Headwater Exploration Inc. press release

HEADWATER EXPLORATION INC. ANNOUNCES 2025 RESERVES, FOURTH QUARTER PRODUCTION RESULTS AND OPERATIONS UPDATE

2026-01-16

TSX - Toronto Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · Canada

HEADWATER EXPLORATION INC. ANNOUNCES 2025 RESERVES, FOURTH QUARTER PRODUCTION RESULTS AND OPERATIONS UPDATE Canada NewsWire

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

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.

Proved

Reserves

$M

Proved Plus Probable

Reserves

$M

2026

122,950

141,850

2027

144,520

146,048

2028

121,163

162,800

2029

12,544

136,977

Total Undiscounted

401,177

587,674

Net Present Value of Future Net Revenue

Before Income Tax and Discounted at

After Income Tax and Discounted at

0 %

5 %

10 %

15 %

20 %

0 %

5 %

10 %

15 %

20 %

$M

$M

$M

$M

$M

$M

$M

$M

$M

$M

Proved developed producing

1,580,469

1,300,038

1,094,813

948,758

840,512

1,308,397

1,085,217

917,035

796,776

707,466

Proved developed non-producing

22,085

18,085

15,045

12,732

10,937

16,475

13,596

11,340

9,605

8,252

Proved undeveloped

564,417

435,380

339,626

267,516

212,359

434,931

326,944

247,782

188,757

144,004

Total proved

2,166,971

1,753,503

1,449,485

1,229,007

1,063,808

1,759,803

1,425,757

1,176,158

995,138

859,722

Total probable

1,396,109

936,584

684,811

526,684

419,304

1,075,014

716,912

521,132

398,502

315,479

Total proved plus probable

3,563,080

2,690,087

2,134,296

1,755,691

1,483,111

2,834,817

2,142,669

1,697,291

1,393,641

1,175,202

(1)

Based on the average of GLJ Ltd., McDaniel and Sproule Associates Limited price forecasts effective as at January 1, 2026.

(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, 2025. 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.

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

as of January 1, 2026

FORECAST PRICES AND COSTS

Year

WTI

Crude

Oil

($US/Bbl)

Edmonton

Light Crude

40o API

($Cdn/Bbl)

WCS

Crude Oil

Stream

Quality at

Hardisty

($Cdn/Bbl)

NYMEX Henry Hub

($US/

MMBtu)

Natural Gas AECO Spot

($Cdn/

MMBtu)

AGT

Premium to Henry Hub(1)

($Cdn/MMbtu)

McCully Gas

Price(2)

($Cdn/

MMbtu)

Inflation Rates

%/Year

Exchange Rate (3)

($US/$Cdn)

Forecast

2026

59.92

77.54

65.13

3.74

3.00

9.38

16.14

-

0.73

2027

65.10

83.60

70.43

3.78

3.30

9.25

15.31

2.00

0.74

2028

70.28

90.17

76.90

3.85

3.49

8.87

15.07

2.00

0.74

2029

71.93

92.32

78.71

3.93

3.58

8.98

9.31

2.00

0.74

2030

73.37

94.17

80.29

4.01

3.65

9.08

9.08

2.00

0.74

2031

74.84

96.06

81.90

4.09

3.72

9.19

9.19

2.00

0.74

2032

76.34

97.98

83.53

4.17

3.80

9.30

9.30

2.00

0.74

2033

77.87

99.93

85.20

4.26

3.88

9.41

9.41

2.00

0.74

2034

79.42

101.93

86.91

4.34

3.95

9.53

9.53

2.00

0.74

2035

81.01

103.97

88.65

4.43

4.03

9.64

9.64

2.00

0.74

2036

82.63

106.05

90.42

4.52

4.11

9.76

9.76

2.00

0.74

Thereafter

+2%/yr

+2%/yr

+2%/yr

+2%yr

+2%/yr

+2%/yr

+2%/yr

2.00

0.74

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 2026 – 2028 reflects only the winter producing months (January to April and December) to correlate to the intermittent production strategy employed by the Company to capture seasonal premium pricing. After 2028, 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.

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.