Financial and Operating Highlights
Three months ended December 31, |
Year ended December 31, |
||||
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 December 31, 2021 which include 9.4 million stock options with a weighted average exercise price of $2.33 and 15.4 million warrants issued pursuant to the recapitalization transaction in March 2020 with an exercise price of $0.92. |
(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) program in the Marten 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 to December 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 capital of $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) program in 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
Marten Hills Core Area Development
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 March 5, 2022, Headwater’s oil processing facility was fully commissioned resulting in a $4.00/bbl reduction to transportation costs. Commissioning of the water injection facilities is ongoing with 3 wells currently on injection and an additional 18 injection wells to be placed on injection prior to July 1, 2022.
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 April 2022. By year-end we anticipate having greater than 35 4-leg horizontal injection wells on injection, representing approximately 45% of our core area under waterflood.
Exploration Update
Since our last update to shareholders on February 1, 2022, we have successfully placed 2 exploration wells on production (15-29 and 16-27), testing the southern and eastern extents of the Clearwater A fairway. The Headwater team is extremely pleased with the results of our exploration efforts in Marten Hills West and believe we have discovered an approximate 25km long hydrocarbon accumulation containing approximately 65 sections of Headwater land.
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 February 27, 2022 and is currently producing 50 bbls/d of 18 degree API oil. Although the results are not as prolific as the initial discovery wells, the Marten Hills West play extension validated by these two successful tests provides confidence in a significant, medium-grade oil charged fairway in the Clearwater A sandstone. An additional western extension well has been drilled and placed on production at 02/08-34-075-03W5. It is currently recovering load fluid with IP30 rates expected by the middle of April 2022. Headwater is continuing to delineate this fairway with 4 additional Clearwater A wells expected to be drilled prior to quarter end. The 11-05 and 13-07 wells drilled in the fourth quarter of 2021 continue to perform exceptionally well with 60-day IP (“IP60”) rates of 225 bbls/d and 215 bbls/d respectively.
A second test in the Clearwater B at 00/09-34-075-03W5 was rig released on Feb 19, 2022. This well, immediately to the north of the initial discovery well, 00/08-34-075-03W5, finished recovering load fluid on March 9, 2022. Current rates for 09-34 are highly encouraging at greater than 200 bbls/d of oil. The 08-34 well drilled in the fourth quarter of 2021 has achieved an IP60 rate of 149 bbls/d. These results in conjunction with other area operators results, in the same zone, confirm a 15-section prolific hydrocarbon accumulation on Headwater lands.
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 May 1, 2022, when it will be shut-in to await next winter’s premium pricing season. Based on field receipts to date, the McCully field is expected to generate approximately $9 million of free cash flow (1) during the first quarter of 2022.
(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 $259 million and exit adjusted working capital (1) of $207 million. Headwater is maintaining capital expenditures (2) for 2022 at $145 million with 2022 production at 12,500 boe/d (11,500 bbls/d of heavy oil and 6.2 mmcf/d of natural gas), as previously released.
(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 US$88.00/bbl, WCS Cdn$97.00/bbl, FX 0.79, AGT US$14.19/mmbtu |
2021 Reserve Information
Headwater currently has heavy oil reserves located in the Marten Hills area of Alberta and natural gas reserves in the McCully Field near Sussex, New Brunswick. GLJ Ltd. (“GLJ“) assessed the Company’s reserves in its report dated effective December 31, 2021 (“GLJ Report“) which was prepared in accordance with standards of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and is based on the average forecast prices as at December 31, 2021 of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information is included in Headwater’s Annual Information Form for the year ended December 31, 2021, filed on SEDAR on March 10, 2022.
The following tables are a summary of Headwater’s petroleum and natural gas reserves, as evaluated by GLJ, effective December 31, 2021. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates provided herein. Reserves information may not add due to rounding.
Reserves Summary
Heavy |
Shale |
Conventional |
Oil |
||
Oil |
Gas |
Gas |
NGL |
Equivalent |
|
Mbbls |
MMcf |
MMcf |
Mbbls |
MBOE |
|
Proved developed producing |
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 GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2022. |
(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 GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited price forecasts effective as at January 1, 2022. |
(2) |
All future net revenues are stated prior to provision for interest income and other, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures. |
(3) |
After-income tax net present value of future net revenue are based on Headwater’s estimated tax pools as at December 31, 2021. The after-income tax net present value of Headwater’s oil and natural gas properties reflects the income tax burden on the properties on a stand-alone basis and takes into account Headwater’s existing tax pools. It does not consider tax planning. |
Future Development Costs (“FDC”)
The following is a summary of the estimated FDC required to bring proved undeveloped reserves and proved plus probable undeveloped reserves on production.
Proved Reserves $MM |
Proved Plus Probable Reserves $MM |
|
2022 |
66,150 |
70,350 |
2023 |
19,806 |
21,211 |
Thereafter (1) |
2,661 |
2,768 |
Total Undiscounted |
88,616 |
94,329 |
(1) |
Future development capital after 2023 is associated with McCully gas plant optimization. |
Pricing Assumptions
The following tables set forth the benchmark reference prices, as at December 31, 2021, reflected in the GLJ Report, using the average of commodity price forecasts from GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2022, to estimate the reserves volumes and associated values in the GLJ Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2021
FORECAST PRICES AND COSTS
Year |
WTI Cushing Oklahoma ($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 December 31, 2021. |
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