HEADWATER EXPLORATION INC. ANNOUNCES 2023 RESERVES, YEAR END 2023 OPERATING AND FINANCIAL RESULTS, OPERATIONS UPDATE, INCREASE TO 2024 CAPITAL BUDGET AND DECLARES QUARTERLY DIVIDEND

CALGARY, AB, March 7, 2024 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) announces its operating and financial results for the three months and year ended December 31, 2023. 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").  These filings will be available at www.sedarplus.ca and the Company's website at www.headwaterexp.com. In addition, readers are also directed to the Company's Annual Information Form for the year ended December 31, 2023, dated March 7, 2024, filed on SEDAR+ at www.sedarplus.ca.

Financial and Operating Highlights

	Three months ended  December 31,		Percent   Change		Year ended December 31,		Percent   Change
	2023	2022			2023	2022
Financial (thousands of dollars except per share and production data)
Sales, net of blending ^(1) (4)	131,690	102,974	28		482,823	430,047	12
Adjusted funds flow from operations ^(2)	81,983	71,828	14		288,262	279,727	3
Per share - basic ^(3)	0.35	0.31	13		1.22	1.23	(1)
- diluted ^(3)	0.34	0.31	10		1.21	1.21	-
Cash flows provided by operating activities	90,690	66,448	36		303,316	283,925	7
Per share - basic	0.38	0.29	31		1.29	1.25	3
- diluted	0.38	0.28	36		1.28	1.23	4
Net income	45,469	39,789	14		156,072	162,109	(4)
Per share - basic	0.19	0.17	12		0.66	0.71	(7)
- diluted	0.19	0.17	12		0.66	0.70	(6)
Capital expenditures ^(1)	30,050	60,677	(50)		233,846	244,495	(4)
Adjusted working capital ^(2)					63,526	104,918	(39)
Shareholders' equity					610,498	543,335	12
Dividends declared	23,658	23,392	1		94,421	23,392	304
Per share	0.10	0.10	-		0.40	0.10	300
Weighted average shares (thousands)
Basic	236,408	231,766	2		235,583	227,299	4
Diluted	238,872	235,305	2		237,705	230,755	3
Shares outstanding, end of period (thousands)
Basic					236,580	233,920	1
Diluted ^(5)					241,138	241,029	-
Operating (6:1 boe conversion)
Average daily production
Heavy crude oil (bbls/d)	18,514	13,536	37		16,466	11,411	44
Natural gas (mmcf/d)	8.0	11.5	(30)		8.8	8.2	7
Natural gas liquids (bbls/d)	93	99	(6)		98	57	72
Barrels of oil equivalent ^(9) (boe/d)	19,939	15,546	28		18,038	12,841	40
Average daily sales ^(6)(boe/d)	20,134	15,568	29		18,038	12,843	40
Netbacks ($/boe) ^(3) (7)
Operating
Sales, net of blending ^(4)	71.09	71.90	(1)		73.34	91.74	(20)
Royalties	(12.91)	(13.51)	(4)		(13.01)	(18.17)	(28)
Transportation	(5.12)	(4.21)	22		(5.35)	(4.28)	25
Production expenses	(7.34)	(6.25)	17		(7.17)	(5.93)	21
Operating netback ^(3)	45.72	47.93	(5)		47.81	63.36	(25)
Realized gains on financial derivatives	3.35	2.96	13		2.14	0.01	na
Operating netback, including financial derivatives ^(3)	49.07	50.89	(4)		49.95	63.37	(21)
General and administrative expense	(1.51)	(1.14)	32		(1.47)	(1.38)	7
Interest income and other expense ^(8)	0.84	1.15	(27)		0.92	0.76	21
Current tax expense	(4.14)	(0.75)	452		(5.62)	(3.07)	83
Adjusted funds flow netback ^(3)	44.26	50.15	(12)		43.78	59.68	(27)

(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, 2023 includes 2.5 million stock options with a weighted average exercise price of $3.88 and 2.0 million performance share units ("PSUs"). The number of outstanding PSUs has been adjusted for dividends. Restricted share units 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, 2023, sales volumes comprised of 18,709 bbs/d of heavy oil, 8.0 mmcf/d of natural gas and 93 bbls/d of natural gas liquids (2022- heavy oil of 13,558 bbls/d, natural gas of 11.5 mmcf/d and natural gas liquids of 99 bbls/d). For the year ended December 31, 2023, sales volumes comprised of 16,465 bbls/d of heavy oil, 8.8 mmcf/d of natural gas and 98 bbls/d of natural gas liquids (2022- heavy oil of 11,413 bbls/d, natural gas of 8.2 mmcf/d and natural gas liquids of 57 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 2023 HIGHLIGHTS

• Achieved record production of 19,939 boe/d (93% heavy oil), an increase of 28% over 2022 fourth quarter production of 15,546 boe/d (87% heavy oil).
• Realized record adjusted funds flow from operations ⁽¹⁾ of $82.0 million ($0.35 per basic share), cash flows from operating activities of $90.7 million ($0.38 per basic share) and free cash flow ⁽³⁾ of $51.9 million.
• Achieved an operating netback, including financial derivatives, ⁽²⁾ of $49.07/boe and an adjusted funds flow netback ⁽²⁾ of $44.26/boe.
• Generated net income of $45.5 million ($0.19 per basic share) equating to $24.55/boe.
• Executed a $30.1 million capital expenditure ⁽³⁾ program including 13 net crude oil wells in Marten Hills West, at a 100% success rate.
• Returned $0.10 per common share to shareholders.
• As at December 31, 2023, Headwater had working capital of $78.6 million, adjusted working capital ⁽¹⁾ of $63.5 million and no outstanding bank debt.

YEAR ENDED DECEMBER 31, 2023 HIGHLIGHTS

• Achieved average production of 18,038 boe/d (91% heavy oil), an increase of 40% over 2022 annual production of 12,841 boe/d (89% heavy oil).
• Realized adjusted funds flow from operations ⁽¹⁾ of $288.3 million ($1.22 per basic share) and cash flows from operating activities of $303.3 million ($1.29 per basic share).
• Achieved an operating netback, including financial derivatives, ⁽²⁾ of $49.95/boe and an adjusted funds flow netback ⁽²⁾ of $43.78/boe.
• Generated net income of $156.1 million ($0.66 per basic share) equating to $23.71/boe.
• Returned a total of $0.40 per common share or $94.4 million to shareholders.
• Proved developed producing reserves increased by 33% to 22.1 mmboe from 16.6 mmboe.
• Total proved reserves increased by 54% to 32.5 mmboe from 21.1 mmboe.
• Total proved plus probable reserves increased by 51% to 51.9 mmboe from 34.3 mmboe.
• Achieved finding and development ("F&D") costs ⁽²⁾, including changes in future development costs of $19.17 per boe on a proved developed producing basis, $18.61 per boe on a total proved basis and $14.97 per boe on a total proved plus probable basis.
• Based on a 2023 adjusted funds flow netback ⁽²⁾ of $43.78/boe, achieved recycle ratios ⁽²⁾ of 2.3 on a proved developed producing basis, 2.4 on a total proved basis and 2.9 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

Production from Marten Hills West grew more than 250% from 3,000 bbls/d in the first quarter of 2023 to greater than 10,500 bbls/d in the fourth quarter of 2023. The year was also characterized by a significant pool expansion in addition to the validation of the stacked pay potential of the area. Economic production has now been proven from four different Clearwater sands in Marten Hills West.

In the Clearwater A, successful tests at 00/03-15-075-01W5 and 02/05-18-075-01W5 have expanded the eastern Clearwater A pool boundary by 4 miles de-risking an additional ten sections of land. The 00/3-15-076-01W5 well achieved a 60-day initial production rate of 157 bbls/d while the 02/05-18-075-01W5 well achieved a 60-day initial production rate of 147 bbls/d. Success from these wells expands the potential of the Clearwater A in Marten Hills West to greater than 45 sections.

The positive results of the two active waterflood pilots in the Clearwater A suggest that a large portion of the Clearwater A pool will be amenable to secondary recovery.  The two active pilots continue to exceed our expectations with decreasing gas oil ratios and greater than 200 bbls/d of stabilized oil production. Continued implementation of the Clearwater A waterflood will occur with a full section waterflood employed by the end of the first quarter of 2024.

The successful discovery well drilled at 02/13-15-076-02W5 in the Clearwater E in the fourth quarter of 2023 has recently been followed up with a second test at 00/04-35-076-02W5.  This well finished recovering load fluid March 2^nd and is currently producing 160 bbls/d. In conjunction with our discovery well, this pool is now estimated to be in excess of 15 sections.  A further test of the Clearwater E sand will occur in the second quarter.

Our discovery well in the Clearwater G at 00/02-30-075-01W5 has achieved a 90-day initial production rate of 160 bbls/d.  Three additional Clearwater G tests following up on this discovery will be drilled over the next couple of months to continue validation of the size and potential of this sand.

Further drilling in the Clearwater B will occur in the second half of 2024 with 4 wells planned within this sand.

Marten Hills Core

In 2024 we will continue to advance the secondary recovery efforts in the core converting two sections to injection and growing our stabilized production to more than 4,000 bbls/d. By mid-2025 we will have the entire core area under secondary recovery resulting in reduced corporate declines and required maintenance capital. In addition, we have recently expanded our enhanced recovery efforts with a pilot injector northeast of the core area supporting the 02/12-08-075-24W5 well. Early indications here look excellent with strong injectivity indicating enhanced recovery efforts can be expanded beyond the defined core area in Marten Hills.

West Nipisi

In the first quarter of 2024, three Clearwater C extension wells were drilled in the 7-section development area of West Nipisi. The northwest extension wells, 00/14-17-078-09W5 and 00/13-17-078-09W5 have achieved an average per well 30-day initial production rate of 195 bbls/d. The 03/04-04-078-09W5 well, a southern extension test, has achieved a 15-day initial production rate of 215 bbls/d. Results from these three tests validate economic development from the entire 7-section block.

In addition, two multi-lateral wells and a stratigraphic test have been drilled in the West Nipisi expansion area via winter access roads for evaluation of two prospective Clearwater sands. The 02/05-15-077-12W5 well, targeting the Clearwater G sand, was rig-released February 17^th and the 00/05-18-77-11W5 well, targeting the Clearwater F sand, was rig-released February 27^th. Both wells are at various stages of load fluid recovery and will be produced until break up conditions prevail. Results from the multi-lateral wells in addition to evaluation of the stratigraphic test will aid in determining the viability of an all-weather access road into the area.

Heart River & Little Horse

At Heart River, south of our Greater Peavine area, we have recently spud our first Falher test at 00/06-36-076-16W5 targeting a Falher sandstone prospective for heavy oil.  Results from this well are anticipated to be released in conjunction with our first quarter results. 

The exploration team has also identified additional multi-zone prospectivity across 47 sections of newly acquired acreage in an offsetting area called Little Horse, which is prospective for heavy oil and located directly east of Heart River. The first test in this recently acquired acreage is planned for the fourth quarter of 2024.  

Handel

To date, the team has been successful at acquiring 56 sections of land prospective for Mannville oil in the Handel area of West Central Saskatchewan. A stratigraphic test and one single-leg horizontal well have been recently drilled in the area. The horizontal well targeting the Lloydminster sandstone had encouraging geotechnical shows and is currently being placed on production. Pending the success of this well, up to two additional tests will be drilled in this area in 2024.

Exploration Land Update

The Headwater team continues its pursuit of organic growth opportunities in and beyond the boundaries of the Clearwater acreage. Year to date in 2024, we have added 81.5 net sections to our land base. We have now accumulated over 520 net sections in the Clearwater fairway and 175 net sections of non-Clearwater acreage in oily fairways across the basin. Within the 175 sections of non-clearwater acreage we have defined numerous play concepts, and plan to test 4 of these prospects in 2024.

McCully

McCully was placed back on production December 1^st to align with our aggressive hedging profile. Approximately 86% of our December 2023 to March 2024 volumes are hedged at Cdn$17.85/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 asset has protected the asset's cash flow against highly volatile gas pricing experienced this winter.

(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 continue until April 2024.

2024 GUIDANCE UPDATE  

As a result of Headwater's success in accumulating incremental lands year to date in 2024, the Board of Directors has approved an expansion of the Company's 2024 capital budget from $180 million to $200 million. Average forecast production for 2024 will remain at 20,000 boe/d. At US$75.30 WTI, the Company expects to generate adjusted funds flow from operations of $298 million and exit the year with adjusted working capital of $65 million.

		2024 Guidance^(1)
2024 annual average production (boe/d)		20,000
Capital expenditures ^(2)		$200 million
Comprised of:
Development capital		$135 million
Land		$20 million
Exploration and enhanced oil recovery		$45 million
WTI		US$75.30/bbl
WCS		Cdn$79.70/bbl
Adjusted funds flow from operations ^(3)		$298 million
Exit adjusted working capital ^(3)		$65 million
Quarterly dividend		$0.10/common share

(1)	The Company's previous 2024 guidance as set out in a press release dated December 7, 2023 was $180 million of capital expenditures (comprised of $135 million in maintenance and growth capital, $25 million in waterflood capital and $20 million of exploration capital), adjusted funds flow from operations of $275 million and exit adjusted working capital of $58 million based on assumptions of US$70.00/bbl WTI and WCS of Cdn$73.30/bbl (and certain other assumptions as set out in such press release).
(2)	Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(3)	Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release.
(4)	For assumptions utilized in the above guidance see "Future Oriented Financial Information" within this press release.

FIRST QUARTER DIVIDEND

The Board of Directors of Headwater confirms a cash dividend to shareholders of $0.10 per common share payable on April 15, 2024, to shareholders of record at the close of business on March 29, 2024. 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.

2023 RESERVES INFORMATION

Headwater currently has heavy oil reserves located in the Marten Hills, Greater Peavine and West Nipisi areas of Alberta and natural gas 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, 2023 ("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, 2023 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, 2023, filed on SEDAR+ on March 7, 2024.     

The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by McDaniel, effective December 31, 2023. 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	Gas	NGL	Equivalent
	Mbbls	MMcf	MMcf	Mbbls	MBOE
Proved developed producing	18,073	756	22,363	145	22,071
Proved developed non-producing	-	1,477	-	2	248
Proved undeveloped	9,796	-	2,206	34	10,198
Total proved	27,869	2,233	24,569	181	32,517
Total probable	16,982	690	12,868	166	19,407
Total proved plus probable	44,851	2,923	37,437	347	51,925

(1)	Reserves have been presented on 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 & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2024.
(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

	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	778,722	688,988	613,355	553,138	505,233	664,843	591,058	527,120	475,773	434,791
Proved developed non- producing	13,265	10,119	7,890	6,307	5,154	9,969	7,601	5,909	4,710	3,840
Proved undeveloped	272,562	228,530	192,511	163,319	139,600	205,597	170,049	140,776	117,040	97,801
Total proved	1,064,549	927,636	813,755	722,765	649,987	880,408	768,708	673,806	597,524	536,432
Total probable	741,828	556,153	434,004	350,666	291,476	572,538	427,197	331,428	266,240	220,089
Total proved plus probable	1,806,377	1,483,789	1,247,759	1,073,431	941,463	1,452,946	1,195,905	1,005,234	863,764	756,521

(1)	Based on the average of GLJ Ltd., McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2024.
(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, 2023. 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.

	Proved Reserves  $M	Proved Plus Probable Reserves $M
2024	99,900	99,900
2025	92,479	132,342
2026	-	52,631
Thereafter ^(1)	3,184	3,247
Total Undiscounted	195,563	288,120

(1)	Future development capital after 2026 is associated with McCully gas plant optimization.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2023, 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, 2024, to estimate the reserves volumes and associated values in the McDaniel Report. 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS as of December 31, 2023 FORECAST PRICES AND COSTS
Year		WTI Cushing Oklahoma ($US/Bbl)		MSW Light Crude 40^oAPI ($Cdn/Bbl)		WCS Crude Oil  Stream Quality at Hardisty ($Cdn/Bbl)		NYMEX Henry Hub ($US/ MMBtu)		Natural Gas AECO-C Spot ($Cdn/ MMBtu)		AGT Premium to Henry Hub^(1) ($Cdn/MMbtu)		McCully Gas Price^(2) ($Cdn/Mcf)		Inflation Rates %/Year		Exchange Rate^(3) ($Cdn/$US)
Forecast^(4)
2024		73.67		92.91		76.74		2.75		2.20		2.44		11.94		0.0		0.75
2025		74.98		95.04		79.77		3.64		3.37		3.10		15.62		2.0		0.75
2026		76.14		96.07		81.12		4.02		4.05		3.09		16.05		2.0		0.76
2027		77.66		97.99		82.88		4.10		4.13		3.09		9.74		2.0		0.76
2028		79.22		99.95		85.04		4.18		4.21		3.09		9.63		2.0		0.76
2029		80.80		101.94		86.74		4.27		4.30		3.09		9.74		2.0		0.76

Thereafter	Escalation rate of 2.0%
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 2024 – 2026 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 2026, 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, 2023.

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 2024 guidance related to expected annual average production, capital expenditures and the breakdown thereof, adjusted funds flow from operations, dividends and exit adjusted working capital; the expectation the waterflood pilot results in Marten Hills West suggest that a large portion of the Clearwater A will be amenable to secondary recovery and the expectation to have a full section under waterflood in Marten Hills West by the end of the first quarter of 2024; the expectation that as a result of successful tests in the Clearwater E in Marten Hills West, this pool is now estimated to be in excess of 15 sections; the timing of additional tests in the Clearwater E, G and B in Marten Hills West in 2024; the expectation to have 4,000 bbls/d of stabilized production in the Marten Hills Core in 2024 and the expectation to have the entire core area under secondary recovery by mid-2025, which is expected to reduce corporate declines and required maintenance capital; the expectation that results from the core indicate enhanced recovery efforts can be expanded beyond the defined core area in Marten Hills; the expectation to produce wells in West Nipisi until break-up conditions prevail and the expectation results from the West Nipisi wells will aid in determining the viability of an all-weather access road into the area; the expectation the results from the Heart River test will be released in conjunction with first quarter 2024 results and the expectation the first test in Little Horse will occur in the fourth quarter of 2024; the expectation to complete up to two additional tests in the Handel area in 2024; certain expected operations and timing of results from certain exploration lands including from the Handel area; the expectation to test 4 exploration prospects in 2024; the allocation of 2024 capital budget to exploration tests; the expectation of McCully performance through the 2023/2024 winter season; the expectation that the Company's positive working capital balance and credit facility will provide Headwater the optionality to organically expand its Clearwater 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. 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), 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 7, 2024, 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 2024 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. The assumptions used in the 2024 guidance include: 2024 annual production guidance comprised of: 18,650 bbls/d of heavy oil, 50 bbls/d of natural gas liquids and 7.8 mmcf/d of natural gas, AGT US$5.05/mmbtu, AECO of Cdn$1.95/GJ, foreign exchange rate of Cdn$/US$ of 0.74, blending expense of WCS less $2.20, royalty rate of 18.8%, operating and transportation costs of $13.45/boe, G&A and interest income and other expense of $1.30/boe and cash taxes of $6.10/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.

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

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. In addition, 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.

Non-GAAP Financial Measures

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.

	Three months ended December 31,			Year ended December 31,
	2023	2022		2023	2022
	(thousands of dollars)			(thousands of dollars)
Adjusted funds flow from operations	81,983	71,828		288,262	279,727
Capital expenditures	(30,050)	(60,677)		(233,846)	(244,495)
Free cash flow	51,933	11,151		54,416	35,232

Total sales, net of blending

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.

	Three months ended December 31,			Year ended December 31,
	2023	2022		2023	2022
	(thousands of dollars)			(thousands of dollars)
Total sales	138,426	109,377		511,234	458,379
Blending expense	(6,736)	(6,403)		(28,411)	(28,332)
Total sales, net of blending expense	131,690	102,974		482,823	430,047

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.

	Three months ended December 31,			Year ended December 31,
	2023	2022		2023	2022
	(thousands of dollars)			(thousands of dollars)
Cash flows used in investing activities	54,716	61,957		243,714	232,056
Proceeds from government grant	1,200	780		1,200	1,988
Restricted cash	-	5,000		-	-
Change in non-cash working capital	(23,392)	(5,223)		(8,594)	14,879
Government grant	(2,474)	(1,837)		(2,474)	(4,428)
Capital expenditures	30,050	60,677		233,846	244,495

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 deducting current income taxes, adjusted funds flow from operations is a useful measure of operating performance.

	Three months ended December 31,		Year ended, December 31,
	2023	2022	2023	2022
	(thousands of dollars)		(thousands of dollars)
Cash flows provided by operating activities	90,690	66,448	303,316	283,925
Changes in non–cash working capital	(5,387)	6,455	(7,050)	10,195
Current income tax expense	(7,668)	(1,075)	(36,990)	(14,393)
Current income taxes paid	4,348	-	28,986	-
Adjusted funds flow from operations	81,983	71,828	288,262	279,727

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. 

	Year ended December 31,
	2023	2022
	(thousands of dollars)
Working capital	78,610	109,433
Contribution receivable (long-term)	-	1,104
Repayable contribution	(11,405)	(6,720)
Financial derivative receivable	(3,758)	(419)
Financial derivative liability	79	1,520
Adjusted working capital	63,526	104,918

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. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. 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 GLJ Ltd. as at December 31, 2022 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 = ($233.8 million (2023 capital expenditures) + -$3.0 million (change in FDC associated with proved developed producing reserves)) / (22,071 mboe – 16,614 mboe + 6,584 mboe) = $19.17 per boe. Total proved F&D is calculated as follows = ($233.8 million (2023 capital expenditures) + $100.7 million (change in FDC associated with total proved reserves)) / (32,517 mboe – 21,125 mboe + 6,584 mboe) = $18.61 per boe. Total proved plus probable F&D is calculated as follows = ($233.8 million (2023 capital expenditures) + $128.7 million (change in FDC associated with total proved plus probable reserves)) / (51,925 mboe – 34,295 mboe + 6,584 mboe) = $14.97 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.

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.

SOURCE Headwater Exploration Inc.

HEADWATER EXPLORATION INC.: Mr. Neil Roszell, P. Eng., Executive Chairman; Mr. Jason Jaskela, P.Eng., President and Chief Executive Officer; Ms. Georgia Little, CPA, CA, Interim Vice President Finance and Chief Financial Officer; [email protected], [phone]