HEADWATER EXPLORATION INC. ANNOUNCES DIVIDEND POLICY, 2023 BUDGET, OPERATIONS UPDATE AND THIRD QUARTER RESULTS

HEADWATER EXPLORATION INC. ANNOUNCES DIVIDEND POLICY, 2023 BUDGET, OPERATIONS UPDATE AND THIRD QUARTER RESULTS

Canada NewsWire

CALGARY, AB, Nov. 3, 2022 /CNW/ - Headwater Exploration Inc. (the "Company" or "Headwater") (TSX: HWX) is pleased to announce its inaugural quarterly cash dividend in conjunction with its operating and financial results for the three and nine months ended September 30, 2022 and its 2023 budget.

Growth and Return of Capital

Headwater expects approximately 38% production per share growth in 2023 while underspending anticipated cash flow. As a result of continued exceptional results, Headwater's Board of Directors (the "Board") has implemented a return of capital strategy with the declaration of Headwater's inaugural quarterly cash dividend of $0.10 per common share. The first dividend will be payable on January 16, 2023, to shareholders of record at the close of business on December 30, 2022. This dividend is designated as an eligible dividend for Canadian income tax purposes. The Board expects that the regular quarterly dividend can be maintained in conjunction with our anticipated growth profile at a long term WTI oil price of US$55/bbl. Based on Headwater's closing common share price on November 2, 2022, of $7.21 per share, this represents an annual yield of approximately 5.5%.

Continued Exploration Success

Headwater drilled a successful exploration test at 16-22-075-02W5 in Marten Hills West which has extended our proven pool boundaries by approximately 3.5 miles. This well has achieved an average 30-day production ("IP30") rate of 330 bbls/d of oil, providing payout in approximately 4-5 months at US$80/bbl WTI.

We also drilled two successful 1.5 mile extended reach step-out wells in our Marten Hills core area. The 12-08-075-24W4 well has achieved an IP30 rate of 377 bbls/d and the 11-08-075-24W4 well will complete its 30-day initial production period mid-November. The wells have extended our core area pool boundaries by approximately 1.5 miles. 

In our Marten Hills central area we drilled two successful pool extension wells. The wells at 02/16-14-075-26W4 and 03/16-14-075-26W4 have confirmed our geotechnical interpretation of this pool which covers approximately 5 sections of 100% owned Headwater lands. These wells achieved IP30's of 130 bbls/d, providing payout in approximately 8-9 months at US$80/bbl WTI.

Preliminary 2023 Budget

In assessing our continued success and our initial return of capital strategy, the Board has approved an initial capital budget for 2023 of $200 million resulting in 2023 annual average production of 18,000 boe/d (92% heavy oil).

The capital budget is expected to generate 38% production per share growth at a reinvestment rate of 60%-70% of 2023 forecasted adjusted funds flow from operations at US$75/bbl to US$85/bbl WTI.  

At US$75/bbl to US$85/bbl WTI, Headwater forecasts 2023 adjusted funds flow from operations of $285-$330 million and free cash flow of approximately $85-$130 million resulting in estimated positive exit 2023 adjusted working capital of $105-$150 million.

Selected financial and operational information is outlined below and should be read in conjunction with the unaudited condensed interim 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

Financial and Operating Highlights


 

Three months ended

September 30,

 

 

Percent
Change

 

Nine months ended

September 30,

 

 

Percent

Change


2022

2021

2022

2021

Financial (thousands of dollars except share data)







Sales, net of blending (1) (4)

94,949

48,841

94

327,073

109,392

199

Adjusted funds flow from operations (2)

58,441

31,524

85

207,899

69,185

200

     Per share - basic

0.25

0.16

56

0.92

0.35

163

                     - diluted

0.25

0.13

92

0.89

0.29

207

Cash flow provided by operating activities 

72,060

27,888

158

217,477

63,903

240

     Per share - basic

0.31

0.14

121

0.96

0.32

200

                     - diluted

0.30

0.12

150

0.93

0.27

244

Net income

31,545

26,106

21

122,320

17,901

583

     Per share - basic

0.14

0.13

8

0.54

0.09

500

                     - diluted

0.13

0.12

8

0.53

0.08

563

Capital expenditures (1)

71,001

37,293

90

183,818

91,346

101

Adjusted working capital (2)




117,967

63,709

85

Shareholders' equity




525,006

295,528

78

Weighted average shares (thousands) 







     Basic

229,909

202,313

14

225,794

198,385

14

     Diluted

236,658

218,190

8

232,984

214,166

9

Shares outstanding, end of period (thousands)







     Basic




229,911

202,466

14

     Diluted (5)




241,593

240,447

-

Operating (6:1 boe conversion)















Average daily production







  Heavy crude oil (bbls/d)

10,842

7,637

42

10,695

5,751

86

  Natural gas (mmcf/d)

4.3

0.3

1,333

7.2

3.7

95

  Natural gas liquids (bbls/d)

55

-

100

43

3

1,333

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

11,612

7,688

51

11,929

6,363

87
















Average daily sales (6) (boe/d)

11,680

7,613

53

11,925

6,355

88








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







  Operating







     Sales, net of blending (4)

88.36

69.73

27

100.46

63.05

59

     Royalties

(21.93)

(10.46)

110

(20.21)

(8.66)

133

     Transportation

(3.94)

(8.68)

(55)

(4.31)

(7.86)

(45)

     Production expenses

(5.95)

(4.42)

35

(5.79)

(4.88)

19









Operating netback (3)

56.54

46.17

22

70.15

41.65

68

     Realized losses on financial derivatives 

-

-

-

(1.29)

(0.23)

461

Operating netback, including financial derivatives (3)

56.54

46.17

22

68.86

41.42

66

     General and administrative expense

(1.46)

(1.40)

4

(1.49)

(1.61)

(7)

     Interest income and other expense (8)

1.18

0.24

392

0.58

0.08

625

     Current tax expense

(1.87)

-

100

(4.09)

-

100

 Adjusted funds flow netback (3)

54.39

45.01

21

63.86

39.89

60

(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 interim financial statements blending expense is recorded within blending and transportation expense.

(5)

In-the-money dilutive instruments as at September 30, 2022 includes 7.2 million stock options with a weighted average exercise price of $2.51, 3.5 million warrants issued pursuant to the recapitalization transaction in March 2020 with an exercise price of $0.92, 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.

(7)

Netbacks are calculated using average sales volumes. For the three months ended September 30, 2022, sales volumes comprised of 10,910 bbs/d of heavy oil, 4.3 mmcf/d of natural gas and 55 bbls/d of natural gas liquids (2021- heavy oil of 7,562 bbls/d and natural gas of 0.3 mmcf/d). For the nine months ended September 30, 2022, sales volumes comprised of 10,690 bbls/d of heavy oil, 7.2 mmcf/d of natural gas and 43 bbls/d of natural gas liquids (2021- heavy oil of 5,743 bbls/d, natural gas of 3.7 mmcf/d and natural gas liquids of 3 bbls/d). 

(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."



THIRD QUARTER 2022 HIGHLIGHTS

  • Realized adjusted funds flow from operations (1) of $58.4 million ($0.25 per share basic) and cash flows from operating activities of $72.1 million ($0.31 per share basic) representing an increase of 85% and 158%, respectively, over the third quarter of 2021.

  • Recognized net income of $31.5 million ($0.14 per share basic) representing an increase of 21% from the third quarter of 2021.

  • Achieved an operating netback (2) of $56.54/boe and an adjusted funds flow netback (2) of $54.39/boe representing an increase of 22% and 21%, respectively, over the third quarter of 2021.

  • Production averaged 11,612 boe/d (consisting of 10,842 bbls/d of heavy oil, 4.3 mmcf/d of natural gas and 55 bbls/d of natural gas liquids) representing an increase of 51% from the third quarter of 2021.

  • Executed a $71.0 million capital expenditure (3) program including 9 successful exploration wells in Marten Hills West plus 8 injection wells in Marten Hills as part of Headwater's enhanced oil recovery project.

  • Added 8.25 sections of additional crown lands prospective for Clearwater oil in the Greater Peavine area.

  • As at September 30, 2022, Headwater had adjusted working capital (1) of $118.0 million, working capital of $113.4 million and no outstanding bank debt.

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

Operations Update

Marten Hills West

In addition to the previously discussed successful exploration extension well at 16-22-075-02W5, an additional 5 wells were drilled in the Clearwater A in the third quarter of 2022. The IP30 rates on these wells have continued to exceed our expectations, achieving average rates of >175 bbls/d of oil.

Headwater has continued to delineate the Clearwater B formation with a total of 3 wells being drilled in the quarter. IP30 rates on these wells have averaged 100 bbls/d of oil which is consistent with expectations for the Clearwater B.

A pilot waterflood to assess the enhanced oil recovery potential in the Clearwater A is contemplated for the first quarter of 2023.

Marten Hills Core

We have continued operations in the Marten Hills core area with the development of the upper bench in section 24-074-25W4. Six wells were drilled during the quarter with exceptional results.  On average the wells have achieved IP30 rates of >350 bbls/d per well. 

Waterflood implementation in the core area has resulted in production stabilization of approximately 2,000 bbls/d (20% of current core area production). The production stabilization witnessed over the last several months is consistent with expectations and it continues to demonstrate that enhanced oil recovery is a viable option for the Clearwater formation that is expected to materially increase ultimate oil recovery. Headwater plans to continue to implement additional waterflood patterns with expectations that all of the core area will be under waterflood by the middle of 2024.

Greater Peavine Area

Our first exploration test, a stratigraphic test at 06-16-074-18W5 in our Shadow prospect is currently drilling.  Immediately following this well, the rig will spud our first multi-lateral horizontal well in the same prospect area. Headwater has one drilling rig assigned to continue drilling exploration prospects through year end and into the first quarter of 2023. The current schedule will see this rig drill a total of three horizontal wells at Shadow, prior to moving to test additional prospects at Peavine, Utikima Lake and Seal. The initial seven exploration wells are expected to be rig released by early February.  We look forward to providing results on the exploration program throughout the first quarter of 2023.

Since the start of the fourth quarter, Headwater has added an additional 6 sections of land in Peavine, increasing our total land position in the Greater Peavine area to 117.5 sections.

McCully 

McCully is scheduled to be placed back on production at the end of November. We have hedged approximately 4.3 mmcf/d representing 57% of our estimated winter season's production at a price of Cdn$28/mcf. McCully is anticipated to deliver record free cash flow of approximately $28 million over the winter season (1). This asset is long-life, low decline and adds to the sustainability of Headwater's dividend.

(1)

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

2022 Guidance Update

The Company remains on track to achieve its previously released annual production guidance of 13,000 boe/d. Capital expenditures for the year are now expected to be $245 million which represents an increase of approximately 6.5% from our previously released capital budget of $230 million. The increase in the capital budget is a result of approximately $7.5 million of additional costs associated with inflation and an additional $7.5 million of spending on equipment inventory and civil construction work to prepare for an active first quarter in 2023. With the $15 million increase in capital and the declared $23 million dividend, the forecast exit adjusted working capital is now approximately $113 million.


Previous

2022 Guidance (1)

Revised

2022 Guidance




2022 annual average production (boe/d)

13,000

13,000




Capital expenditures (2)

$230 million

$245 million

Adjusted funds flow from operations (3)

$295 million

$287 million

Dividend payable

$0 million

$23 million

Exit adjusted working capital (3)

$160 million

$113 million

(1)

Previous guidance released on August 4, 2022.

(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.



Credit Facility

Headwater has executed a commitment letter for a credit facility in the amount of $100 million with a senior lender. With the 2023 guidance as outlined, Headwater does not intend to draw on the credit facility.

Outlook

The positive working capital balance and credit facility provide a war chest to continue to provide Headwater the optionality to organically expand its Clearwater resources base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes.

2023 will be another exciting year for Headwater as it targets 38% production growth while testing material exploration potential. Based on current strip pricing, we anticipate generating significant free cash flow above our capital expenditures and committed quarterly dividend which will allow the optionality to continually increase our regular quarterly dividend and/or provide special dividends while pursuing incremental opportunities.

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, revised 2022 and 2023 guidance related to expected annual average production, expected reinvestment rate in 2023, capital expenditures and the breakdown thereof, adjusted funds flow from operations, expected dividends, free cash flow and exit adjusted working capital; the expectation to deliver 38% production per share growth in 2023 while underspending anticipated cash flow; the expected timing of the inaugural quarterly dividend; the expectation the quarterly dividend can be maintained in conjunction with our long-term growth profile at long term WTI of US$55/bbl; the expected timing of the enhanced oil recovery pilot in the Clearwater A; the expectation that waterflood implementation is expected to materially increase ultimate oil recovery and the expectation that Headwater plans to continue to implement additional waterflood patterns with expectations that all of the core area will be under waterflood by the middle of 2024; the expected drilling schedule in the Greater Peavine area including two additional wells at Shadow and additional prospects at Peavine, Utikima Lake and Seal, which are all expected to be rig released by early February 2023 with the expectation that results on the exploration program will be provided throughout the first quarter of 2023; the expectation to re-start McCully operations in late November 2022; the expectation that the McCully asset will generate $28 million of free cash flow over the winter season; the expectation that the Company will not draw on its credit facility in 2023; the expectation that the Company's positive working capital balance and credit facility will provide Headwater the optionality to organically expand its Clearwater resources base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes; and the anticipation that the Company will generate significant free cash flow above our capital expenditures and committed quarterly dividend which will allow the optionality to continually increase our regular quarterly dividend and/or provide special dividends while pursuing incremental opportunities. 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; 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.

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 and 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 revised 2022 guidance include: WTI US$94.90/bbl, WCS Cdn$99.90/bbl, AGT US$15.10/mmbtu, foreign exchange rate of US$/Cdn$ of 0.77, blending expense of WCS less $2.00, royalty rate of 20%, operating and transportation costs of $10.00/boe, financial derivatives losses of $0.40/boe, G&A and interest income and other expense of $0.90/boe and cash taxes of $3.90/boe. The AGT price is the volume weighted average price for the winter producing months in the McCully field which include January to April and November to December. The assumptions used in the 2023 guidance include: WTI US$75.00-US$85.00/bbl, WCS Cdn$75.00-Cdn$88.50/bbl, AGT US$19.20/mmbtu, foreign exchange rate of US$/Cdn$ of 0.73, blending expense of WCS less $2.00, royalty rate of 16%-18%, operating and transportation costs of $10.50/boe, financial derivatives losses of $0.70/boe, G&A and interest income and other expense of $0.90/boe and cash taxes of $6.10/boe-$8.10/boe. The AGT price is the volume weighted 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 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 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

September 30,

 

Nine months ended

September 30,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Adjusted funds flow from operations  

58,441

31,524

207,899

69,185

Capital expenditures    

(71,001)

(37,293)

(183,818)

(91,346)

Free cash flow  

(12,560)

(5,769)

24,081

(22,161)






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


 

Three months ended

September 30,

 

Nine months ended

September 30,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Total sales

99,587

50,123

349,002

115,653

Blending expense   

(4,638)

(1,282)

(21,929)

(6,261)

Total sales, net of blending expense 

94,949

48,841

327,073

109,392






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 interim financial statements netted by the government grant.


 

Three months ended

September 30,

 

Nine months ended

September 30,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Cash flows used in investing activities

54,062

23,741

170,099

62,080

Proceeds from government grant

1,208

-

1,208

-

Restricted cash

-

(1,248)

(5,000)

229

Change in non-cash working capital

15,731

14,800

20,102

29,037

Government grant

-

-

(2,591)

-

Capital expenditures  

71,001

37,293

183,818

91,346






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

September 30,

 

Nine months ended

September 30,


2022

2021

2022

2021


(thousands of dollars)

(thousands of dollars)

Cash flows provided by operating activities

72,060

27,888

217,477

63,903

Changes in non–cash working capital

(11,610)

3,636

3,740

5,282

Current income taxes

(2,009)

-

(13,318)

-

Adjusted funds flow from operations

58,441

31,524

207,899

69,185






Adjusted Working Capital

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




As at

September 30,

2022

As at

December 31,
2021






(thousands of dollars)

Working capital



113,381

89,775

Contribution receivable (long-term)



671

-

Repayable contribution 



(4,195)

-

Financial derivative receivable



(711)

(770)

Financial derivative liability



8,821

3,924

Adjusted working capital



117,967

92,929






Non-GAAP Ratios

Payout

Headwater uses this ratio to evaluate is operational performance and capital allocation processes. Payout is calculated as the time at which a well or project's cumulative operating netback equals total capital expenditures. 

Reinvestment Rate

Management believes the reinvestment rate is a useful measure to analyze the ratio of funds generated by the Company and used for reinvestment. Reinvestment rate is calculated as capital expenditures divided by adjusted funds flow from operations.

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.

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.

Cision View original content: http://www.newswire.ca/en/releases/archive/November2022/03/c3171.html

Copyright CNW Group 2022