CALGARY,
AB, Nov. 3, 2022 /CNW/ - Headwater Exploration
Inc. (the "Company" or "Headwater") (TSX:
HWX) is pleased to announce its inaugural quarterly cash
dividend in conjunction with its operating and financial results
for the three and nine months ended September 30, 2022 and its 2023 budget.
Growth and Return of
Capital
Headwater expects approximately 38% production per share growth
in 2023 while underspending anticipated cash flow. As a result of
continued exceptional results, Headwater's Board of Directors (the
"Board") has implemented a return of capital strategy with the
declaration of Headwater's inaugural quarterly cash dividend of
$0.10 per common share. The first
dividend will be payable on January 16,
2023, to shareholders of record at the close of business on
December 30, 2022. This dividend is
designated as an eligible dividend for Canadian income tax
purposes. The Board expects that the regular quarterly dividend can
be maintained in conjunction with our anticipated growth profile at
a long term WTI oil price of US$55/bbl. Based on Headwater's closing common
share price on November 2, 2022, of
$7.21 per share, this represents an
annual yield of approximately 5.5%.
Continued Exploration
Success
Headwater drilled a successful exploration test at
16-22-075-02W5 in Marten Hills West
which has extended our proven pool boundaries by approximately 3.5
miles. This well has achieved an average 30-day production ("IP30")
rate of 330 bbls/d of oil, providing payout in approximately 4-5
months at US$80/bbl WTI.
We also drilled two successful 1.5 mile extended reach step-out
wells in our Marten Hills core area. The 12-08-075-24W4 well has
achieved an IP30 rate of 377 bbls/d and the 11-08-075-24W4 well
will complete its 30-day initial production period mid-November.
The wells have extended our core area pool boundaries by
approximately 1.5 miles.
In our Marten Hills central area we drilled two successful pool
extension wells. The wells at 02/16-14-075-26W4 and
03/16-14-075-26W4 have confirmed our geotechnical interpretation of
this pool which covers approximately 5 sections of 100% owned
Headwater lands. These wells achieved IP30's of 130 bbls/d,
providing payout in approximately 8-9 months at US$80/bbl WTI.
Preliminary 2023 Budget
In assessing our continued success and our initial return of
capital strategy, the Board has approved an initial capital budget
for 2023 of $200 million resulting in
2023 annual average production of 18,000 boe/d (92% heavy oil).
The capital budget is expected to generate 38% production per
share growth at a reinvestment rate of 60%-70% of 2023 forecasted
adjusted funds flow from operations at US$75/bbl to US$85/bbl WTI.
At US$75/bbl to US$85/bbl WTI, Headwater forecasts 2023
adjusted funds flow from operations of $285-$330 million
and free cash flow of approximately $85-$130 million
resulting in estimated positive exit 2023 adjusted working capital
of $105-$150
million.
Selected financial and operational information is outlined below
and should be read in conjunction with the unaudited condensed
interim 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
Financial and Operating Highlights
|
Three months
ended
September
30,
|
Percent
Change
|
Nine months
ended
September
30,
|
Percent
Change
|
|
2022
|
2021
|
2022
|
2021
|
Financial
(thousands of dollars except share data)
|
|
|
|
|
|
|
Sales, net of
blending (1) (4)
|
94,949
|
48,841
|
94
|
327,073
|
109,392
|
199
|
Adjusted funds flow
from operations (2)
|
58,441
|
31,524
|
85
|
207,899
|
69,185
|
200
|
Per share - basic
|
0.25
|
0.16
|
56
|
0.92
|
0.35
|
163
|
- diluted
|
0.25
|
0.13
|
92
|
0.89
|
0.29
|
207
|
Cash flow provided by
operating activities
|
72,060
|
27,888
|
158
|
217,477
|
63,903
|
240
|
Per share - basic
|
0.31
|
0.14
|
121
|
0.96
|
0.32
|
200
|
- diluted
|
0.30
|
0.12
|
150
|
0.93
|
0.27
|
244
|
Net income
|
31,545
|
26,106
|
21
|
122,320
|
17,901
|
583
|
Per share - basic
|
0.14
|
0.13
|
8
|
0.54
|
0.09
|
500
|
- diluted
|
0.13
|
0.12
|
8
|
0.53
|
0.08
|
563
|
Capital
expenditures (1)
|
71,001
|
37,293
|
90
|
183,818
|
91,346
|
101
|
Adjusted working
capital (2)
|
|
|
|
117,967
|
63,709
|
85
|
Shareholders'
equity
|
|
|
|
525,006
|
295,528
|
78
|
Weighted average
shares (thousands)
|
|
|
|
|
|
|
Basic
|
229,909
|
202,313
|
14
|
225,794
|
198,385
|
14
|
Diluted
|
236,658
|
218,190
|
8
|
232,984
|
214,166
|
9
|
Shares outstanding, end
of period (thousands)
|
|
|
|
|
|
|
Basic
|
|
|
|
229,911
|
202,466
|
14
|
Diluted
(5)
|
|
|
|
241,593
|
240,447
|
-
|
Operating
(6:1 boe conversion)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily
production
|
|
|
|
|
|
|
Heavy crude
oil (bbls/d)
|
10,842
|
7,637
|
42
|
10,695
|
5,751
|
86
|
Natural
gas (mmcf/d)
|
4.3
|
0.3
|
1,333
|
7.2
|
3.7
|
95
|
Natural gas
liquids (bbls/d)
|
55
|
-
|
100
|
43
|
3
|
1,333
|
Barrels of oil
equivalent (9) (boe/d)
|
11,612
|
7,688
|
51
|
11,929
|
6,363
|
87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily sales
(6) (boe/d)
|
11,680
|
7,613
|
53
|
11,925
|
6,355
|
88
|
|
|
|
|
|
|
|
Netbacks
($/boe) (3) (7)
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
|
Sales, net of blending
(4)
|
88.36
|
69.73
|
27
|
100.46
|
63.05
|
59
|
Royalties
|
(21.93)
|
(10.46)
|
110
|
(20.21)
|
(8.66)
|
133
|
Transportation
|
(3.94)
|
(8.68)
|
(55)
|
(4.31)
|
(7.86)
|
(45)
|
Production
expenses
|
(5.95)
|
(4.42)
|
35
|
(5.79)
|
(4.88)
|
19
|
|
|
|
|
|
|
|
|
Operating netback
(3)
|
56.54
|
46.17
|
22
|
70.15
|
41.65
|
68
|
Realized losses on financial
derivatives
|
-
|
-
|
-
|
(1.29)
|
(0.23)
|
461
|
Operating netback,
including financial derivatives (3)
|
56.54
|
46.17
|
22
|
68.86
|
41.42
|
66
|
General and administrative
expense
|
(1.46)
|
(1.40)
|
4
|
(1.49)
|
(1.61)
|
(7)
|
Interest income and other
expense (8)
|
1.18
|
0.24
|
392
|
0.58
|
0.08
|
625
|
Current tax
expense
|
(1.87)
|
-
|
100
|
(4.09)
|
-
|
100
|
Adjusted funds
flow netback (3)
|
54.39
|
45.01
|
21
|
63.86
|
39.89
|
60
|
(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 interim financial statements blending expense is recorded
within blending and transportation expense.
|
(5)
|
In-the-money
dilutive instruments as at September 30, 2022 includes 7.2 million
stock options with a weighted average exercise price of $2.51, 3.5
million warrants issued pursuant to the recapitalization
transaction in March 2020 with an exercise price of $0.92, 0.2
million restricted share units and 0.8 million performance share
units.
|
(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. For the three months ended
September 30, 2022, sales volumes comprised of 10,910 bbs/d of
heavy oil, 4.3 mmcf/d of natural gas and 55 bbls/d of natural gas
liquids (2021- heavy oil of 7,562 bbls/d and natural gas of 0.3
mmcf/d). For the nine months ended September 30, 2022, sales
volumes comprised of 10,690 bbls/d of heavy oil, 7.2 mmcf/d of
natural gas and 43 bbls/d of natural gas liquids (2021- heavy oil
of 5,743 bbls/d, natural gas of 3.7 mmcf/d and natural gas liquids
of 3 bbls/d).
|
(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."
|
|
|
THIRD QUARTER 2022 HIGHLIGHTS
- Realized adjusted funds flow from operations (1) of
$58.4 million ($0.25 per share basic) and cash flows from
operating activities of $72.1 million
($0.31 per share basic) representing
an increase of 85% and 158%, respectively, over the third quarter
of 2021.
- Recognized net income of $31.5
million ($0.14 per share
basic) representing an increase of 21% from the third quarter of
2021.
- Achieved an operating netback (2) of $56.54/boe and an adjusted funds flow netback
(2) of $54.39/boe
representing an increase of 22% and 21%, respectively, over the
third quarter of 2021.
- Production averaged 11,612 boe/d (consisting of 10,842 bbls/d
of heavy oil, 4.3 mmcf/d of natural gas and 55 bbls/d of natural
gas liquids) representing an increase of 51% from the third quarter
of 2021.
- Executed a $71.0 million capital
expenditure (3) program including 9 successful
exploration wells in Marten Hills
West plus 8 injection wells in Marten Hills as part of
Headwater's enhanced oil recovery project.
- Added 8.25 sections of additional crown lands prospective for
Clearwater oil in the Greater
Peavine area.
- As at September 30, 2022,
Headwater had adjusted working capital (1) of
$118.0 million, working capital of
$113.4 million and no outstanding
bank debt.
(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 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.
|
Operations Update
Marten Hills West
In addition to the previously discussed successful exploration
extension well at 16-22-075-02W5, an additional 5 wells were
drilled in the Clearwater A in the third quarter of 2022. The IP30
rates on these wells have continued to exceed our expectations,
achieving average rates of >175 bbls/d of oil.
Headwater has continued to delineate the Clearwater B formation
with a total of 3 wells being drilled in the quarter. IP30 rates on
these wells have averaged 100 bbls/d of oil which is consistent
with expectations for the Clearwater B.
A pilot waterflood to assess the enhanced oil recovery potential
in the Clearwater A is contemplated for the first quarter of
2023.
Marten Hills Core
We have continued operations in the Marten Hills core area with
the development of the upper bench in section 24-074-25W4. Six
wells were drilled during the quarter with exceptional
results. On average the wells have achieved IP30 rates of
>350 bbls/d per well.
Waterflood implementation in the core area has resulted in
production stabilization of approximately 2,000 bbls/d (20% of
current core area production). The production stabilization
witnessed over the last several months is consistent with
expectations and it continues to demonstrate that enhanced oil
recovery is a viable option for the Clearwater formation that is expected to
materially increase ultimate oil recovery. Headwater plans to
continue to implement additional waterflood patterns with
expectations that all of the core area will be under waterflood by
the middle of 2024.
Greater Peavine Area
Our first exploration test, a stratigraphic test at
06-16-074-18W5 in our Shadow prospect is currently drilling.
Immediately following this well, the rig will spud our first
multi-lateral horizontal well in the same prospect area. Headwater
has one drilling rig assigned to continue drilling exploration
prospects through year end and into the first quarter of 2023. The
current schedule will see this rig drill a total of three
horizontal wells at Shadow, prior to moving to test additional
prospects at Peavine, Utikima Lake and Seal. The initial seven
exploration wells are expected to be rig released by early
February. We look forward to providing results on the
exploration program throughout the first quarter of 2023.
Since the start of the fourth quarter, Headwater has added an
additional 6 sections of land in Peavine, increasing our total land
position in the Greater Peavine area to 117.5 sections.
McCully
McCully is scheduled to be placed back on production at the end
of November. We have hedged approximately 4.3 mmcf/d representing
57% of our estimated winter season's production at a price of
Cdn$28/mcf. McCully is anticipated to
deliver record free cash flow of approximately $28 million over the winter season
(1). This asset is long-life, low decline and adds to
the sustainability of Headwater's dividend.
(1)
|
McCully's winter season
is estimated to be November 2022 to April 2023.
|
2022 Guidance Update
The Company remains on track to achieve its previously released
annual production guidance of 13,000 boe/d. Capital expenditures
for the year are now expected to be $245
million which represents an increase of approximately 6.5%
from our previously released capital budget of $230 million. The increase in the capital budget
is a result of approximately $7.5
million of additional costs associated with inflation and an
additional $7.5 million of spending
on equipment inventory and civil construction work to prepare for
an active first quarter in 2023. With the $15 million increase in capital and the declared
$23 million dividend, the forecast
exit adjusted working capital is now approximately $113 million.
|
Previous
2022 Guidance
(1)
|
Revised
2022
Guidance
|
|
|
|
2022 annual average
production (boe/d)
|
13,000
|
13,000
|
|
|
|
Capital expenditures
(2)
|
$230 million
|
$245 million
|
Adjusted funds flow
from operations (3)
|
$295 million
|
$287 million
|
Dividend
payable
|
$0 million
|
$23 million
|
Exit adjusted working
capital (3)
|
$160 million
|
$113 million
|
(1)
|
Previous guidance
released on August 4, 2022.
|
(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.
|
|
|
Credit Facility
Headwater has executed a commitment letter for a credit facility
in the amount of $100 million with a
senior lender. With the 2023 guidance as outlined, Headwater does
not intend to draw on the credit facility.
Outlook
The positive working capital balance and credit facility provide
a war chest to continue to provide Headwater the optionality to
organically expand its Clearwater
resources base, pursue accretive acquisitions and implement
additional enhanced oil recovery schemes.
2023 will be another exciting year for Headwater as it targets
38% production growth while testing material exploration potential.
Based on current strip pricing, we anticipate generating
significant free cash flow above our capital expenditures and
committed quarterly dividend which will allow the optionality to
continually increase our regular quarterly dividend and/or provide
special dividends while pursuing incremental opportunities.
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, revised 2022 and 2023 guidance related
to expected annual average production, expected reinvestment rate
in 2023, capital expenditures and the breakdown thereof, adjusted
funds flow from operations, expected dividends, free cash flow and
exit adjusted working capital; the expectation to deliver 38%
production per share growth in 2023 while underspending anticipated
cash flow; the expected timing of the inaugural quarterly dividend;
the expectation the quarterly dividend can be maintained in
conjunction with our long-term growth profile at long term WTI of
US$55/bbl; the expected timing of the
enhanced oil recovery pilot in the Clearwater A; the expectation
that waterflood implementation is expected to materially increase
ultimate oil recovery and the expectation that Headwater plans to
continue to implement additional waterflood patterns with
expectations that all of the core area will be under waterflood by
the middle of 2024; the expected drilling schedule in the Greater
Peavine area including two additional wells at Shadow and
additional prospects at Peavine, Utikima Lake and Seal, which are
all expected to be rig released by early February 2023 with the expectation that results
on the exploration program will be provided throughout the first
quarter of 2023; the expectation to re-start McCully operations in
late November 2022; the expectation
that the McCully asset will generate $28
million of free cash flow over the winter season; the
expectation that the Company will not draw on its credit facility
in 2023; the expectation that the Company's positive working
capital balance and credit facility will provide Headwater the
optionality to organically expand its Clearwater resources base, pursue accretive
acquisitions and implement additional enhanced oil recovery
schemes; and the anticipation that the Company will generate
significant free cash flow above our capital expenditures and
committed quarterly dividend which will allow the optionality to
continually increase our regular quarterly dividend and/or provide
special dividends while pursuing incremental opportunities. 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 approvals, 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
below under the heading "Future Oriented Financial
Information" as set out below. 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, the
Russian-Ukrainian war and the impact on the global economy and
commodity prices; the impacts of inflation and supply chain issues
and steps taken by central banks to curb inflation; 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.
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 and 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 revised 2022 guidance
include: WTI US$94.90/bbl, WCS
Cdn$99.90/bbl, AGT US$15.10/mmbtu, foreign exchange rate of US$/Cdn$
of 0.77, blending expense of WCS less $2.00, royalty rate of 20%, operating and
transportation costs of $10.00/boe,
financial derivatives losses of $0.40/boe, G&A and interest income and other
expense of $0.90/boe and cash taxes
of $3.90/boe. The AGT price is the
volume weighted average price for the winter producing months in
the McCully field which include January to April and November to
December. The assumptions used in the 2023 guidance include: WTI
US$75.00-US$85.00/bbl, WCS Cdn$75.00-Cdn$88.50/bbl, AGT
US$19.20/mmbtu, foreign exchange rate
of US$/Cdn$ of 0.73, blending expense of WCS less $2.00, royalty rate of 16%-18%, operating and
transportation costs of $10.50/boe,
financial derivatives losses of $0.70/boe, G&A and interest income and other
expense of $0.90/boe and cash taxes
of $6.10/boe-$8.10/boe. The AGT price is the volume weighted
average price for the winter producing months in the McCully field
which include January to April and November to December.
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 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 free cash flow, total sales, net of blending and capital
expenditures) which do not have any standardized meaning prescribed
by IFRS. Our determinations of these measures may not be comparable
with calculations of similar measures for other issuers. In
addition, this press release contains the terms adjusted funds flow
from operations and adjusted working capital, which are considered
capital management measures. The term cash flow in this press
release is equivalent to adjusted funds flow from
operations.
Non-GAAP Financial Measures
Free cash flow
Management utilizes free cash flow to assess the amount of funds
available for future capital allocation decisions. It is calculated
as adjusted funds flow from operations net of capital
expenditures.
|
Three months
ended
September
30,
|
Nine months
ended
September
30,
|
|
2022
|
2021
|
2022
|
2021
|
|
(thousands of
dollars)
|
(thousands of
dollars)
|
Adjusted funds flow
from operations
|
58,441
|
31,524
|
207,899
|
69,185
|
Capital
expenditures
|
(71,001)
|
(37,293)
|
(183,818)
|
(91,346)
|
Free cash
flow
|
(12,560)
|
(5,769)
|
24,081
|
(22,161)
|
|
|
|
|
|
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
interim financial statements blending expense is recorded within
blending and transportation expense.
|
Three months
ended
September
30,
|
Nine months
ended
September
30,
|
|
2022
|
2021
|
2022
|
2021
|
|
(thousands of
dollars)
|
(thousands of
dollars)
|
Total sales
|
99,587
|
50,123
|
349,002
|
115,653
|
Blending expense
|
(4,638)
|
(1,282)
|
(21,929)
|
(6,261)
|
Total sales, net of
blending expense
|
94,949
|
48,841
|
327,073
|
109,392
|
|
|
|
|
|
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 interim financial
statements netted by the government grant.
|
Three months
ended
September
30,
|
Nine months
ended
September
30,
|
|
2022
|
2021
|
2022
|
2021
|
|
(thousands of
dollars)
|
(thousands of
dollars)
|
Cash flows used in
investing activities
|
54,062
|
23,741
|
170,099
|
62,080
|
Proceeds from
government grant
|
1,208
|
-
|
1,208
|
-
|
Restricted
cash
|
-
|
(1,248)
|
(5,000)
|
229
|
Change in non-cash
working capital
|
15,731
|
14,800
|
20,102
|
29,037
|
Government
grant
|
-
|
-
|
(2,591)
|
-
|
Capital
expenditures
|
71,001
|
37,293
|
183,818
|
91,346
|
|
|
|
|
|
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
September
30,
|
Nine months
ended
September
30,
|
|
2022
|
2021
|
2022
|
2021
|
|
(thousands of
dollars)
|
(thousands of
dollars)
|
Cash flows provided by
operating activities
|
72,060
|
27,888
|
217,477
|
63,903
|
Changes in non–cash
working capital
|
(11,610)
|
3,636
|
3,740
|
5,282
|
Current income
taxes
|
(2,009)
|
-
|
(13,318)
|
-
|
Adjusted funds flow
from operations
|
58,441
|
31,524
|
207,899
|
69,185
|
|
|
|
|
|
Adjusted Working Capital
Adjusted working capital is a capital management measure which
management uses to assess the Company's liquidity.
|
|
|
As at
September
30,
2022
|
As at
December 31,
2021
|
|
|
|
|
|
(thousands of
dollars)
|
Working
capital
|
|
|
113,381
|
89,775
|
Contribution receivable
(long-term)
|
|
|
671
|
-
|
Repayable
contribution
|
|
|
(4,195)
|
-
|
Financial derivative
receivable
|
|
|
(711)
|
(770)
|
Financial derivative
liability
|
|
|
8,821
|
3,924
|
Adjusted working
capital
|
|
|
117,967
|
92,929
|
|
|
|
|
|
Non-GAAP Ratios
Payout
Headwater uses this ratio to evaluate is operational performance
and capital allocation processes. Payout is calculated as the time
at which a well or project's cumulative operating netback equals
total capital expenditures.
Reinvestment Rate
Management believes the reinvestment rate is a useful measure to
analyze the ratio of funds generated by the Company and used for
reinvestment. Reinvestment rate is calculated as capital
expenditures divided by adjusted funds flow from operations.
Adjusted funds flow netback, operating netback and operating
netback, including financial derivatives
Adjusted funds flow netback, operating netback and operating
netback, including financial derivatives are non-GAAP ratios and
are used by management to better analyze the Company's performance
against prior periods on a more comparable basis. Adjusted funds
flow netback is defined as adjusted funds flow from operations
divided by sales volumes in the period.
Operating netback is defined as sales less royalties,
transportation and blending costs and production expense divided by
sales volumes in the period. The sales price, transportation and
blending costs, and sales volumes exclude the impact of purchased
condensate. Operating netback, including financial derivatives is
defined as operating netback plus realized gains or losses on
financial derivatives.
Adjusted funds flow per share
Adjusted funds flow per share is a non-GAAP ratio and is used by
management to better analyze the Company's performance against
prior periods on a more comparable basis. Adjusted funds flow per
share is calculated as adjusted funds flow from operations divided
by weighted average shares outstanding on a basic or diluted
basis.
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 Headwater Exploration Inc.