Headwater Exploration Inc. announces 2021 reserves, fourth quarter and year end 2021 operating and financial results and operations update

CALGARY, AB – Headwater Exploration Inc. (the “Company” or “Headwater“) (TSX: HWX) announces its operating and financial results for the three months and year ended December 31, 2021. 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.sedar.com 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, 2021, dated March 10, 2022, filed on SEDAR at www.sedar.com.

Financial and Operating Highlights

	Three months ended December 31,		Year ended December 31,
	2021	2020	2021	2020
Financial (thousands of dollars except share data)
Total sales, net of blending ^{(1) (4)}	70,125	6,283	179,517	9,156
Cash flows provided by (used in) operating activities	47,753	(1,451)	111,656	230
Per share – basic	0.23	(0.01)	0.56	–
– diluted	0.22	(0.01)	0.52	–
Adjusted funds flow from operations⁽²⁾	48,731	4,816	117,916	8,782
Per share – basic	0.24	0.03	0.59	0.06
– diluted	0.22	0.03	0.55	0.06
Net income	27,927	16,919	45,828	6,707
Per share – basic	0.14	0.10	0.23	0.05
– diluted	0.13	0.10	0.21	0.05
Adjusted net income ⁽¹⁾	32,596	21,208	78,427	10,996
Per share – basic	0.16	0.13	0.39	0.08
– diluted	0.15	0.13	0.36	0.08
Capital expenditures ⁽¹⁾	49,043	1,748	140,389	2,277
Property Acquisition	–	135,297	–	135,297
Adjusted working capital ⁽²⁾			92,929	80,759
Shareholders’ equity			397,791	269,030
Weighted average shares (thousands)
Basic	204,005	161,365	199,802	139,379
Diluted	220,958	168,600	215,861	145,377
Shares outstanding, end of period (thousands)
Basic			217,681	195,106
Diluted ⁽⁵⁾			242,448	238,121
Operating (6:1 boe conversion)
Average daily production
Heavy crude oil (bbls/d)	9,377	979	6,665	246
Natural gas (mmcf/d)	6.4	4.0	4.4	3.8
Natural gas liquids (bbls/d)	–	3	2	3
Barrels of oil equivalent ⁽⁹⁾ (boe/d)	10,449	1,646	7,393	882

Average daily sales ⁽⁶⁾(boe/d)	10,459	1,646	7,390	882

Netbacks ($/boe) ^{(3) (7)}
Operating
Sales, net of blending ⁽⁴⁾	72.88	41.50	66.57	28.37
Royalties	(11.34)	(3.86)	(9.62)	(2.03)
Transportation	(6.98)	(5.10)	(7.55)	(2.40)
Production expenses	(4.20)	(7.92)	(4.64)	(8.98)
Operating netback ⁽³⁾	50.36	24.62	44.76	14.96
Realized gains on financial derivatives	1.41	10.42	0.35	17.09
Operating netback, including financial derivatives ⁽³⁾	51.77	35.04	45.11	32.05
General and administrative expense	(1.23)	(4.64)	(1.48)	(8.78)
Interest income and other expense ⁽⁸⁾	0.10	1.39	0.09	3.94
Adjusted funds flow netback ⁽³⁾	50.64	31.79	43.72	27.21

(1)	Non-GAAP 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 annual financial statements blending expense is recorded within blending and transportation expense.
(5)	Includes in-the-money dilutive instruments as at December 31, 2021 which include 9.4 million stock options with a weighted average exercise price of $2.33 and 15.4 million warrants issued pursuant to the recapitalization transaction in March 2020 with an exercise price of $0.92.
(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.
(7)	Netbacks are calculated using average sales volumes. Fourth quarter 2021 sales volumes comprised of 9,388 bbs/d of heavy oil and 6.4 mmcf/d of natural gas. Annual 2021 sales volumes comprised of 6,661 bbls/d of heavy oil, 4.4 mmcf/d of natural gas and 2 bbls/d of natural gas liquids.
(8)	Excludes accretion on decommissioning liabilities and interest on lease liability.
(9)	See ‘”Barrels of Oil Equivalent.”

FOURTH QUARTER 2021 HIGHLIGHTS

Achieved average production of 10,449 boe/d (consisting of 9,377 bbls/d of heavy oil and 6.4 mmcf/d of natural gas), an increase of over 500% from the fourth quarter of 2020.
Cash flows provided by operating activities was $47.8 million, $0.23 per share (basic), and adjusted funds flow from operations⁽¹⁾ was $48.7 million, $0.24 per share (basic).
Achieved an operating netback⁽²⁾ of $50.36/boe and an adjusted funds flow netback⁽²⁾ of $50.64/boe.
Generated net income of $27.9 million, $0.14 per share (basic), and adjusted net income⁽³⁾ of $32.6 million, $0.16 per share (basic).
Executed a $49.0 million capital expenditure ⁽³⁾ program in the Marten Hills area including 3 successful exploration wells and 8 multi-lateral development wells at a 100% success rate. In addition to the drilling program, $26.5 million was spent on equipping and facilities primarily for ongoing construction of Headwater’s 100% owned 15,000 bbls/d oil processing facility. The oil processing facility was commissioned subsequent to December 31, 2021.
On December 23, 2021, Cenovus Marten Hills Partnership, a wholly owned subsidiary of Cenovus Energy Inc. (“Cenovus”), exercised its 15 million warrants (the “Cenovus Warrants”) for 15 million common shares of the Company for total proceeds of $30 million. On exercise of the Cenovus Warrants, Cenovus held approximately 7% of the outstanding common shares of the Company.
As at December 31, 2021, Headwater had working capital of $89.8 million, adjusted working capital⁽¹⁾of $92.9 million and no outstanding debt.

YEAR ENDED DECEMBER 31, 2021

Achieved average production of 7,393 boe/d (consisting of 6,665 bbls/d of heavy oil, 4.4 mmcf/d of natural gas and 2 bbls/d of natural gas liquids), an increase of over 700% from 2020 annual production of 882 boe/d.
Cash flows provided by operating activities was $111.7 million, $0.56 per share (basic), and adjusted funds flow from operations⁽¹⁾ was $117.9 million, $0.59 per share (basic).
Executed a $140.4 million capital expenditure ⁽³⁾ program in the Marten Hills area including 58 net wells (51 crude oil wells, 4 source wells and 3 stratigraphic tests) at a 100% success rate.
The Company’s joint gas processing facility, commissioned in the third quarter of 2021, in combination with pipeline infrastructure installed in the first quarter of 2021, has resulted in an approximate 50% reduction in Headwater’s CO2e emissions intensity on a barrel of oil equivalent basis over the 2021 calendar year.
Proved developed producing reserves increased by 96% to 9.8 mmboe from 5.0 mmboe.
Total proved reserves increased by 65% to 15.7 mmboe from 9.5 mmboe.
Proved plus probable reserves increased by 82% to 23.8 mmboe from 13.1 mmboe.
Achieved finding and development (“F&D”) costs⁽²⁾, including changes in future development costs of $20.43 per boe on a proved basis and $13.92 per boe on a proved plus probable basis. Based on a 2021 operating netback including financial derivatives ⁽²⁾ of $45.11/boe, achieved recycle ratios ⁽²⁾ of 2.2 on a proved basis and 3.2 on a 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 measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.

Operations Update

Marten Hills Core Area Development

The first quarter of 2022 has been very active to date. Accomplishments include:

Rig released 11 6-leg producing horizontal wells
Rig released 5 4-leg horizontal injection wells
The balance of the first quarter program in the core area will see an additional 6 4-leg horizontal injection wells

Initial production (“IP”) rates from our latest core area wells have been consistent with expectations and the results of previous quarters, with an average post load recovery 30-day IP (“IP30”) rate of approximately 400 bbls/d.

On March 5, 2022, Headwater’s oil processing facility was fully commissioned resulting in a $4.00/bbl reduction to transportation costs. Commissioning of the water injection facilities is ongoing with 3 wells currently on injection and an additional 18 injection wells to be placed on injection prior to July 1, 2022.

Enhanced Oil Recovery

The initial results on our first 3 waterflood pilots have exhibited very encouraging behavior over the past nine months. Our independent reserves evaluator has evaluated the pilot waterflood results and has provided increased per well reserves bookings associated with waterflood. The pilot results provide confidence to continue development of our core area under full field waterflood.

Our next phase of injection is scheduled to begin imminently, with the next 9 injectors to be placed on injection prior to the end of April 2022. By year-end we anticipate having greater than 35 4-leg horizontal injection wells on injection, representing approximately 45% of our core area under waterflood.

Exploration Update

Since our last update to shareholders on February 1, 2022, we have successfully placed 2 exploration wells on production (15-29 and 16-27), testing the southern and eastern extents of the Clearwater A fairway. The Headwater team is extremely pleased with the results of our exploration efforts in Marten Hills West and believe we have discovered an approximate 25km long hydrocarbon accumulation containing approximately 65 sections of Headwater land.

The Marten Hills West Clearwater A hydrocarbon accumulation has been successfully extended 20km southeast and 10km east of our discovery wells at 11-05-076-02W5 and 13-07-076-02W5 through the successful drilling of 15-29-075-01W5 and 16-27-074-01W5. The 15-29-075-01W5 well has produced at a 24-day IP rate of approximately 82 bbls/d of 21 degree API oil. The 16-27-74-01W5 well finished recovering load fluid February 27, 2022 and is currently producing 50 bbls/d of 18 degree API oil. Although the results are not as prolific as the initial discovery wells, the Marten Hills West play extension validated by these two successful tests provides confidence in a significant, medium-grade oil charged fairway in the Clearwater A sandstone. An additional western extension well has been drilled and placed on production at 02/08-34-075-03W5. It is currently recovering load fluid with IP30 rates expected by the middle of April 2022. Headwater is continuing to delineate this fairway with 4 additional Clearwater A wells expected to be drilled prior to quarter end. The 11-05 and 13-07 wells drilled in the fourth quarter of 2021 continue to perform exceptionally well with 60-day IP (“IP60”) rates of 225 bbls/d and 215 bbls/d respectively.

A second test in the Clearwater B at 00/09-34-075-03W5 was rig released on Feb 19, 2022. This well, immediately to the north of the initial discovery well, 00/08-34-075-03W5, finished recovering load fluid on March 9, 2022. Current rates for 09-34 are highly encouraging at greater than 200 bbls/d of oil. The 08-34 well drilled in the fourth quarter of 2021 has achieved an IP60 rate of 149 bbls/d. These results in conjunction with other area operators results, in the same zone, confirm a 15-section prolific hydrocarbon accumulation on Headwater lands.

Headwater will continue to delineate both the Clearwater A and B sands through additional drilling in the back half of the year.

McCully Asset

The McCully asset has produced strongly throughout this winter season and Headwater anticipates continuing to produce the field until May 1, 2022, when it will be shut-in to await next winter’s premium pricing season. Based on field receipts to date, the McCully field is expected to generate approximately $9 million of free cash flow ⁽¹⁾ during the first quarter of 2022.

(1)

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

2022 Outlook

With the increase in realized commodity pricing in the first quarter of 2022, the Company expects to generate adjusted funds flow from operations ⁽¹⁾ of $259 million and exit adjusted working capital ⁽¹⁾ of $207 million. Headwater is maintaining capital expenditures ⁽²⁾ for 2022 at $145 million with 2022 production at 12,500 boe/d (11,500 bbls/d of heavy oil and 6.2 mmcf/d of natural gas), as previously released.

(1)	Capital management measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.
(2)	Non-GAAP measure. Refer to “Non-GAAP and Other Financial Measures” within this press release.
(3)	Pricing assumptions are as follows: WTI US$88.00/bbl, WCS Cdn$97.00/bbl, FX 0.79, AGT US$14.19/mmbtu

2021 Reserve Information

Headwater currently has heavy oil reserves located in the Marten Hills area of Alberta and natural gas reserves in the McCully Field near Sussex, New Brunswick. GLJ Ltd. (“GLJ“) assessed the Company’s reserves in its report dated effective December 31, 2021 (“GLJ 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, 2021 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, 2021, filed on SEDAR on March 10, 2022.

The following tables are a summary of Headwater’s petroleum and natural gas reserves, as evaluated by GLJ, effective December 31, 2021. 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	6,439	810	18,229	206	9,818
Proved developed non-producing	–	994	–	–	166
Proved undeveloped	5,226	–	1,995	121	5,680
Total proved	11,665	1,804	20,224	327	15,663
Total probable	6,697	507	6,983	182	8,127
Total proved plus probable	18,362	2,311	27,206	509	23,790

(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, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2022.
(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%
	$MM	$MM	$MM	$MM	$MM	$MM	$MM	$MM	$MM	$MM

Proved developed producing	330,844	309,567	288,497	270,537	255,468	306,069	286,707	267,285	250,754	236,934
Proved developed non-producing	1,065	1,030	961	880	801	699	706	670	618	563
Proved undeveloped	148,348	128,751	112,297	98,450	86,739	111,565	95,912	82,718	71,601	62,201
Total proved	480,258	439,349	401,755	369,867	343,008	418,332	383,324	350,673	322,973	299,698
Total probable	282,703	230,817	192,873	164,846	143,509	221,976	180,331	149,943	127,648	110,767
Total proved plus probable	762,961	670,166	594,628	534,713	486,517	640,309	563,655	500,616	450,621	410,465

(1)	Based on the average of GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2022.
(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, 2021. 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 $MM	Proved Plus Probable Reserves $MM
2022	66,150	70,350
2023	19,806	21,211
Thereafter ⁽¹⁾	2,661	2,768
Total Undiscounted	88,616	94,329

(1)	Future development capital after 2023 is associated with McCully gas plant optimization.

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2021, reflected in the GLJ Report, using the average of commodity price forecasts from GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2022, to estimate the reserves volumes and associated values in the GLJ Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2021
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 ($Cdn/ MMBtu)	Algonquin City Gates Natural Gas ($US/MMBtu)	McCully Gas Price⁽¹⁾ ($Cdn/Mcf)	Inflation Rates %/Year	Exchange Rate⁽¹⁾ ($Cdn/$US)

Forecast⁽³⁾

2022	72.83	86.82	74.43	3.85	3.56	7.55	13.84	0.0	0.797
2023	68.78	80.73	69.17	3.44	3.20	5.64	10.19	2.3	0.797
2024	66.76	78.01	66.54	3.17	3.05	4.37	6.93	2.0	0.797
2025	68.09	79.57	67.87	3.24	3.10	4.46	6.91	2.0	0.797
2026	69.45	81.16	69.23	3.30	3.17	4.55	6.87	2.0	0.797
2027	70.84	82.78	70.61	3.37	3.23	4.64	6.76	2.0	0.797

Thereafter Escalation rate of 2.0%

Notes:

(1)	The forecast McCully gas price is used by GLJ 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 2022 – 2023 reflects only the winter producing months (January to April and November to December) or correlate to the intermittent production strategy employed by the Company to capture seasonal premium pricing. After 2023, the GLJ Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year.
(2)	The exchange rate used to generate the benchmark reference prices in this table.
(3)	As at December 31, 2021.

The company continues to grow significantly while spending less than our cash flow. As the business strategy continues to evolve, there will be an increased focus on returning excess free cash flow to shareholders. While it is early, Headwater looks forward to providing clarity on these elements over the next 9 months.

Headwater’s guiding principles of shareholder value creation, sustainability, asset development with an emphasis on environmental, social, and governance goals, and maintaining a pristine balance sheet continue to be unwavering.

Additional corporate information can be found in our corporate presentation on our website at www.headwaterexp.com

Advisories & Contact

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 first quarter program in the core area will see an additional 6 4-leg horizontal injection wells; the timing of commissioning the water injection facility; the expectation that an additional 18 injection wells to be placed on injection prior to July 1, 2022; the expectation to have 35 4-leg horizontal injection wells on injection by year end representing approximately 45% of our core area under waterflood; the belief that Headwater has discovered an approximate 25km long hydrocarbon accumulation containing 65 sections of Headwater land; the expectation that 9 injectors will be placed on injection prior to the end of April; the belief that the two successful tests in the Marten Hills West play extension validated a significant, medium-grade oil charged fairway in the Clearwater A sandstone; the intent that Headwater will continue to delineate this fairway throughout the back half of the year to quantify the extent and quality of the discovered accumulation; Headwater’s intent to continue the Company’s previous strategy of production optimization of the McCully gas field in New Brunswick; the expectation that production from the McCully field will be shut-in May 1 to take advantage of premium gas pricing; expected free cash flow generation; and 2022 guidance related to expected average daily production, capital expenditures, cash flow from operating activities, adjusted funds flow from operations, exit working capital and exit adjusted working 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 approval, 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 in the MD&A available on SEDAR at www.sedar.com. 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; disruptions to the Canadian and global economy resulting from major public health events, including the COVID-19 pandemic, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including the COVID-19 pandemic and 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 most recent Annual Information Form dated March 10, 2022, on SEDAR at www.sedar.com, and the risk factors contained therein.

The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

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 2022 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.

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 IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all “load” fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.

NON-GAAP AND OTHER FINANCIAL MEASURES

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

Non-GAAP Financial Measures

Total sales, net of blending

Management utilizes 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 annual financial statements blending expense is recorded within blending and transportation expense.

	Three months ended December 31,		Year ended December 31,
	2021	2020	2021	2020
	(thousands of dollars)		(thousands of dollars)
Total sales	75,287	6,626	190,940	9,499
Blending expense	(5,162)	(343)	(11,423)	(343)
Total sales, net of blending expense	70,125	6,283	179,517	9,156

Adjusted Net Income

Adjusted net income is a non-GAAP financial measure which management utilizes to present a measure of financial performance that is more comparable over periods. It is calculated by adding the remeasurement loss on warrant liability associated with the Cenovus Warrants to net income.

	Three months ended December 31,		Year ended December 31,
	2021	2020	2021	2020
	(thousands of dollars)		(thousands of dollars)
Net income	27,927	16,919	45,828	6,707
Remeasurement loss on warrant liability	4,669	4,289	32,599	4,289
Adjusted net income	32,596	21,208	78,427	10,996

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.

	Three months ended December 31,		Year ended December 31,
	2021	2020	2021	2020
	(thousands of dollars)		(thousands of dollars)
Cash flows used in investing activities	47,047	34,374	109,127	34,404
Property acquisition	–	(32,781)	–	(32,781)
Restricted cash	1,248	(1,477)	1,477	(797)
Change in non-cash working capital	748	1,632	29,785	1,451
Capital expenditures	49,043	1,748	140,389	2,277
Property acquisition	–	135,297	–	135,297
Capital expenditures including acquisition	49,043	137,045	140,389	137,574

Free cash flow

Management uses free cash flow for its own performance measure and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund its future growth expenditures. Free cash flow is defined as adjusted funds flow from operations less capital expenditures. The most directly comparable GAAP measure for free cash flow is cash flows provided by operating activities.

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 transaction costs, adjusted funds flow from operations is a useful measure of operating performance. Management removes transaction costs as these costs relate to acquisitions/dispositions and not the operations of the underlying properties.

	Three months ended December 31,		Year ended, December 31,
	2021	2020	2021	2020
	(thousands of dollars)		(thousands of dollars)
Cash flows provided by operating activities	47,753	(1,451)	111,656	230
Changes in non–cash working capital	978	3,319	6,260	1,222
Transaction costs	–	2,948	–	7,330
Adjusted funds flow from operations	48,731	4,816	117,916	8,782

Adjusted Working Capital

Adjusted working capital is a capital management measure which management uses to assess the Company’s liquidity.

	Year ended December 31,
	2021	2020
	(thousands of dollars)
Working capital	89,775	70,528
Financial derivative receivable	(770)	(74)
Financial derivative liability	3,924	–
Warrant liability	–	10,305
Adjusted working capital	92,929	80,759

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 on financial derivatives.

Adjusted funds flow per share and adjusted net income per share

Adjusted funds flow per share and adjusted net income per share 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 per share and adjusted net income per share are calculated as adjusted funds flow from operations or adjusted net income 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 as at December 31, 2020 as compared to December 31, 2021. 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 F&D is calculated as follows = ($140.4 million (2021 capital expenditures) + $40.7 million (change in FDC associated with proved reserves)) / (15,663 mboe – 9,495 mboe +2,699 mboe) = $20.43 per boe. Total proved plus probable F&D is calculated as follows = ($140.4 million (2021 capital expenditures) + $46.3 million (change in FDC associated with proved plus probable reserves)) / (23,790 mboe – 13,080 mboe +2,699 mboe) = $13.92 per boe.

Recycle ratio

Recycle ratio is used as a measure of profitability. Recycle ratio is calculated as the Company’s operating netback including financial derivatives 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. These figures are calculated using sales volumes.

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