CALGARY, AB, Nov. 12, 2026 /CNW/ -- Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2026, along with a transaction update. Selected financial and operational information is outlined below and should be read in conjunction with the unaudited condensed interim financial statements and the related management's discussion and analysis ("MD&A"). These filings will be available on SEDAR+ at www.sedarplus.ca and the Company's website at www.headwaterexp.com. 

 Financial and Operating Highlights

THIRD QUARTER 2026 HIGHLIGHTS

• On September 7, 2026, Headwater entered into the Arrangement Agreement (as defined below) with Tamarack Valley Energy Ltd. ("Tamarack") for a $10 billion all-stock business combination (the "Transaction"), creating a premier North American oil company as the largest publicly traded pure-play Clearwater producer with over 80,000 boe/d of run-rate production, with shareholders of Headwater and Tamarack also receiving equity securities of Tributary Exploration Inc. ("Tributary"), a new growth-oriented exploration company led by Headwater's current management.

• Achieved record production of 25,555 boe/d representing an increase of 13% from the third quarter of 2025.

• Realized record adjusted funds flow from operations ⁽¹⁾ of $117.9 million ($0.50 per share basic ⁽²⁾).

• Achieved an operating netback, including financial derivatives ⁽²⁾ of $60.14/boe and an adjusted funds flow netback ⁽²⁾ of $50.31/boe.

• Achieved net income of $66.7 million ($0.28 per share basic) equating to $28.45/boe.

• Executed a $62.0 million capital expenditure ⁽³⁾ program inclusive of development, exploration and secondary recovery implementation.

• Declared a cash dividend of $28.5 million, or $0.12 per common share. To date, Headwater has paid out cumulative dividends of $400.8 million to shareholders ($1.69 per common share).

• As at September 30, 2026, Headwater had adjusted working capital ⁽¹⁾ of $18.9 million, working capital of $20.4 million, and no outstanding bank debt.

TRANSACTION UPDATE

On September 7, 2026, Headwater and Tamarack entered into an arrangement agreement (the "Arrangement Agreement"), whereby Tamarack will acquire all of the issued and outstanding shares of Headwater. In connection with the Transaction, certain assets of Headwater and Tamarack, including Headwater's Mannville exploration assets in Alberta, thermal heavy oil opportunities in Saskatchewan and natural gas assets in New Brunswick, will be transferred to Tributary, a newly formed exploration and development company, with shareholders of Headwater and Tamarack receiving equity securities in Tributary. Tributary will be operated by Headwater's current management team and the board of directors of Tributary will consist of current members of the board of directors of Headwater. The Toronto Stock Exchange ("TSX") has conditionally approved the listing of the Tributary securities on the TSX. Listing of such securities is subject to Tributary fulfilling all of the requirements of the TSX. The Transaction will be completed by way of a plan of arrangement under the Business Corporations Act (Alberta) and remains subject to shareholder and court approvals, as well as other customary closing conditions. The special meetings of Headwater and Tamarack shareholders to consider the Transaction are scheduled for November 18, 2026, and closing of the Transaction is expected to occur on November 19, 2026, subject to satisfaction or waiver of the applicable closing conditions.

For further information, see the joint management information circular of Headwater and Tamarack dated October 13, 2026 (the "Circular"), which is available on Headwater's SEDAR+ issuer profile at www.sedarplus.ca. 

OPERATIONS UPDATE

Development in the third quarter of 2026 was focused in Marten Hills West and Greater Pelican, with both areas recently setting record production levels. The new production highs are supported by current corporate water injection rates exceeding 30,000 bbl/d, representing more than a 60% increase in daily injection since the beginning of 2026.

In Marten Hills West during the third quarter, the Company drilled 6 producing wells and 11 injectors across the Clearwater and Grand Rapids formations. Current production levels exceed 18,500 boe/d, with approximately 11,000 bbl/d supported under secondary recovery, representing more than 60% of the area's oil production.

In Greater Pelican, the third quarter was primarily focused on expanding the polymer flood at the 12-30-079-22W4 pad. The Company drilled four 4-leg producing wells, which achieved an average 30-day initial production rate of 200 bbl/d. In addition, seven single leg injectors have been rig-released in the fourth quarter and will be commissioned for polymer injection before year end. Current production from this area has exceeded 1,500 bbl/d and it is anticipated approximately 1,200 bbl/d will be supported by secondary recovery once all injectors are onstream.

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: statements with respect to the Transaction, including but not limited to, the timing of the Headwater and Tamarack special meetings, the anticipated timing of closing, the receipt of required approvals, the conveyance of assets to Tributary, the anticipated board and management of Tributary and the listing of the Tributary securities on the TSX; the expectation that seven single leg injectors in Greater Pelican will be commissioned for polymer injection by year-end; and the expectation approximately 1,200 bbl/d will be supported by secondary recovery once all injectors are onstream in Greater Pelican. 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 Transaction, including the anticipated closing date of November 19, 2026, the satisfaction of the requirements of the TSX with respect to the listing of the Tributary securities, that the remaining required shareholder and court approvals will be obtained, that the other conditions to completion of the Transaction will be satisfied or waived, as applicable and that the Transaction will be completed on the terms and within the timeframe currently anticipated; 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, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, 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, the risk that the Transaction may be varied, accelerated or terminated in certain circumstances; the risk that the required shareholder, court, regulatory or other approvals may not be obtained in a timely manner or at all, or that the other conditions to the Transaction may not be satisfied, or to the extent permitted, waived; 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 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 the Circular and Headwater's most recent Annual Information Form dated March 5, 2026, on SEDAR+ at www.sedarplus.ca, and the risk factors contained therein. 

BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The terms "Mcfe" (or thousand cubic feet of natural gas equivalent) and "boe" (or barrels of oil equivalent) may be misleading, particularly if used in isolation. A Mcfe and boe 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.

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

Total sales, net of blending expense

Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the interim financial statements blending expense is recorded within blending and transportation expense.

Capital expenditures

Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – E&E and capital expenditures – PP&E 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. Adjusted funds flow from operations is an indicator as to whether adjustments are necessary to the level of capital expenditures. For example, in periods where adjusted funds flow from operations is negatively impacted by reduced commodity pricing, capital expenditures may need to be reduced or curtailed to preserve the Company's capital structure and return of capital policy. Management believes that by excluding the impact of changes in non-cash working capital, transaction costs and restricted cash and adjusting for current income taxes in the period, adjusted funds flow from operations provides a useful measure of Headwater's ability to generate the funds necessary to manage the capital needs of the Company. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the Company's financial 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.

Non-GAAP Ratios

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are 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.

Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. Sales volumes exclude the impact of purchased condensate and butane. Operating netback, including financial derivatives is defined as operating netback plus realized gains (losses) on financial derivatives.

Adjusted funds flow from operations per share

Adjusted funds flow from operations per share 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 per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding on a basic or diluted basis.

Supplementary Financial Measures

Per boe numbers

This press release represents various results on a per boe basis including sales, net of blending expense per boe, realized gains (losses) on financial derivatives per boe, royalty expense per boe, transportation expense per boe, production expense per boe, general and administrative expenses per boe, interest income and other expense per boe, current taxes per boe, settlement of decommissioning liability expense per boe and net income per boe. These figures are calculated using sales volumes.

SOURCE Headwater Exploration Inc.