Financial and Operating Highlights
Three months ended | Percent | Year ended | Percent | ||||
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 |
(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." |
FOURTH QUARTER 2022 HIGHLIGHTS
- Headwater declared its inaugural quarterly cash dividend of
$0.10 per common share and returned$23.4 million to shareholders inJanuary 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
- 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 |
100/12-08-078-09W5 | 300 | |
100/13-08-078-09W5 | 288 | |
100/05-08-078-09W5 | 276 | |
100/13-16-078-09W5 | 201 | |
100/14-16-078-09W5 | 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
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.
Headwater successfully drilled an exploration discovery well testing a previously untested
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.
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
(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 |
2023 GUIDANCE UPDATE
Headwater is re-confirming its previously released capital expenditures guidance of
2023 Guidance | ||
2023 annual average production (boe/d) | 18,000 | |
Capital expenditures (2) | ||
WTI | ||
WCS | ||
Adjusted funds flow from operations (3) | ||
Dividends | ||
Exit adjusted working capital (3) |
(1) Based on oil and gas commodity strip pricing at |
(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
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
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
The following tables are a summary of Headwater's petroleum and natural gas reserves, as evaluated by GLJ, effective
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 |
(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 |
(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 $M | |
2023 | 58,383 | 85,583 |
2024 | 33,249 | 70,470 |
Thereafter (1) | 3,194 | 3,323 |
Total Undiscounted | 94,826 | 159,376 |
(1) Future development capital after 2024 is associated with McCully gas plant optimization. |
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of
FORECAST PRICES AND COSTS
Year | WTI ($US/Bbl) | MSW Light Crude 40o API ($Cdn/Bbl) | WCS Crude Oil ($Cdn/Bbl) | NYMEX ($US/ MMBtu) | Natural ($Cdn/ MMBtu) | Algonquin ($US/MMBtu) | Price (1) ($Cdn/Mcf) | Inflation %/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 |
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
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
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")
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 | Year ended | |||
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 | Year ended | |||
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 | Year ended | |||
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 | Year ended, | |||
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 is a capital management measure which management uses to assess the Company's liquidity.
Year ended | ||
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
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
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