HEADWATER EXPLORATION INC. ANNOUNCES 2023 RESERVES, YEAR END 2023 OPERATING AND FINANCIAL RESULTS, OPERATIONS UPDATE, INCREASE TO 2024 CAPITAL BUDGET AND DECLARES QUARTERLY DIVIDEND
|
Three months ended
|
Percent |
Year ended
|
Percent |
|||
|
2023 |
2022 |
2023 |
2022 |
|||
Financial
(thousands of dollars except per share and production |
|
|
|
|
|
|
|
Sales, net of blending (1) (4) |
131,690 |
102,974 |
28 |
482,823 |
430,047 |
12 |
|
Adjusted funds flow from operations (2) |
81,983 |
71,828 |
14 |
288,262 |
279,727 |
3 |
|
Per share - basic (3) |
0.35 |
0.31 |
13 |
1.22 |
1.23 |
(1) |
|
- diluted (3) |
0.34 |
0.31 |
10 |
1.21 |
1.21 |
- |
|
Cash flows provided by operating activities |
90,690 |
66,448 |
36 |
303,316 |
283,925 |
7 |
|
Per share - basic |
0.38 |
0.29 |
31 |
1.29 |
1.25 |
3 |
|
- diluted |
0.38 |
0.28 |
36 |
1.28 |
1.23 |
4 |
|
Net income |
45,469 |
39,789 |
14 |
156,072 |
162,109 |
(4) |
|
Per share - basic |
0.19 |
0.17 |
12 |
0.66 |
0.71 |
(7) |
|
- diluted |
0.19 |
0.17 |
12 |
0.66 |
0.70 |
(6) |
|
Capital expenditures (1) |
30,050 |
60,677 |
(50) |
233,846 |
244,495 |
(4) |
|
Adjusted working capital (2) |
|
|
|
63,526 |
104,918 |
(39) |
|
Shareholders' equity |
|
|
|
610,498 |
543,335 |
12 |
|
Dividends declared |
23,658 |
23,392 |
1 |
94,421 |
23,392 |
304 |
|
Per share |
0.10 |
0.10 |
- |
0.40 |
0.10 |
300 |
|
Weighted average shares (thousands) |
|
|
|
|
|
|
|
Basic |
236,408 |
231,766 |
2 |
235,583 |
227,299 |
4 |
|
Diluted |
238,872 |
235,305 |
2 |
237,705 |
230,755 |
3 |
|
Shares outstanding, end of period (thousands) |
|
|
|
|
|
|
|
Basic |
|
|
|
236,580 |
233,920 |
1 |
|
Diluted (5) |
|
|
|
241,138 |
241,029 |
- |
|
Operating (6:1 boe conversion) |
|
|
|
|
|
|
|
Average daily production |
|
|
|
|
|
|
|
Heavy crude oil (bbls/d) |
18,514 |
13,536 |
37 |
16,466 |
11,411 |
44 |
|
Natural gas (mmcf/d) |
8.0 |
11.5 |
(30) |
8.8 |
8.2 |
7 |
|
Natural gas liquids (bbls/d) |
93 |
99 |
(6) |
98 |
57 |
72 |
|
Barrels of oil equivalent (9)(boe/d) |
19,939 |
15,546 |
28 |
18,038 |
12,841 |
40 |
|
Average daily sales (6) (boe/d) |
20,134 |
15,568 |
29 |
18,038 |
12,843 |
40 |
|
Netbacks ($/boe) (3) (7) |
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
|
|
Sales, net of blending (4) |
71.09 |
71.90 |
(1) |
73.34 |
91.74 |
(20) |
|
Royalties |
(12.91) |
(13.51) |
(4) |
(13.01) |
(18.17) |
(28) |
|
Transportation |
(5.12) |
(4.21) |
22 |
(5.35) |
(4.28) |
25 |
|
Production expenses |
(7.34) |
(6.25) |
17 |
(7.17) |
(5.93) |
21 |
|
Operating netback (3) |
45.72 |
47.93 |
(5) |
47.81 |
63.36 |
(25) |
|
Realized gains on financial derivatives |
3.35 |
2.96 |
13 |
2.14 |
0.01 |
na |
|
Operating netback, including financial derivatives (3) |
49.07 |
50.89 |
(4) |
49.95 |
63.37 |
(21) |
|
General and administrative expense |
(1.51) |
(1.14) |
32 |
(1.47) |
(1.38) |
7 |
|
Interest income and other expense (8) |
0.84 |
1.15 |
(27) |
0.92 |
0.76 |
21 |
|
Current tax expense |
(4.14) |
(0.75) |
452 |
(5.62) |
(3.07) |
83 |
|
Adjusted funds flow netback (3) |
44.26 |
50.15 |
(12) |
43.78 |
59.68 |
(27) |
(1) |
Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) |
Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) |
Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(4) |
Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the audited annual financial statements blending expense is recorded within blending and transportation expense. |
(5) |
In-the-money dilutive instruments as at |
(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 |
(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." |
- Achieved record production of 19,939 boe/d (93% heavy oil), an increase of 28% over 2022 fourth quarter production of 15,546 boe/d (87% heavy oil).
- Realized record adjusted funds flow from operations (1) of
$82.0 million ($0.35 per basic share), cash flows from operating activities of$90.7 million ($0.38 per basic share) and free cash flow (3) of$51.9 million . - Achieved an operating netback, including financial derivatives, (2) of
$49.07 /boe and an adjusted funds flow netback (2) of$44.26 /boe. - Generated net income of
$45.5 million ($0.19 per basic share) equating to$24.55 /boe. - Executed a
$30.1 million capital expenditure (3) program including 13 net crude oil wells inMarten Hills West , at a 100% success rate. - Returned
$0.10 per common share to shareholders. - As at
December 31, 2023 , Headwater had working capital of$78.6 million , adjusted working capital (1) of$63.5 million and no outstanding bank debt.
- Achieved average production of 18,038 boe/d (91% heavy oil), an increase of 40% over 2022 annual production of 12,841 boe/d (89% heavy oil).
- Realized adjusted funds flow from operations (1) of
$288.3 million ($1.22 per basic share) and cash flows from operating activities of$303.3 million ($1.29 per basic share). - Achieved an operating netback, including financial derivatives, (2) of
$49.95 /boe and an adjusted funds flow netback (2) of$43.78 /boe. - Generated net income of
$156.1 million ($0.66 per basic share) equating to$23.71 /boe. - Returned a total of
$0.40 per common share or$94.4 million to shareholders. - Proved developed producing reserves increased by 33% to 22.1 mmboe from 16.6 mmboe.
- Total proved reserves increased by 54% to 32.5 mmboe from 21.1 mmboe.
- Total proved plus probable reserves increased by 51% to 51.9 mmboe from 34.3 mmboe.
- Achieved finding and development ("F&D") costs (2), including changes in future development costs of
$19.17 per boe on a proved developed producing basis,$18.61 per boe on a total proved basis and$14.97 per boe on a total proved plus probable basis. - Based on a 2023 adjusted funds flow netback (2) of
$43.78 /boe, achieved recycle ratios (2) of 2.3 on a proved developed producing basis, 2.4 on a total proved basis and 2.9 on a total proved plus probable basis.
(1) |
Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) |
Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) |
Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
Production from
In the Clearwater A, successful tests at 00/03-15-075-01W5 and 02/05-18-075-01W5 have expanded the eastern Clearwater A pool boundary by 4 miles de-risking an additional ten sections of land. The 00/3-15-076-01W5 well achieved a 60-day initial production rate of 157 bbls/d while the 02/05-18-075-01W5 well achieved a 60-day initial production rate of 147 bbls/d. Success from these wells expands the potential of the Clearwater A in
The positive results of the two active waterflood pilots in the Clearwater A suggest that a large portion of the Clearwater A pool will be amenable to secondary recovery. The two active pilots continue to exceed our expectations with decreasing gas oil ratios and greater than 200 bbls/d of stabilized oil production. Continued implementation of the Clearwater A waterflood will occur with a full section waterflood employed by the end of the first quarter of 2024.
The successful discovery well drilled at 02/13-15-076-02W5 in the Clearwater E in the fourth quarter of 2023 has recently been followed up with a second test at 00/04-35-076-02W5. This well finished recovering load fluid
Our discovery well in the Clearwater G at 00/02-30-075-01W5 has achieved a 90-day initial production rate of 160 bbls/d. Three additional Clearwater G tests following up on this discovery will be drilled over the next couple of months to continue validation of the size and potential of this sand.
Further drilling in the Clearwater B will occur in the second half of 2024 with 4 wells planned within this sand.
In 2024 we will continue to advance the secondary recovery efforts in the core converting two sections to injection and growing our stabilized production to more than 4,000 bbls/d. By mid-2025 we will have the entire core area under secondary recovery resulting in reduced corporate declines and required maintenance capital. In addition, we have recently expanded our enhanced recovery efforts with a pilot injector northeast of the core area supporting the 02/12-08-075-24W5 well. Early indications here look excellent with strong injectivity indicating enhanced recovery efforts can be expanded beyond the defined core area in
West Nipisi
In the first quarter of 2024, three Clearwater C extension wells were drilled in the 7-section development area of West Nipisi. The northwest extension wells, 00/14-17-078-09W5 and 00/13-17-078-09W5 have achieved an average per well 30-day initial production rate of 195 bbls/d. The 03/04-04-078-09W5 well, a southern extension test, has achieved a 15-day initial production rate of 215 bbls/d. Results from these three tests validate economic development from the entire 7-section block.
In addition, two multi-lateral wells and a stratigraphic test have been drilled in the West Nipisi expansion area via winter access roads for evaluation of two prospective
At
The exploration team has also identified additional multi-zone prospectivity across 47 sections of newly acquired acreage in an offsetting area called
To date, the team has been successful at acquiring 56 sections of land prospective for
Exploration Land Update
The Headwater team continues its pursuit of organic growth opportunities in and beyond the boundaries of the
McCully
McCully was placed back on production
(1) |
Non-GAAP financial measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) |
McCully's winter season is estimated to continue until |
As a result of Headwater's success in accumulating incremental lands year to date in 2024, the Board of Directors has approved an expansion of the Company's 2024 capital budget from
|
|
2024 Guidance(1) |
|
|
|
2024 annual average production (boe/d) |
|
20,000 |
Capital expenditures (2) |
|
|
Comprised of: |
|
|
Development capital |
|
|
Land |
|
|
Exploration and enhanced oil recovery |
|
|
WTI |
|
|
WCS |
|
|
Adjusted funds flow from operations (3) |
|
|
Exit adjusted working capital (3) |
|
|
Quarterly dividend |
|
|
(1) |
The Company's previous 2024 guidance as set out in a press release dated |
(2) |
Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) |
Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(4) |
For assumptions utilized in the above guidance see "Future Oriented Financial Information" within this press release. |
The Board of Directors of Headwater confirms a cash dividend to shareholders of
Since inception, we have continued to maintain a positive working capital balance. When combined with our existing credit facility, it provides us with optionality to organically expand our resource base, pursue accretive acquisitions and implement additional enhanced oil recovery schemes.
Headwater continues to focus on total shareholder returns through a combination of growth and return of capital.
Headwater currently has heavy oil reserves located in the
The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by McDaniel, effective
Reserves Summary
|
Heavy |
Shale |
Conventional |
|
Oil |
|
Oil |
Gas |
Gas |
NGL |
Equivalent |
|
Mbbls |
MMcf |
MMcf |
Mbbls |
MBOE |
|
|
|
|
|
|
Proved developed producing |
18,073 |
756 |
22,363 |
145 |
22,071 |
Proved developed non-producing |
- |
1,477 |
- |
2 |
248 |
Proved undeveloped |
9,796 |
- |
2,206 |
34 |
10,198 |
Total proved |
27,869 |
2,233 |
24,569 |
181 |
32,517 |
Total probable |
16,982 |
690 |
12,868 |
166 |
19,407 |
Total proved plus probable |
44,851 |
2,923 |
37,437 |
347 |
51,925 |
(1) |
Reserves have been presented on gross basis which are the Company's total working interest share before the deduction of any royalties and without including any royalty interests of the Company. |
(2) |
Based on the average of |
(3) |
Pursuant to the COGE Handbook, reported reserves should target at least a 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. |
Net Present Value of Future Net Revenue
|
Before Income Tax and Discounted at |
After Income Tax and Discounted at |
||||||||
|
0 % |
5 % |
10 % |
15 % |
20 % |
0 % |
5 % |
10 % |
15 % |
20 % |
|
$M |
$M |
$M |
$M |
$M |
$M |
$M |
$M |
$M |
$M |
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing |
778,722 |
688,988 |
613,355 |
553,138 |
505,233 |
664,843 |
591,058 |
527,120 |
475,773 |
434,791 |
Proved developed non- |
13,265 |
10,119 |
7,890 |
6,307 |
5,154 |
9,969 |
7,601 |
5,909 |
4,710 |
3,840 |
Proved undeveloped |
272,562 |
228,530 |
192,511 |
163,319 |
139,600 |
205,597 |
170,049 |
140,776 |
117,040 |
97,801 |
Total proved |
1,064,549 |
927,636 |
813,755 |
722,765 |
649,987 |
880,408 |
768,708 |
673,806 |
597,524 |
536,432 |
Total probable |
741,828 |
556,153 |
434,004 |
350,666 |
291,476 |
572,538 |
427,197 |
331,428 |
266,240 |
220,089 |
Total proved plus probable |
1,806,377 |
1,483,789 |
1,247,759 |
1,073,431 |
941,463 |
1,452,946 |
1,195,905 |
1,005,234 |
863,764 |
756,521 |
(1) |
Based on the average of |
(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 |
Future Development Costs ("FDC")
The following is a summary of the estimated FDC required to bring proved undeveloped reserves and proved plus probable undeveloped reserves on production.
|
Proved Reserves $M |
Proved Plus Probable Reserves $M |
2024 |
99,900 |
99,900 |
2025 |
92,479 |
132,342 |
2026 |
- |
52,631 |
Thereafter (1) |
3,184 |
3,247 |
Total Undiscounted |
195,563 |
288,120 |
(1) |
Future development capital after 2026 is associated with McCully gas plant optimization. |
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS |
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|
Year |
|
WTI
($US/Bbl) |
|
MSW Light Crude 40o API ($Cdn/Bbl) |
|
WCS ($Cdn/Bbl) |
|
NYMEX ($US/ MMBtu) |
|
Natural ($Cdn/ MMBtu) |
|
AGT
Premium to ($Cdn/MMbtu) |
|
McCully Price(2) ($Cdn/Mcf) |
|
Inflation %/Year |
|
Exchange ($Cdn/$US) |
|
|
|
|
|
|
|
|
|
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Forecast(4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2024 |
|
73.67 |
|
92.91 |
|
76.74 |
|
2.75 |
|
2.20 |
|
2.44 |
|
11.94 |
|
0.0 |
|
0.75 |
2025 |
|
74.98 |
|
95.04 |
|
79.77 |
|
3.64 |
|
3.37 |
|
3.10 |
|
15.62 |
|
2.0 |
|
0.75 |
2026 |
|
76.14 |
|
96.07 |
|
81.12 |
|
4.02 |
|
4.05 |
|
3.09 |
|
16.05 |
|
2.0 |
|
0.76 |
2027 |
|
77.66 |
|
97.99 |
|
82.88 |
|
4.10 |
|
4.13 |
|
3.09 |
|
9.74 |
|
2.0 |
|
0.76 |
2028 |
|
79.22 |
|
99.95 |
|
85.04 |
|
4.18 |
|
4.21 |
|
3.09 |
|
9.63 |
|
2.0 |
|
0.76 |
2029 |
|
80.80 |
|
101.94 |
|
86.74 |
|
4.27 |
|
4.30 |
|
3.09 |
|
9.74 |
|
2.0 |
|
0.76 |
Thereafter |
Escalation rate of 2.0% |
|
|
Notes: |
|
|
|
(1) |
Not a published forecast. McDaniel's estimate of the AGT premium to |
(2) |
The forecast McCully gas price is used by McDaniel in calculating the net present value of Headwater's future natural gas net revenues from the McCully Field. The McCully gas price is determined by adjusting the forecast AGT gas prices to reflect the expected premiums received at Headwater's delivery point, transportation costs, as applicable, heat content and marketing conditions. The McCully gas price in years 2024 – 2026 reflects only the winter producing months (January to April and December) to correlate to the intermittent production strategy employed by the Corporation to capture seasonal premium pricing. After 2026, the McDaniel Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year. |
(3) |
The exchange rate used to generate the benchmark reference prices in this table. |
(4) |
As at |
Additional corporate information can be found in the Company's corporate presentation and on Headwater's website at www.headwaterexp.com
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial, "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation, the 2024 guidance related to expected annual average production, capital expenditures and the breakdown thereof, adjusted funds flow from operations, dividends and exit adjusted working capital; the expectation the waterflood pilot results in
FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2024 has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. The assumptions used in the 2024 guidance include: 2024 annual production guidance comprised of: 18,650 bbls/d of heavy oil, 50 bbls/d of natural gas liquids and 7.8 mmcf/d of natural gas, AGT
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.
I NITIAL PRODUCTION RATES: References in this press release to initial production rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.
NON-GAAP AND OTHER FINANCIAL MEASURES
In this press release, we refer to certain financial measures (such as free cash flow, total sales, net of blending and capital expenditures) which do not have any standardized meaning prescribed by IFRS. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this press release contains the terms adjusted funds flow from operations and adjusted working capital, which are considered capital management measures. The term cash flow in this press release is equivalent to adjusted funds flow from operations.
Non-GAAP Financial Measures
Free cash flow
Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures.
|
Three months ended
|
|
Year ended
|
||
|
2023 |
2022 |
|
2023 |
2022 |
|
(thousands of dollars) |
|
(thousands of dollars) |
||
Adjusted funds flow from operations |
81,983 |
71,828 |
|
288,262 |
279,727 |
Capital expenditures |
(30,050) |
(60,677) |
|
(233,846) |
(244,495) |
Free cash flow |
51,933 |
11,151 |
|
54,416 |
35,232 |
Total sales, net of blending
Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the audited annual financial statements blending expense is recorded within blending and transportation expense.
|
Three months ended
|
|
Year ended
|
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|
2023 |
2022 |
|
2023 |
2022 |
|
(thousands of dollars) |
|
(thousands of dollars) |
||
Total sales |
138,426 |
109,377 |
|
511,234 |
458,379 |
Blending expense |
(6,736) |
(6,403) |
|
(28,411) |
(28,332) |
Total sales, net of blending expense |
131,690 |
102,974 |
|
482,823 |
430,047 |
Capital expenditures
Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's audited annual financial statements netted by the government grant.
|
Three months ended |
|
Year ended
|
||
|
2023 |
2022 |
|
2023 |
2022 |
|
(thousands of dollars) |
|
(thousands of dollars) |
||
Cash flows used in investing activities |
54,716 |
61,957 |
|
243,714 |
232,056 |
Proceeds from government grant |
1,200 |
780 |
|
1,200 |
1,988 |
Restricted cash |
- |
5,000 |
|
- |
- |
Change in non-cash working capital |
(23,392) |
(5,223) |
|
(8,594) |
14,879 |
Government grant |
(2,474) |
(1,837) |
|
(2,474) |
(4,428) |
Capital expenditures |
30,050 |
60,677 |
|
233,846 |
244,495 |
Capital Management Measures
Adjusted Funds Flow from Operations
Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the performance of the Company's oil and gas properties. Adjusted funds flow from operations is an indicator of operating performance as it varies in response to production levels and management of production and transportation costs. Management believes that by eliminating changes in non-cash working capital and deducting current income taxes, adjusted funds flow from operations is a useful measure of operating performance.
|
Three months ended
|
Year ended,
|
||
|
2023 |
2022 |
2023 |
2022 |
|
(thousands of dollars) |
(thousands of dollars) |
||
Cash flows provided by operating activities |
90,690 |
66,448 |
303,316 |
283,925 |
Changes in non–cash working capital |
(5,387) |
6,455 |
(7,050) |
10,195 |
Current income tax expense |
(7,668) |
(1,075) |
(36,990) |
(14,393) |
Current income taxes paid |
4,348 |
- |
28,986 |
- |
Adjusted funds flow from operations |
81,983 |
71,828 |
288,262 |
279,727 |
Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity. Financial derivative receivable/liability have been excluded as these contracts are subject to a high degree of volatility prior to settlement and relate to future production periods. Financial derivative receivable/liability are included in adjusted funds flow from operations when the contracts are ultimately realized. Management has included the effects of the contribution receivable and repayable contribution to provide a better indication of Headwater's net financing obligations.
|
Year ended
|
|
|
||
|
2023 |
2022 |
|
(thousands of dollars) |
|
Working capital |
78,610 |
109,433 |
Contribution receivable (long-term) |
- |
1,104 |
Repayable contribution |
(11,405) |
(6,720) |
Financial derivative receivable |
(3,758) |
(419) |
Financial derivative liability |
79 |
1,520 |
Adjusted working capital |
63,526 |
104,918 |
Non-GAAP Ratios
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period.
Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Operating netback, including financial derivatives is defined as operating netback plus realized gains or losses on financial derivatives.
Adjusted funds flow per share
Adjusted funds flow per share is a non-GAAP ratio and is used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding on a basic or diluted basis.
F&D costs per boe
F&D costs is used as a measure of capital efficiency. The F&D cost calculation includes all capital expenditure (exploration and development) for that period plus the change in future development capital ("FDC") for that period based on the evaluations completed by
Recycle ratio
Recycle ratio is used as a measure of profitability. Recycle ratio is calculated as the Company's adjusted funds flow netback divided by F&D costs per boe.
Per boe numbers
This press release represents various results on a per boe basis including Headwater average realized sales price, net of blending, financial derivatives gains (losses) per boe, royalty expense per boe, transportation expense per boe, production expense per boe, general and administrative expenses per boe, interest income and other expense per boe and current taxes per boe. These figures are calculated using sales volumes.
SOURCE