Headwater Exploration Inc. Announces 2024 Reserves, Year End 2024 Operating and Financial Results, Operations Update and Declares Quarterly Dividend

CALGARY, ALBERTA – Headwater Exploration Inc. (the “Company” or “Headwater“) (TSX:HWX) announces its operating and financial results for the three months and year ended December 31, 2024. Selected financial and operational information is outlined below and should be read in conjunction with the audited financial statements and the related management’s discussion and analysis (“MD&A”).  In addition, readers are also directed to the Company’s Annual Information Form for the year ended December 31, 2024, dated March 13, 2025. These filings will be available on SEDAR+ at www.sedarplus.ca and the Company’s website at www.headwaterexp.com.

Financial and Operating Highlights

(1) Non-GAAP financial measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(2) Capital management measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(3) Non-GAAP ratio. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(4) Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the audited annual financial statements blending expense is recorded within blending and transportation expense.

(5) In-the-money dilutive instruments as at December 31, 2024 include 177 thousand stock options with a weighted average exercise price of $4.56. Restricted share units (“RSU”) and performance share units (“PSU”) have been excluded as the Company intends to cash settle these awards.

(6) Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company’s heavy crude oil sales volumes and production volumes differ due to changes in inventory. For the three months ended December 31, 2024, sales volumes comprised of 20,288 bbs/d of heavy oil, 7.2 mmcf/d of natural gas and 51 bbls/d of natural gas liquids (2023 – heavy oil of 18,709 bbls/d, natural gas of 8.0 mmcf/d and natural gas liquids of 93 bbls/d). For the year ended December 31, 2024, sales volumes comprised of 19,060 bbls/d of heavy oil, 6.9 mmcf/d of natural gas and 67 bbls/d of natural gas liquids (2023- heavy oil of 16,465 bbls/d, natural gas of 8.8 mmcf/d and natural gas liquids of 98 bbls/d).

(7) Netbacks are calculated using average sales volumes.

(8) Excludes unrealized foreign exchange gains/losses, accretion on decommissioning liabilities, interest on lease liability and interest on repayable contribution.

(9) See ‘”Barrels of Oil Equivalent.”

FOURTH QUARTER 2024 HIGHLIGHTS

• Achieved record average production of 21,559 boe/d, an increase of 8% over 2023 fourth quarter production of 19,939 boe/d.
• Realized adjusted funds flow from operations ⁽¹⁾ of $87.9 million ($0.37 per basic share ⁽²⁾), cash flows from operating activities of $76.0 million ($0.32 per basic share) and free cash flow ⁽³⁾ of $39.2 million.
• Achieved an operating netback, including financial derivatives ⁽²⁾, of $51.89/boe and an adjusted funds flow netback ⁽²⁾ of $44.34/boe.
• Generated net income of $48.9 million ($0.21 per basic share) equating to $24.68/boe.
• Executed a $48.7 million capital expenditure ⁽³⁾ program including 8 net crude oil wells in Marten Hills West at a 100% success rate, 13 injection wells and 1 water source well.
• Returned $0.10 per common share, or $23.8 million, to shareholders.
• As at December 31, 2024, Headwater had working capital of $78.7 million, adjusted working capital ⁽¹⁾ of $67.6 million and no outstanding bank debt.

YEAR ENDED DECEMBER 31, 2024 HIGHLIGHTS

• Achieved average production of 20,310 boe/d, an increase of 13% over 2023 annual production of 18,038 boe/d.
• Realized adjusted funds flow from operations ⁽¹⁾ of $336.6 million ($1.42 per basic share ⁽²⁾), cash flows from operating activities of $316.7 million ($1.34 per basic share) and free cashflow ⁽³⁾ of $113.7 million.
• Achieved an operating netback, including financial derivatives ⁽²⁾, of $53.07/boe and an adjusted funds flow netback ⁽²⁾ of $45.35/boe.
• Generated record net income of $188.0 million ($0.80 per basic share) equating to $25.34/boe.
• Executed a $222.9 million capital expenditure ⁽³⁾ program:
  • Drilled 76 net crude oil wells during the year ended December 31, 2024, including 60 wells in Marten Hills West, 8 wells in the Greater Nipisi area, 6 wells in the Greater Peavine area, with the remainder attributed to newer exploration areas including Handel, Saskatchewan;
  • Pursued secondary recovery efforts with approximately 35% of Headwater’s heavy oil production stabilized by December 31, 2024; and
  • Continued accumulation of organic growth opportunities in and beyond the boundaries of the Clearwater. To date, Headwater now holds more than 800 net sections of land across Western Canada.
• Returned a total of $0.40 per common share, or $95.0 million, to shareholders. On December 5, 2024, the Company announced an increase to its quarterly cash dividend to $0.11 per common share ($0.44 per common share annualized) effective for the dividend to be paid on April 15, 2025, to shareholders of record at the close of business on March 31, 2025. To date, Headwater has paid out a cumulative dividend of $212.9 million to shareholders ($0.90 per common share).
• Proved developed producing reserves increased by 32% to 29.2 mmboe from 22.1 mmboe.
• Total proved reserves increased by 33% to 43.1 mmboe from 32.5 mmboe.
• Total proved plus probable reserves increased by 31% to 67.9 mmboe from 51.9 mmboe. 
• Achieved finding and development (“F&D”) costs ⁽²⁾, including changes in future development costs of $15.32 per boe on a proved developed producing basis, $15.93 per boe on a total proved basis and $12.95 per boe on a total proved plus probable basis.
• Based on a 2024 adjusted funds flow netback ⁽²⁾of $45.35/boe, achieved recycle ratios ⁽²⁾of 3.0 on a proved developed producing basis, 2.9 on a total proved basis and 3.5 on a total proved plus probable basis. 

(1) Capital management measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(2) Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(3) Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to “Non-GAAP and Other Financial Measures” within this press release.

OPERATIONS UPDATE

Marten Hills West 

In the fourth quarter of 2024, Headwater had an active Marten Hills West program drilling 8 successful multi-lateral producing wells and commissioning our second full section secondary recovery pilot.

Headwater continued to push the south and eastern pool boundaries of the Clearwater sandstone with successful step-out tests at 00/10-10-075-01W5 and 00/11-10-075-01W5. The 00/10-10-075-01W5 well has achieved a 90-day initial production rate of 117 bbls/d and the 00/11-10-075-01W5 well achieved a 90-day initial production rate of 270 bbls/d. In the first quarter of 2025, Headwater offset these expansion wells with a test at 03/06-10-075-01W5 which has achieved a 30-day initial production rate of 325 bbls/d.

Results from the Clearwater sandstone secondary recovery pilots continue to gain momentum with the commissioning of our second full section waterflood pilot in section 22-075-02W5. Injection rates in the sandstone are now exceeding 2,400 bbls/d, with stabilized oil volumes increasing from 250 bbls/d to approximately 900 bbls/d over the past 4 months. We are highly encouraged with these results and are excited to move forward with an additional 2-3 sections budgeted for secondary recovery implementation in 2025.  With the expansion contemplated in 2025, we anticipate having 2,000 bbls/d of oil supported by year-end.

Clearwater E development has continued with current oil rates from this zone exceeding 700 bbls/d.  Winter access roads were utilized to re-activate the 00/04-35-076-02W5 Clearwater E exploratory well drilled last winter. The well achieved a 60-day initial rate of 135 bbls/d of 24 API oil validating the northern extension. An all-weather road will be built to access the area and support further development in the third quarter of 2025. Our two active secondary recovery pilots at 02/16-07-075-01W5 and 00/13-07-075-01W5 are showing encouraging results, with early indications of subsiding gas-oil ratios and decline mitigation.  The 2025 budget contemplates drilling up to 15 Clearwater E multi-laterals supported by two sections of planned secondary recovery.

Marten Hills Core

Results from secondary recovery in the core continue to perform beyond expectation with 8 of 9 sections now supported.  All supported sections continue to show extremely positive results, with production rates exceeding 7,000 bbls/d having stayed flat for more than 14 months.

Greater Pelican

Headwater is excited to report achieving final Indian Oil and Gas Canada approval on the first segment of the 34.5 section land partnership with the Bigstone Cree Nation (“BCN”) in the Greater Pelican Area. The Company is on track to spud our first well targeting the Wabiskaw formation late in the first quarter of 2025.

Headwater has captured more than 57 sections in the Greater Pelican area with multiple identified prospects. In addition to the test scheduled for the first quarter of 2025, we plan to test 2-3 additional identified concepts in 2025.  

Greater Nipisi

The discovery well at Little Horse South, 16-29-076-14W5 has achieved a 120-day initial production rate of 178 bbls/d. Based on these exceptional results, Headwater is currently drilling two follow-up tests offsetting the original discovery well to continue to validate this pool that could be 15-20 sections in size.

Headwater recently rig released a Bluesky exploration test on the northern 20 section block of Little Horse. The northern test at 05-26-077-14W5 was drilled through a fault block and into a suspected gas cap. A technical review is underway to determine placement of stratigraphic tests for further prospect evaluation.

In the West Nipisi expansion area, Headwater utilized winter access roads to re-activate the 00/05-18-077-11W5 Clearwater F well and conduct a two well exploration program to further evaluate the commercial viability of an all-weather access road.  The results although encouraging, do not currently provide sufficient justification for an all-weather access road.

Greater Peavine – Seal

Two large diameter multi-lateral wells were drilled via winter access roads on the western side of Seal for evaluation. Unfortunately both wells were shut-in late in February due to early break-up conditions before recovering load fluid.

The remainder of the ongoing six well Seal program will utilize a combination of large diameter and Stingwray well technology to test multiple formations on our eastern Seal acreage.

Handel

Headwater conducted a 3D seismic shoot in Handel across 31 sections of land and has identified multiple Mannville targets that will be further delineated with stratigraphic tests in the second half of 2025.

The 3D seismic has identified multiple Waseca channels that will be tested to determine the possibility of steam-assisted gravity drainage development. In addition, the 3D seismic has provided strong indications of multiple structural traps that could provide conventional heavy oil development.

McCully

McCully was placed back on production December 1^st to align with our aggressive hedging profile. Approximately 87% of our December 2024 to April 2025 volumes are hedged at Cdn$10.40/mcf which is expected to provide approximately $15 million of free cash flow ⁽¹⁾ over the winter producing season ⁽²⁾. Headwater’s structured hedging program for the McCully assets has provided consistent cash flow against highly volatile gas pricing experienced during the winter season.

(1) Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to “Non-GAAP and Other Financial Measures” within this press release.

(2) McCully’s winter season is estimated to be December 1, 2024 to April 30, 2025.

FIRST QUARTER DIVIDEND

The Board of Directors of Headwater confirms a cash dividend to shareholders of $0.11 per common share payable on April 15, 2025, to shareholders of record at the close of business on March 31, 2025. This dividend is an eligible dividend for the purposes of the Income Tax Act (Canada).

OUTLOOK

Since inception, we have continued to maintain a positive working capital balance.  When combined with our existing credit facility, it provides us with optionality to organically expand our resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes.

Headwater continues to focus on total shareholder returns through a combination of growth and return of capital.

2024 RESERVES INFORMATION

Headwater currently has reserves primarily located in the Marten Hills, Greater Peavine and Greater Nipisi areas 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, 2024 (“McDaniel Report”) which was prepared in accordance with standards of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and is based on the average forecast prices as at December 31, 2024 of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information is included in Headwater’s Annual Information Form for the year ended December 31, 2024, filed on SEDAR+ on March 13, 2025.     

The following tables are a summary of Headwater’s petroleum and natural gas reserves, as evaluated by McDaniel, effective December 31, 2024. 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

(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, 2025.

(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 recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Net Present Value of Future Net Revenue

(1) Based on the average of GLJ Ltd., McDaniel and Sproule Associates Limited price forecasts effective as at January 1, 2025.

(2) All future net revenues are stated prior to provision for interest income and other, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures.

(3) After-income tax net present value of future net revenue are based on Headwater’s estimated tax pools as at December 31, 2024. The after-income tax net present value of Headwater’s oil and natural gas properties reflects the income tax burden on the properties on a stand-alone basis and takes into account Headwater’s existing tax pools. It does not consider tax planning.

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.

 (1) Future development capital after 2027 is associated with McCully gas plant optimization.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2024, 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, 2025, to estimate the reserves volumes and associated values in the McDaniel Report. 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2024
FORECAST PRICES AND COSTS

Notes:

(1) Not a published forecast. McDaniel’s estimate of the AGT premium to Henry Hub.

(2) The forecast McCully gas price is used by McDaniel in calculating the net present value of Headwater’s future natural gas net revenues from the McCully Field. The McCully gas price is determined by adjusting the forecast AGT gas prices to reflect the expected premiums received at Headwater’s delivery point, transportation costs, as applicable, heat content and marketing conditions. The McCully gas price in years 2025 – 2027 reflects only the winter producing months (January to April and December) to correlate to the intermittent production strategy employed by the Corporation to capture seasonal premium pricing. After 2027, the McDaniel Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year.

(3) The exchange rate used to generate the benchmark reference prices in this table.

(4) As at December 31, 2024.

Additional corporate information can be found in the Company’s corporate presentation and on Headwater’s website at www.headwaterexp.com

FOR FURTHER INFORMATION PLEASE CONTACT:

HEADWATER EXPLORATION INC.                           HEADWATER EXPLORATION INC.

Mr. Neil Roszell, P. Eng.                                             Mr. Jason Jaskela, P.Eng.                                           

Executive Chair                                                           President and Chief Executive Officer

HEADWATER EXPLORATION INC.

Ms. Ali Horvath, CPA, CA

Chief Financial Officer

info@headwaterexp.com

(587) 391-3680

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; that with the secondary recovery expansion contemplated in 2025 in Marten Hills West, 2,000 bbls/d of oil will be supported by year-end; the expectation that an all-weather road will be built to access the Clearwater E development and support further development in the third quarter of 2025;  the expected Clearwater E development and planned secondary recovery development; the expectation that the Company will spud its first well targeting the Wabiskaw formation late in the first quarter of 2025; the expectation to test an additional 2-3 identified concepts in 2025 in the Greater Pelican area; the expectation that success in Little Horse south could validate a new pool estimated to be 15-20 sections in size; the timing and results of the stratigraphic test wells in Handel; the results of the 3D seismic shoot in Handel and whether the results will determine the possibility of steam-assisted gravity drainage or a conventional heavy oil development; the expectation of McCully’s performance and free cash flow through the 2024/2025 winter season; the expectation that the Company’s positive working capital balance and credit facility will provide Headwater the optionality to organically expand its resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes; and the intent of Headwater to continue to focus on total shareholder returns through a combination of growth and return of capital. 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 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. Refer to Headwater’s Annual Information Form dated March 13, 2025, on SEDAR+ at www.sedarplus.ca, and the risk factors contained therein.

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 has 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.

DIVIDENDS: 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 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.

INITIAL PRODUCTION RATES: References in this press release to initial production 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

Non-GAAP Financial Measures

In this press release, we refer to certain financial measures (such as free cash flow, total sales, net of blending and capital expenditures) 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.

Free cash flow

 Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures.  

 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 audited annual 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 – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company’s audited annual financial statements netted by the government grant.

Capital Management Measures

This press release contains the terms adjusted funds flow from operations and adjusted working capital, which are considered capital management measures.  The term cash flow in this press release is equivalent to adjusted funds flow from operations.

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 deducting current income taxes, 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 contribution receivable and repayable contribution to provide a better indication of Headwater’s net financing obligations. 

Non-GAAP Ratios

This press release contains the terms adjusted funds flow netback, operating netback and operating netback, including financial derivatives, 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, 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. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate and butane. Operating netback, including financial derivatives is defined as operating netback plus realized gains or losses on financial derivatives.

Adjusted funds flow per share

Adjusted funds flow 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.

 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, 2024 as compared to the evaluation completed by McDaniel as at December 31, 2023. 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 = ($222.9 million (2024 capital expenditures) + -$26 thousand (change in FDC associated with proved developed producing reserves)) / (29,183 mboe – 22,071 mboe + 7,433 mboe) = $15.32 per boe. Total proved F&D is calculated as follows = ($222.9 million (2024 capital expenditures) + $63.8 million (change in FDC associated with total proved reserves)) / (43,075 mboe – 32,517 mboe + 7,433 mboe) = $15.93 per boe. Total proved plus probable F&D is calculated as follows = ($222.9 million (2024 capital expenditures) + $79.6 million (change in FDC associated with total proved plus probable reserves)) / (67,853 mboe – 51,925 mboe + 7,433 mboe) = $12.95 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.

Per boe numbers

 This press release represents various results on a per boe basis including Headwater average realized sales price, net of blending, financial derivatives gains (losses) 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 and current taxes per boe. These figures are calculated using sales volumes.