; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures and the risk that the Company's pools may be smaller than anticipated. Refer to Headwater's most recent Annual Information Form dated March 13, 2025, on SEDAR+ at www.sedarplus.ca, and the risk factors contained therein. 

GUIDANCE AND FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2025 have been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. The assumptions used in the updated 2025 guidance include: annual average production of 22,600 boe/d, WTI of US$66.50/bbl, WCS of Cdn$76.60/bbl, AGT US$9.00/mmbtu, AECO of $1.65 CAD/GJ, foreign exchange rate of US$/Cdn$ of 0.72, blending expense of WCS less $1.90, royalty rate of 18.3%, operating and transportation costs of $13.95/boe, G&A and interest income and other expense of $1.30/boe and cash taxes of $4.70/boe. The AGT price is the average price for the winter producing months in the McCully field which include January to April and November to December. 2025 annual production guidance is comprised of: 20,600 bbls/d of heavy oil, 140 bbls/d of natural gas liquids and 11.2 mmcf/d of natural gas.

DIVIDEND POLICY: The amount of future cash dividends paid by the Company if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, adjusted funds flow from operations, fluctuations in commodity prices, production levels, capital expenditure requirements, acquisitions, debt service requirements and debt levels, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the Board will adjust the Company's dividend policy from time to time and, as a result, future cash dividends could be reduced or suspended entirely.

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.

ORIGINAL OIL-IN-PLACE ("OOIP"): The term OOIP as used herein is equivalent to Total Petroleum Initially-In-Place ("TPIIP"). TPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered.

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.

NON-GAAP AND OTHER FINANCIAL MEASURES: In this press release, we use various non-GAAP and other financial measures to analyze operating performance and financial position. These non-GAAP and other financial measures do not have standardized meanings prescribed under IFRS and therefore may not be comparable to similar measures presented by other issuers.

Non-GAAP Financial Measures

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 adjusting for current income taxes in the period, adjusted funds flow from operations is a useful measure of operating performance.

Adjusted Working Capital

Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity. Financial derivative receivable/liability have been excluded as these contracts are subject to a high degree of volatility prior to settlement and relate to future production periods. Financial derivative receivable/liability are included in adjusted funds flow from operations when the contracts are ultimately realized. Management has included the effects of the repayable contribution to provide a better indication of Headwater's net financing obligations.

SOURCE Headwater Exploration Inc.