HEADWATER EXPLORATION INC. ANNOUNCES 2022 RESERVES, YEAR END 2022 OPERATING AND FINANCIAL RESULTS, OPERATIONS UPDATE AND DECLARES QUARTERLY DIVIDEND

HEADWATER EXPLORATION INC. ANNOUNCES 2022 RESERVES, YEAR END 2022 OPERATING AND FINANCIAL RESULTS, OPERATIONS UPDATE AND DECLARES QUARTERLY DIVIDEND

Canada NewsWire

CALGARY, AB, March 9, 2023 /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, 2022. 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, 2022, dated March 9, 2023, filed on SEDAR at www.sedar.com.

Financial and Operating Highlights


Three months ended

December 31,

Percent
Change

Year ended

December 31,

Percent
Change


2022

2021

2022

2021

Financial (thousands of dollars except share data)







Sales, net of blending (1) (4)

102,974

70,125

47

430,047

179,517

140

Adjusted funds flow from operations (2)

71,828

48,731

47

279,727

117,916

137

     Per share - basic

0.31

0.24

29

1.23

0.59

108

                     - diluted

0.31

0.22

41

1.21

0.55

120

Cash flows provided by operating activities 

66,448

47,753

39

283,925

111,656

154

     Per share - basic

0.29

0.23

26

1.25

0.56

123

                     - diluted

0.28

0.22

27

1.23

0.52

137

Net income

39,789

27,927

42

162,109

45,828

254

     Per share - basic

0.17

0.14

21

0.71

0.23

209

                     - diluted

0.17

0.13

31

0.70

0.21

233

Capital expenditures (1)

60,677

49,043

24

244,495

140,389

74

Adjusted working capital (2)




104,918

92,929

13

Shareholders' equity




543,335

397,791

37

Weighted average shares (thousands) 







     Basic

231,766

204,005

14

227,299

199,802

14

     Diluted

235,305

220,958

6

230,755

215,861

7

Shares outstanding, end of period (thousands)







     Basic




233,920

217,681

7

     Diluted (5)




241,029

242,448

(1)

Operating (6:1 boe conversion)















Average daily production







  Heavy crude oil (bbls/d)

13,536

9,377

44

11,411

6,665

71

  Natural gas (mmcf/d)

11.5

6.4

80

8.2

4.4

86

  Natural gas liquids (bbls/d)

99

-

100

57

2

2750

  Barrels of oil equivalent (9) (boe/d)

15,546

10,449

49

12,841

7,393

74
















Average daily sales (6) (boe/d)

15,568

10,459

49

12,843

7,390

74








Netbacks ($/boe) (3) (7)







  Operating







     Sales, net of blending (4)

71.90

72.88

(1)

91.74

66.57

38

     Royalties

(13.51)

(11.34)

19

(18.17)

(9.62)

89

     Transportation

(4.21)

(6.98)

(40)

(4.28)

(7.55)

(43)

     Production expenses

(6.25)

(4.20)

49

(5.93)

(4.64)

28









Operating netback (3)

47.93

50.36

(5)

63.36

44.76

42

     Realized losses on financial derivatives 

2.96

1.41

110

0.01

0.35

(97)

Operating netback, including financial derivatives (3)

50.89

51.77

(2)

63.37

45.11

40

     General and administrative expense

(1.14)

(1.23)

(7)

(1.38)

(1.48)

(7)

     Interest income and other expense (8)

1.15

0.10

1050

0.76

0.09

744

     Current tax expense

(0.75)

-

100

(3.07)

-

100

 Adjusted funds flow netback (3)

50.15

50.64

(1)

59.68

43.72

37

(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)

In-the-money dilutive instruments as at December 31, 2022 includes 6.1 million stock options with a weighted average exercise price of $2.74, 0.2 million restricted share units and 0.8 million performance share units. 

(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, 2022, sales volumes comprised of 13,558 bbs/d of heavy oil, 11.5 mmcf/d of natural gas and 99 bbls/d of natural gas liquids (2021- heavy oil of 9,377 bbls/d and natural gas of 6.4 mmcf/d). For the year ended December 31, 2022, sales volumes comprised of 11,411 bbls/d of heavy oil, 8.2 mmcf/d of natural gas and 57 bbls/d of natural gas liquids (2021- heavy oil of 6,665 bbls/d, natural gas of 4.4 mmcf/d and natural gas liquids of 2 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 2022 HIGHLIGHTS

  • Headwater declared its inaugural quarterly cash dividend of $0.10 per common share and returned $23.4 million to shareholders in January 2023.
  • Achieved average production of 15,546 boe/d (consisting of 13,536 bbls/d of heavy oil, 11.5 mmcf/d of natural gas and 99 bbls/d of natural gas liquids), an increase of 49% from the fourth quarter of 2021.
  • Generated significant adjusted funds flow from operations (1) of $71.8 million ($0.31 per basic share), representing an increase of 47% from the fourth quarter of 2021.
  • Achieved an operating netback (2) of $47.93/boe and an adjusted funds flow netback (2) of $50.15/boe.
  • Recognized net income of $39.8 million ($0.17 per share basic).
  • As at December 31, 2022, Headwater had working capital of $109.4 million, adjusted working capital (1) of $104.9 million and no outstanding bank debt.

YEAR ENDED DECEMBER 31, 2022 HIGHLIGHTS

  • Achieved average production of 12,841 boe/d (consisting of 11,411 bbls/d of heavy oil, 8.2 mmcf/d of natural gas and 57 bbls/d of natural gas liquids), an increase of 74% from 2021 annual production of 7,393 boe/d.
  • Adjusted funds flow from operations (1) was $279.7 million ($1.23 per basic share), representing an increase of 137% from 2021.
  • Achieved an operating netback (2) of $63.36/boe and an adjusted funds flow netback (2) of $59.68/boe.
  • Generated significant net income of $162.1 million, $0.71 per basic share, an increase of 254% from the comparable period in 2021.
  • Proved developed producing reserves increased by 69% to 16.6 mmboe from 9.8 mmboe.
  • Total proved reserves increased by 34% to 21.1 mmboe from 15.7 mmboe.
  • Proved plus probable reserves increased by 44% to 34.3 mmboe from 23.8 mmboe.
  • Achieved finding and development ("F&D") costs (2), including changes in future development costs of $21.42 on a proved developed producing basis, $24.70 per boe on a proved basis and $20.38 per boe on a proved plus probable basis.
  • Based on a 2022 adjusted funds flow netback (2) of $59.68/boe, achieved recycle ratios (2) of 2.8 on a proved developed producing basis, 2.4 on a proved basis and 2.9 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.


EXPLORATION UPDATE

West Nipisi

Headwater validated a new pool discovery on our acreage by successfully drilling five wells in West Nipisi over the last four months. Results have exceeded expectations with on average 19 degree API oil and we are pleased to provide the following initial production details:

Well UWI

Zone

Initial 30-day
average
production rates
("IP30") (bbls/d)

100/12-08-078-09W5

Clearwater

300

100/13-08-078-09W5

Clearwater

288

100/05-08-078-09W5

Clearwater

276

100/13-16-078-09W5

Clearwater

201

100/14-16-078-09W5

Clearwater

128


A drilling rig has recently been moved back into this area and a stratigraphic test was conducted to assist with the validation of two additional prospective horizons. As a result of the stratigraphic test, two multi-laterals will be drilled prior to the end of the first quarter, testing these two previously untested zones.

Headwater has also continued to expand its land base during the first quarter of 2023 with the acquisition of an additional 31.5 sections of land in the West Nipisi area.

Greater Peavine

Two exploration wells in Peavine were drilled and placed on production in February of 2023. The first well 10-08-080-17W5 has a 14-day initial production rate of approximately 120 bbls/d of 13 degree API oil which is consistent with our expectations for the area. The second well at 11-08-080-17W5  finished recovering load fluid March 7th and is currently producing 200 bbls/d oil.

Our first exploration well at Seal, 13-06-083-15W5, was recently drilled and has been placed on production.  This well is currently recovering load fluid and it exhibited strong geotechnical shows. We look forward to reporting back on its initial production results.

Marten Hills West

Headwater successfully drilled an exploration discovery well testing a previously untested Clearwater sand at 13-02-074-01W5, approximately 8 miles southeast of our Marten Hills West accumulation.  The well recently came off load recovery and is producing at rates of approximately 175 bbls/d of oil.  This previously untested Clearwater sand has the potential to materially increase our drilling inventory across our Marten Hills West land base.

Headwater continued delineation drilling on the southern extension of our Marten Hills West Clearwater A pool with 4 follow-up wells.   The wells have exceeded expectations achieving average IP30's of 230 bbls/d of 20 degree API oil. 

Testing of enhanced oil recovery is progressing on the West Marten Hills Clearwater A pool with two waterflood pilots.  First water injection has recently commenced on our northern pilot at 13-07-76-02W5.  Our second pilot at 16-22-75-02W5 will commence injection early in the third quarter of 2023.

Marten Hills Core

Headwater drilled 16 crude oil wells in the fourth quarter of 2022 and has drilled 6 crude oil wells quarter to date in 2023. The upper bench of 21-074-25W4 was developed in the fourth quarter with 11 wells placed on production with IP30's averaging approximately 300 bbls/d.

Waterflood implementation continues with 9 injection wells added in 2023.  The increased injection has elevated stabilized waterflood production from 2,000 bbls/d to in excess of 2,500 bbls/d.

McCully

McCully was placed on production late November and is expected to deliver approximately $22 million of free cash flow (1) for the 2022/2023 winter season, with 64% of volumes hedged at Cdn$25.32/mmbtu. Headwater's structured hedging program for the McCully asset has protected the asset's cash flow against the highly volatile gas pricing experienced this winter.

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

(2)  McCully's winter season is estimated to be November 2022 to April 2023.


2023 GUIDANCE UPDATE  

Headwater is re-confirming its previously released capital expenditures guidance of $200 million and corresponding annual average production at 18,000 boe/d. At strip pricing (1) the Company expects to generate adjusted funds flow from operations of $280 million with exit adjusted working capital of $90 million.



2023 Guidance




2023 annual average production (boe/d)


18,000

Capital expenditures (2)


$200 million




WTI


US$75.21/bbl

WCS


Cdn$77.67/bbl

Adjusted funds flow from operations (3)


$280 million

Dividends


$94 million

Exit adjusted working capital (3)


$90 million

(1)  Based on oil and gas commodity strip pricing at February 27, 2023

(2)  Non-GAAP 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 has declared a quarterly cash dividend to shareholders of $0.10 per common share payable on April 17, 2023, to shareholders of record at the close of business on March 31, 2023. 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 Clearwater resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes.

Our exploration and pool extension results have continued to be robust with multiple new discoveries over the last several months.   The discoveries and extensions continue to quantify the depth and quality of Headwater's drilling inventory which provides a pathway for continued success in the future.

Headwater continues to focus on total shareholder returns through a combination of growth and return of capital through a consistent and growing dividend stream. Based on current strip pricing and our projected growth rate, we anticipate having the optionality to materially increase our quarterly dividend in 2024 and beyond.

2022 RESERVE INFORMATION

Headwater currently has heavy oil reserves located in the Marten Hills and West Nipisi areas 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, 2022 ("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, 2022 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, 2022, filed on SEDAR on March 9, 2023. 

The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by GLJ, effective December 31, 2022. 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

12,937

776

20,750

89

16,614

Proved developed non-producing

221

1,500

51

1

480

Proved undeveloped

4,006

-

145

1

4,032

Total proved

17,164

2,276

20,946

91

21,126

Total probable

11,422

758

9,453

45

13,169

Total proved plus probable

28,587

3,034

30,399

136

34,295

(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, 2023.

(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

602,841

542,500

490,424

448,535

414,689

518,371

466,231

420,704

384,152

354,730

Proved developed non-producing

19,856

16,687

14,333

12,572

11,222

15,297

12,803

10,958

9,590

8,551

Proved undeveloped

96,883

80,232

67,182

56,705

48,181

73,343

59,446

48,609

39,945

32,928

Total proved

719,579

639,419

571,939

517,812

474,092

607,011

538,480

480,271

433,686

396,209

Total probable

463,302

338,961

257,863

202,875

163,966

357,115

260,011

196,588

153,646

123,301

Total proved plus probable

1,182,881

978,380

829,802

720,687

638,058

964,126

798,491

676,859

587,332

519,510

(1)

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

(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, 2022. 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

2023

58,383

85,583

2024

33,249

70,470

Thereafter (1)

3,194

3,323

Total Undiscounted

94,826

159,376

(1)  Future development capital after 2024 is associated with McCully gas plant optimization.


Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2022, 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, 2023, to estimate the reserves volumes and associated values in the GLJ Report. 

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2022
FORECAST PRICES AND COSTS

Year

WTI

Cushing

Oklahoma

($US/Bbl)

MSW

Light Crude

40o API

($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 (2)

($Cdn/$US)











Forecast (3)










2023

80.33

103.77

76.54

4.74

4.23

7.92

14.68

0.0

0.75

2024

78.50

97.74

77.75

4.50

4.40

6.38

11.93

2.3

0.77

2025

76.95

95.27

77.54

4.31

4.21

6.19

11.53

2.0

0.77

2026

77.61

95.58

80.07

4.40

4.27

6.28

9.99

2.0

0.77

2027

79.16

97.07

81.89

4.49

4.34

6.37

10.12

2.0

0.78

2028

80.75

99.01

84.02

4.58

4.43

6.46

10.28

2.0

0.78


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 2023 – 2025 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 2025, 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, 2022.


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 intent to report the results from certain exploration wells; the expectation that two multi-laterals will be drilled prior to the end of the first quarter testing two previously untested zones; the 2023 guidance related to expected annual average production, capital expenditures and the breakdown thereof, adjusted funds flow from operations and exit adjusted working capital; the expectation that the previously untested Clearwater sand at 13-02-074-01W5 has the potential to materially increase the Company's drilling inventory across the Marten Hills West land base; the expected timing of testing of enhanced oil recovery at Marten Hills West; the expectation of McCully performance through the 2022/2023 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; the expectation that discoveries and extensions have continued to quantify the depth and quality of Headwater's drilling inventory which is expected to provide a pathway for continued success in the future; the expectation to have the optionality to increase the quarterly dividend in 2024 and beyond at current strip pricing and with the Company's projected growth rate. 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; disruptions to the Canadian and global economy resulting from major public health events, the Russian-Ukrainian 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; pandemic, 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 most recent Annual Information Form dated March 9, 2023, on SEDAR at www.sedar.com, 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 2023 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 2023 guidance include: AGT US$7.61/mmbtu, foreign exchange rate of US$/Cdn$ of 0.74, blending expense of WCS less $2.00, royalty rate of 17%, operating and transportation costs of $11.50/boe, financial derivatives gains of $1.00/boe, G&A and interest income and other expense of $1.05/boe and cash taxes of $6.00/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. 2023 annual production guidance comprised of: 16,390 bbls/d of heavy oil, 60 bbls/d of natural gas liquids and 9.3 mmcf/d of natural gas.  

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 ("IP") 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 and ratios (such as free cash flow, total sales, net of blending and capital expenditures, adjusted funds flow netback, operating netback and operating netback, including financial derivatives, F&D costs and recycle ratio) 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,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Adjusted funds flow from operations  

71,828

48,731

279,727

117,916

Capital expenditures    

(60,677)

(49,043)

(244,495)

(140,389)

Free cash flow  

11,151

(312)

35,232

(22,473)


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


Three months ended

December 31,

Year ended

December 31,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Total sales

109,377

75,287

458,379

190,940

Blending expense   

(6,403)

(5,162)

(28,332)

(11,423)

Total sales, net of blending expense 

102,974

70,125

430,047

179,517


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 annual financial statements netted by the government grant.


Three months ended

December 31,

Year ended

December 31,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Cash flows used in investing activities

61,957

47,047

232,056

109,127

Proceeds from government grant

780

-

1,988

-

Restricted cash

5,000

1,248

-

1,477

Change in non-cash working capital

(5,223)

748

14,879

29,785

Government grant

(1,837)

-

(4,428)

-

Capital expenditures  

60,677

49,043

244,495

140,389


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. While current income taxes will not be paid until 2023, management believes adjusting for current income taxes in the period incurred is a better indication of the funds generated by the Company.


Three months ended

December 31,

Year ended,

December 31,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Cash flows provided by operating activities

66,448

47,753

283,925

111,656

Changes in non–cash working capital

6,455

978

10,195

6,260

Current income taxes

(1,075)

-

(14,393)

-

Adjusted funds flow from operations

71,828

48,731

279,727

117,916


Adjusted Working Capital

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


Year ended

December 31,



2022

2021


(thousands of dollars)

Working capital

109,433

89,775

Contribution receivable (long-term)

1,104

-

Repayable contribution

(6,720)

-

Financial derivative receivable

(419)

(770)

Financial derivative liability

1,520

3,924

Adjusted working capital

104,918

92,929


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 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 as at December 31, 2021 as compared to December 31, 2022. 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 = ($244.5 million (2022 capital expenditures) + $1.5 million (change in FDC associated with proved developed reserves)) / (16,614 mboe – 9,818 mboe +4,687 mboe) = $21.42 per boe. Total proved F&D is calculated as follows = ($244.5 million (2022 capital expenditures) + $6.2 million (change in FDC associated with proved reserves)) / (21,126 mboe – 15,663 mboe +4,687 mboe) = $24.70 per boe. Total proved plus probable F&D is calculated as follows = ($244.5 million (2022 capital expenditures) + $65.0 million (change in FDC associated with proved plus probable reserves)) / (34,295 mboe – 23,790 mboe +4,687 mboe) = $20.38 per boe.

Recycle ratio

Recycle ratio is used as a measure of capital efficiency. 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.

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