CALGARY, AB, March 10, 2022 /CNW/ - Headwater Exploration Inc.
(the "Company" or "Headwater") (TSX: HWX)
announces its operating and financial results for the
three months and year ended December 31, 2021. Selected financial and
operational information is outlined below and should be read in
conjunction with the audited financial statements and
the related management's discussion and analysis
("MD&A"). These filings will be available at
www.sedar.com and the Company's website at www.headwaterexp.com. In
addition, readers are also directed to the Company's Annual
Information Form for the year ended December
31, 2021, dated March 10,
2022, filed on SEDAR at www.sedar.com.
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
Crude
40o API
($Cdn/Bbl)
|
WCS
Crude Oil
Stream
Quality at
Hardisty
($Cdn/Bbl)
|
NYMEX
Henry Hub
($US/
MMBtu)
|
Natural Gas
AECO-C
Spot
($Cdn/
MMBtu)
|
Algonquin
City Gates
Natural Gas
($US/MMBtu)
|
McCully
Gas
Price(1)
($Cdn/Mcf)
|
Inflation
Rates
%/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
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 July 1,
2022; the expectation to have 35 4-leg horizontal injection
wells on injection by year end representing approximately 45% of
our core area under waterflood; the belief that Headwater has
discovered an approximate 25km long hydrocarbon accumulation
containing 65 sections of Headwater land; the expectation that 9
injectors will be placed on injection prior to the end of April;
the belief that the two successful tests in the Marten Hills
West play extension validated a significant, medium-grade oil
charged fairway in the Clearwater A sandstone; the intent that
Headwater will continue to delineate this fairway throughout the
back half of the year to quantify the extent and quality of the
discovered accumulation; Headwater's intent to continue the
Company's previous strategy of production optimization of the
McCully gas field in New
Brunswick; the expectation that production from the McCully
field will be shut-in May 1 to take
advantage of premium gas pricing; expected free cash flow
generation; and 2022 guidance related to expected average daily
production, capital expenditures, cash flow from operating
activities, adjusted funds flow from operations, exit working
capital and exit adjusted working capital. The forward-looking
statements contained herein are based on certain key expectations
and assumptions made by the Company, including but not limited to
expectations and assumptions concerning the success of optimization
and efficiency improvement projects, the availability of capital,
current legislation, receipt of required regulatory approval, the
success of future drilling, development and waterflooding
activities, the performance of existing wells, the performance of
new wells, Headwater's growth strategy, general economic
conditions, availability of required equipment and services,
prevailing equipment and services costs, prevailing commodity
prices and certain other guidance assumptions as detailed in the
MD&A available on SEDAR at www.sedar.com. Although the Company
believes that the expectations and assumptions on which the
forward-looking statements are based are reasonable, undue reliance
should not be placed on the forward-looking statements because the
Company can give no assurance that they will prove to be correct.
Since forward-looking statements address future events and
conditions, by their very nature they involve inherent risks and
uncertainties. Actual results could differ materially from those
currently anticipated due to a number of factors and risks. These
include, but are not limited to, risks associated with the oil and
gas industry in general (e.g., operational risks in development,
exploration and production; disruptions to the Canadian and global
economy resulting from major public health events, including the
COVID-19 pandemic, war, terrorist events, political upheavals and
other similar events; events impacting the supply and demand for
oil and gas including the COVID-19 pandemic and actions taken by
the OPEC + group; delays or changes in plans with respect to
exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and
projections relating to production, costs and expenses, and health,
safety and environmental risks), commodity price and exchange rate
fluctuations, changes in legislation affecting the oil and gas
industry and uncertainties resulting from potential delays or
changes in plans with respect to exploration or development
projects or capital expenditures. Refer to Headwater's most recent
Annual Information Form dated March 10,
2022, on SEDAR at www.sedar.com, and the risk factors
contained therein.
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
December 31,
|
|
Year ended
December
31,
|
|
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
December 31,
|
|
Year ended
December
31,
|
|
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
December 31,
|
|
Year ended
December
31,
|
|
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
December
31,
|
Year
ended,
December
31,
|
|
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
Adjusted working capital is a capital management measure
which management uses to assess the Company's liquidity.
|
Year ended December
31,
|
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 December
31, 2020 as compared to December 31,
2021. This total capital including the change in the FDC is
then divided by the change in reserves for that period
incorporating all revisions and production for that same
period. Total proved F&D is calculated as
follows = ($140.4 million (2021
capital expenditures) + $40.7 million
(change in FDC associated with proved reserves)) / (15,663 mboe –
9,495 mboe +2,699 mboe) = $20.43 per
boe. Total proved plus probable F&D is calculated as follows =
($140.4 million (2021 capital
expenditures) + $46.3 million (change
in FDC associated with proved plus probable reserves)) / (23,790
mboe – 13,080 mboe +2,699 mboe) = $13.92 per boe.
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.
SOURCE Headwater Exploration Inc.