Financial and Operating Highlights
Three months ended | Year ended | ||||
2021 | 2020 | 2021 | 2020 | ||
Financial (thousands of dollars except share data) | |||||
Total sales, net of blending (1) (4) | 70,125 | 6,283 | 179,517 | 9,156 | |
Cash flows provided by (used in) operating activities | 47,753 | (1,451) | 111,656 | 230 | |
Per share - basic | 0.23 | (0.01) | 0.56 | - | |
- diluted | 0.22 | (0.01) | 0.52 | - | |
Adjusted funds flow from operations (2) | 48,731 | 4,816 | 117,916 | 8,782 | |
Per share - basic | 0.24 | 0.03 | 0.59 | 0.06 | |
- diluted | 0.22 | 0.03 | 0.55 | 0.06 | |
Net income | 27,927 | 16,919 | 45,828 | 6,707 | |
Per share - basic | 0.14 | 0.10 | 0.23 | 0.05 | |
- diluted | 0.13 | 0.10 | 0.21 | 0.05 | |
Adjusted net income (1) | 32,596 | 21,208 | 78,427 | 10,996 | |
Per share - basic | 0.16 | 0.13 | 0.39 | 0.08 | |
- diluted | 0.15 | 0.13 | 0.36 | 0.08 | |
Capital expenditures (1) | 49,043 | 1,748 | 140,389 | 2,277 | |
Property Acquisition | - | 135,297 | - | 135,297 | |
Adjusted working capital (2) | 92,929 | 80,759 | |||
Shareholders' equity | 397,791 | 269,030 | |||
Weighted average shares (thousands) | |||||
Basic | 204,005 | 161,365 | 199,802 | 139,379 | |
Diluted | 220,958 | 168,600 | 215,861 | 145,377 | |
Shares outstanding, end of period (thousands) | |||||
Basic | 217,681 | 195,106 | |||
Diluted (5) | 242,448 | 238,121 | |||
Operating (6:1 boe conversion) | |||||
Average daily production | |||||
Heavy crude oil (bbls/d) | 9,377 | 979 | 6,665 | 246 | |
Natural gas (mmcf/d) | 6.4 | 4.0 | 4.4 | 3.8 | |
Natural gas liquids (bbls/d) | - | 3 | 2 | 3 | |
Barrels of oil equivalent (9)(boe/d) | 10,449 | 1,646 | 7,393 | 882 | |
Average daily sales (6) (boe/d) | 10,459 | 1,646 | 7,390 | 882 | |
Netbacks ($/boe) (3) (7) | |||||
Operating | |||||
Sales, net of blending (4) | 72.88 | 41.50 | 66.57 | 28.37 | |
Royalties | (11.34) | (3.86) | (9.62) | (2.03) | |
Transportation | (6.98) | (5.10) | (7.55) | (2.40) | |
Production expenses | (4.20) | (7.92) | (4.64) | (8.98) | |
Operating netback (3) | 50.36 | 24.62 | 44.76 | 14.96 | |
Realized gains on financial derivatives | 1.41 | 10.42 | 0.35 | 17.09 | |
Operating netback, including financial derivatives (3) | 51.77 | 35.04 | 45.11 | 32.05 | |
General and administrative expense | (1.23) | (4.64) | (1.48) | (8.78) | |
Interest income and other expense (8) | 0.10 | 1.39 | 0.09 | 3.94 | |
Adjusted funds flow netback (3) | 50.64 | 31.79 | 43.72 | 27.21 |
(1) | Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) | Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) | Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(4) | Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the annual financial statements blending expense is recorded within blending and transportation expense. |
(5) | Includes in-the-money dilutive instruments as at |
(6) | Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company's heavy crude oil sales volumes and production volumes differ due to changes in inventory. |
(7) | Netbacks are calculated using average sales volumes. Fourth quarter 2021 sales volumes comprised of 9,388 bbs/d of heavy oil and 6.4 mmcf/d of natural gas. Annual 2021 sales volumes comprised of 6,661 bbls/d of heavy oil, 4.4 mmcf/d of natural gas and 2 bbls/d of natural gas liquids. |
(8) | Excludes accretion on decommissioning liabilities and interest on lease liability. |
(9) | See '"Barrels of Oil Equivalent." |
FOURTH QUARTER 2021 HIGHLIGHTS
- Achieved average production of 10,449 boe/d (consisting of 9,377 bbls/d of heavy oil and 6.4 mmcf/d of natural gas), an increase of over 500% from the fourth quarter of 2020.
- Cash flows provided by operating activities was
$47.8 million ,$0.23 per share (basic), and adjusted funds flow from operations (1) was$48.7 million ,$0.24 per share (basic). - Achieved an operating netback (2) of
$50.36 /boe and an adjusted funds flow netback (2) of$50.64 /boe. - Generated net income of
$27.9 million ,$0.14 per share (basic), and adjusted net income (3) of$32.6 million ,$0.16 per share (basic). - Executed a
$49.0 million capital expenditure(3) programin theMarten Hills area including 3 successful exploration wells and 8 multi-lateral development wells at a 100% success rate. In addition to the drilling program,$26.5 million was spent on equipping and facilities primarily for ongoing construction of Headwater's 100% owned 15,000 bbls/d oil processing facility. The oil processing facility was commissioned subsequent toDecember 31, 2021 . - On
December 23, 2021 ,Cenovus Marten Hills Partnership , a wholly owned subsidiary of Cenovus Energy Inc. ("Cenovus"), exercised its 15 million warrants (the "Cenovus Warrants") for 15 million common shares of the Company for total proceeds of$30 million . On exercise of the Cenovus Warrants, Cenovus held approximately 7% of the outstanding common shares of the Company. - As at
December 31, 2021 , Headwater had working capitalof$89.8 million , adjusted working capital (1) of$92.9 million and no outstanding debt.
YEAR ENDED DECEMBER 31, 2021
- Achieved average production of 7,393 boe/d (consisting of 6,665 bbls/d of heavy oil, 4.4 mmcf/d of natural gas and 2 bbls/d of natural gas liquids), an increase of over 700% from 2020 annual production of 882 boe/d.
- Cash flows provided by operating activities was
$111.7 million ,$0.56 per share (basic), and adjusted funds flow from operations (1) was$117.9 million ,$0.59 per share (basic). - Executed a
$140.4 million capital expenditure (3) programin the Marten Hills area including 58 net wells (51 crude oil wells, 4 source wells and 3 stratigraphic tests) at a 100% success rate. - The Company's joint gas processing facility, commissioned in the third quarter of 2021, in combination with pipeline infrastructure installed in the first quarter of 2021, has resulted in an approximate 50% reduction in Headwater's CO2e emissions intensity on a barrel of oil equivalent basis over the 2021 calendar year.
- Proved developed producing reserves increased by 96% to 9.8 mmboe from 5.0 mmboe.
- Total proved reserves increased by 65% to 15.7 mmboe from 9.5 mmboe.
- Proved plus probable reserves increased by 82% to 23.8 mmboe from 13.1 mmboe.
- Achieved finding and development ("F&D") costs (2), including changes in future development costs of
$20.43 per boe on a proved basis and$13.92 per boe on a proved plus probable basis. Based on a 2021 operating netback including financial derivatives (2) of$45.11 /boe, achieved recycle ratios (2) of 2.2 on a proved basis and 3.2 on a proved plus probable basis.
(1) | Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) | Non-GAAP ratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) | Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
Operations Update
The first quarter of 2022 has been very active to date. Accomplishments include:
- Rig released 11 6-leg producing horizontal wells
- Rig released 5 4-leg horizontal injection wells
- The balance of the first quarter program in the core area will see an additional 6 4-leg horizontal injection wells
Initial production ("IP") rates from our latest core area wells have been consistent with expectations and the results of previous quarters, with an average post load recovery 30-day IP ("IP30") rate of approximately 400 bbls/d.
On
Enhanced Oil Recovery
The initial results on our first 3 waterflood pilots have exhibited very encouraging behavior over the past nine months. Our independent reserves evaluator has evaluated the pilot waterflood results and has provided increased per well reserves bookings associated with waterflood. The pilot results provide confidence to continue development of our core area under full field waterflood.
Our next phase of injection is scheduled to begin imminently, with the next 9 injectors to be placed on injection prior to the end of
Exploration Update
Since our last update to shareholders on
The Marten Hills West Clearwater A hydrocarbon accumulation has been successfully extended 20km southeast and 10km east of our discovery wells at 11-05-076-02W5 and 13-07-076-02W5 through the successful drilling of 15-29-075-01W5 and 16-27-074-01W5. The 15-29-075-01W5 well has produced at a 24-day IP rate of approximately 82 bbls/d of 21 degree API oil. The 16-27-74-01W5 well finished recovering load fluid
A second test in the Clearwater B at 00/09-34-075-03W5 was rig released on
Headwater will continue to delineate both the Clearwater A and B sands through additional drilling in the back half of the year.
McCully Asset
The McCully asset has produced strongly throughout this winter season and Headwater anticipates continuing to produce the field until
(1) | Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
2022 Outlook
With the increase in realized commodity pricing in the first quarter of 2022, the Company expects to generate adjusted funds flow from operations (1) of
(1) | Capital management measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(2) | Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures" within this press release. |
(3) | Pricing assumptions are as follows: WTI |
2021 Reserve Information
Headwater currently has heavy oil reserves located in the Marten Hills area of
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 | 6,439 | 810 | 18,229 | 206 | 9,818 |
Proved developed non-producing | - | 994 | - | - | 166 |
Proved undeveloped | 5,226 | - | 1,995 | 121 | 5,680 |
Total proved | 11,665 | 1,804 | 20,224 | 327 | 15,663 |
Total probable | 6,697 | 507 | 6,983 | 182 | 8,127 |
Total proved plus probable | 18,362 | 2,311 | 27,206 | 509 | 23,790 |
(1) | Reserves have been presented on gross basis which are the Company's total working interest share before the deduction of any royalties and without including any royalty interests of the Company. |
(2) | Based on the average of |
(3) | Pursuant to the COGE Handbook, reported reserves should target at least a 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. |
Net Present Value of Future Net Revenue
Before Income Tax and Discounted at | After Income Tax and Discounted at | |||||||||
0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% | |
$MM | $MM | $MM | $MM | $MM | $MM | $MM | $MM | $MM | $MM | |
Proved developed producing | 330,844 | 309,567 | 288,497 | 270,537 | 255,468 | 306,069 | 286,707 | 267,285 | 250,754 | 236,934 |
Proved developed non-producing | 1,065 | 1,030 | 961 | 880 | 801 | 699 | 706 | 670 | 618 | 563 |
Proved undeveloped | 148,348 | 128,751 | 112,297 | 98,450 | 86,739 | 111,565 | 95,912 | 82,718 | 71,601 | 62,201 |
Total proved | 480,258 | 439,349 | 401,755 | 369,867 | 343,008 | 418,332 | 383,324 | 350,673 | 322,973 | 299,698 |
Total probable | 282,703 | 230,817 | 192,873 | 164,846 | 143,509 | 221,976 | 180,331 | 149,943 | 127,648 | 110,767 |
Total proved plus probable | 762,961 | 670,166 | 594,628 | 534,713 | 486,517 | 640,309 | 563,655 | 500,616 | 450,621 | 410,465 |
(1) | Based on the average of |
(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 $MM | Proved Plus Probable Reserves $MM | |
2022 | 66,150 | 70,350 |
2023 | 19,806 | 21,211 |
Thereafter (1) | 2,661 | 2,768 |
Total Undiscounted | 88,616 | 94,329 |
(1) | Future development capital after 2023 is associated with McCully gas plant optimization. |
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of
FORECAST PRICES AND COSTS
Year | WTI ($US/Bbl) | MSW Light 40o API ($Cdn/Bbl) | WCS ($Cdn/Bbl) | NYMEX ($US/ MMBtu) | Natural Gas ($Cdn/ MMBtu) | Algonquin ($US/MMBtu) | McCully Price(1) ($Cdn/Mcf) | Inflation %/Year | Exchange Rate (1) ($Cdn/$US) |
Forecast(3) | |||||||||
2022 | 72.83 | 86.82 | 74.43 | 3.85 | 3.56 | 7.55 | 13.84 | 0.0 | 0.797 |
2023 | 68.78 | 80.73 | 69.17 | 3.44 | 3.20 | 5.64 | 10.19 | 2.3 | 0.797 |
2024 | 66.76 | 78.01 | 66.54 | 3.17 | 3.05 | 4.37 | 6.93 | 2.0 | 0.797 |
2025 | 68.09 | 79.57 | 67.87 | 3.24 | 3.10 | 4.46 | 6.91 | 2.0 | 0.797 |
2026 | 69.45 | 81.16 | 69.23 | 3.30 | 3.17 | 4.55 | 6.87 | 2.0 | 0.797 |
2027 | 70.84 | 82.78 | 70.61 | 3.37 | 3.23 | 4.64 | 6.76 | 2.0 | 0.797 |
Thereafter Escalation rate of 2.0%
Notes:
(1) | The forecast McCully gas price is used by GLJ in calculating the net present value of Headwater's future natural gas net revenues from the McCully field. The McCully gas price is determined by adjusting the forecast AGT gas prices to reflect the expected premiums received at Headwater's delivery point, transportation costs, as applicable, heat content and marketing conditions. The McCully gas price in years 2022 – 2023 reflects only the winter producing months (January to April and November to December) or correlate to the intermittent production strategy employed by the Company to capture seasonal premium pricing. After 2023, the GLJ Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year. |
(2) | The exchange rate used to generate the benchmark reference prices in this table. |
(3) | As at |
The company continues to grow significantly while spending less than our cash flow. As the business strategy continues to evolve, there will be an increased focus on returning excess free cash flow to shareholders. While it is early, Headwater looks forward to providing clarity on these elements over the next 9 months.
Headwater's guiding principles of shareholder value creation, sustainability, asset development with an emphasis on environmental, social, and governance goals, and maintaining a pristine balance sheet continue to be unwavering.
Additional corporate information can be found in our corporate presentation on our website at www.headwaterexp.com
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words "guidance", "initial, "anticipate", "scheduled", "can", "will", "prior to", "estimate", "believe", "potential", "should", "unaudited", "forecast", "future", "continue", "may", "expect", "project", and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation, the expectation that first quarter program in the core area will see an additional 6 4-leg horizontal injection wells; the timing of commissioning the water injection facility; the expectation that an additional 18 injection wells to be placed on injection prior to
The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2022 has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results.
BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term "boe" (or barrels of oil equivalent) and "Mcf" (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.
INITIAL PRODUCTION RATES: References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. All IP rates presented herein represent the results from wells after all "load" fluids (used in well completion stimulation) have been recovered. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.
NON-GAAP AND OTHER FINANCIAL MEASURES
In this press release, we refer to certain financial measures (such as total sales, net of blending, adjusted net income, capital expenditures and free cash flow) which do not have any standardized meaning prescribed by IFRS. Our determinations of these measures may not be comparable with calculations of similar measures for other issuers. In addition, this press release contains the terms adjusted funds flow from operations and adjusted working capital, which are considered capital management measures.
Non-GAAP Financial Measures
Total sales, net of blending
Management utilizes sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the annual financial statements blending expense is recorded within blending and transportation expense.
Three months ended |
Year ended | ||||
2021 | 2020 | 2021 | 2020 | ||
(thousands of dollars) | (thousands of dollars) | ||||
Total sales | 75,287 | 6,626 | 190,940 | 9,499 | |
Blending expense | (5,162) | (343) | (11,423) | (343) | |
Total sales, net of blending expense | 70,125 | 6,283 | 179,517 | 9,156 |
Adjusted Net Income
Adjusted net income is a non-GAAP financial measure which management utilizes to present a measure of financial performance that is more comparable over periods. It is calculated by adding the remeasurement loss on warrant liability associated with the Cenovus Warrants to net income.
Three months ended |
Year ended | ||||
2021 | 2020 | 2021 | 2020 | ||
(thousands of dollars) | (thousands of dollars) | ||||
Net income | 27,927 | 16,919 | 45,828 | 6,707 | |
Remeasurement loss on warrant liability | 4,669 | 4,289 | 32,599 | 4,289 | |
Adjusted net income | 32,596 | 21,208 | 78,427 | 10,996 |
Capital expenditures
Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – exploration and evaluation and capital expenditures – property, plant and equipment in the statement of cash flows in the Company's audited annual financial statements.
Three months ended |
Year ended | ||||
2021 | 2020 | 2021 | 2020 | ||
(thousands of dollars) | (thousands of dollars) | ||||
Cash flows used in investing activities | 47,047 | 34,374 | 109,127 | 34,404 | |
Property acquisition | - | (32,781) | - | (32,781) | |
Restricted cash | 1,248 | (1,477) | 1,477 | (797) | |
Change in non-cash working capital | 748 | 1,632 | 29,785 | 1,451 | |
Capital expenditures | 49,043 | 1,748 | 140,389 | 2,277 | |
Property acquisition | - | 135,297 | - | 135,297 | |
Capital expenditures including acquisition | 49,043 | 137,045 | 140,389 | 137,574 |
Free cash flow
Management uses free cash flow for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund its future growth expenditures. Free cash flow is defined as adjusted funds flow from operations less capital expenditures. The most directly comparable GAAP measure for free cash flow is cash flows provided by operating activities.
Capital Management Measures
Adjusted Funds Flow from Operations
Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. In addition to being a capital management measure, adjusted funds flow from operations is used by management to assess the performance of the Company's oil and gas properties. Adjusted funds flow from operations is an indicator of operating performance as it varies in response to production levels and management of production and transportation costs. Management believes that by eliminating changes in non-cash working capital and transaction costs, adjusted funds flow from operations is a useful measure of operating performance. Management removes transaction costs as these costs relate to acquisitions/dispositions and not the operations of the underlying properties.
Three months ended |
Year ended, | |||
2021 | 2020 | 2021 | 2020 | |
(thousands of dollars) | (thousands of dollars) | |||
Cash flows provided by operating activities | 47,753 | (1,451) | 111,656 | 230 |
Changes in non–cash working capital | 978 | 3,319 | 6,260 | 1,222 |
Transaction costs | - | 2,948 | - | 7,330 |
Adjusted funds flow from operations | 48,731 | 4,816 | 117,916 | 8,782 |
Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity.
Year ended | ||
2021 | 2020 | |
(thousands of dollars) | ||
Working capital | 89,775 | 70,528 |
Financial derivative receivable | (770) | (74) |
Financial derivative liability | 3,924 | - |
Warrant liability | - | 10,305 |
Adjusted working capital | 92,929 | 80,759 |
Non-GAAP Ratios
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives
Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period.
Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Operating netback, including financial derivatives is defined as operating netback plus realized gains on financial derivatives.
Adjusted funds flow per share and adjusted net income per share
Adjusted funds flow per share and adjusted net income per share are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share and adjusted net income per share are calculated as adjusted funds flow from operations or adjusted net income divided by weighted average shares outstanding on a basic or diluted basis.
F&D costs per boe
F&D costs is used as a measure of capital efficiency. The F&D cost calculation includes all capital expenditure (exploration and development) for that period plus the change in future development capital ("FDC") for that period based on the evaluations completed by GLJ as at
Recycle ratio
Recycle ratio is used as a measure of profitability. Recycle ratio is calculated as the Company's operating netback including financial derivatives divided by F&D costs per boe.
Per boe numbers
This press release represents various results on a per boe basis including Headwater average realized sales price, net of blending, financial derivatives gains (losses) per boe, royalty expense per boe, transportation expense per boe, production expense per boe, general and administrative expenses per boe, interest income and other expense per boe. These figures are calculated using sales volumes.
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