CALGARY, AB, May 12, 2021 /CNW/ - Headwater Exploration
Inc. (the "Company" or "Headwater") (TSX: HWX) is
pleased to announce increased guidance and its operating
and financial results for the three months ended March 31, 2021. Selected financial and
operational information is outlined below and should be read in
conjunction with the unaudited interim condensed 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
March 31,
|
|
2021
|
2020
|
Financial
(thousands of dollars except share data)
|
|
|
Sales, net of
blending (1)
|
23,122
|
2,308
|
Cash flow provided by
operating activities
|
12,783
|
1,182
|
Per share - basic
|
0.07
|
0.01
|
- diluted
|
0.07
|
0.01
|
Adjusted funds flow
from operations (2)
|
14,479
|
5,413
|
Per share - basic
|
0.07
|
0.05
|
- diluted
|
0.07
|
0.05
|
Net loss
|
(12,793)
|
(6,810)
|
Per share - basic
|
(0.07)
|
(0.06)
|
- diluted
|
(0.07)
|
(0.06)
|
Adjusted net income
(loss) (2)
|
6,402
|
(6,810)
|
Per share - basic
|
0.03
|
(0.06)
|
- diluted
|
0.03
|
(0.06)
|
Development capital
expenditures
|
37,272
|
70
|
Adjusted working
capital (2)
|
58,367
|
114,200
|
Shareholders'
equity
|
257,461
|
157,235
|
Weighted average
shares (thousands)
|
|
|
Basic
|
195,322
|
105,436
|
Diluted
|
195,322
|
105,436
|
Shares outstanding,
end of period (thousands)
|
|
|
Basic
|
195,574
|
144,327
|
Diluted
(5)
|
240,456
|
145,552
|
Operating
(6:1 boe conversion)
|
|
|
|
|
|
Average daily
production
|
|
|
Heavy crude
oil (bbls/d)
|
3,385
|
-
|
Natural gas
(MMcf/d)
|
8.5
|
8.9
|
Natural gas
liquids (bbls/d)
|
5
|
7
|
Barrels of oil
equivalent (3) (boe/d)
|
4,805
|
1,487
|
|
|
|
Average daily sales
(6) (boe/d)
|
4,768
|
1,487
|
|
|
|
Netbacks
($/boe) (7)
|
|
|
Operating
|
|
|
Sales, net of blending
(1)
|
53.89
|
17.06
|
Royalties
|
(5.49)
|
(0.42)
|
Transportation
(1)
|
(6.04)
|
-
|
Production
expense
|
(5.62)
|
(4.78)
|
|
|
|
Field netback
(2)
|
36.74
|
11.86
|
Realized gain (loss) on
financial derivatives
|
(1.28)
|
29.09
|
Operating
netback (2)
|
35.46
|
40.95
|
General and administrative
expense
|
(1.97)
|
(5.05)
|
Interest income and other
(4)
|
0.26
|
4.10
|
Adjusted funds
flow netback (2)
|
33.75
|
40.00
|
(1) 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 condensed financial statements blending
is recorded within blending and transportation
expense.
|
(2) See "Non-IFRS"
measures.
|
(3) See '"Barrels
of Oil Equivalent."
|
(4) Excludes
accretion on decommissioning liabilities and interest on lease
liability.
|
(5) Includes
in-the-money dilutive instruments as at March 31, 2021 which
include 8.6 million stock options with a weighted average exercise
price of $1.44, 21.3 million warrants issued pursuant to the
recapitalization transaction with an exercise price of $0.92 and 15
million warrants with an exercise price of $2.00.
|
(6) Includes sales
of unblended heavy crude oil, natural gas and natural gas liquids.
The Company's heavy crude oil sales and production volumes differ
due to changes in inventory.
|
(7) Netbacks are
calculated using average sales volumes.
|
FIRST QUARTER 2021 HIGHLIGHTS
- Generated average production of 4,805 boe/d representing an
increase of 192% over the fourth quarter of 2020.
- Achieved adjusted funds flow from operations of $14.5 million ($0.07 per share basic), representing an increase
of 201% over the fourth quarter of 2020.
- Achieved an operating netback of $35.46/boe and an adjusted funds flow netback of
$33.75/boe.
- Achieved adjusted net income of $6.4
million ($0.03 per share
basic).
- Successfully executed a $37.3
million exploration and development capital program in the
Marten Hills area inclusive of drilling 12, 8-leg multi-lateral
producing wells, 5 horizontal injection wells, 2 source water wells
and 1 stratigraphic test well.
- Executed an agreement with another area operator to construct a
joint gas processing facility. The facility is currently under
construction and is on track to be commissioned by early
July 2021. This facility will allow
Headwater to achieve gas conservation from production in the core
area of Marten Hills.
- The Company's McCully asset performed strongly throughout the
quarter contributing $5.0 million in
operating cash flow. Consistent with prior years and to optimize
cash flow, Headwater shut-in production May
1, 2021, to await next winter's premium pricing season.
Approximately 40% of next winter's volumes are hedged at an average
price of US$7.39/mmbtu.
- As at March 31, 2021, Headwater
had adjusted working capital of $58.4
million with no outstanding debt.
Operations Update
Marten Hills Core Area Development
During the first quarter, Headwater drilled 12 producing 8-leg
horizontal wells. Numerous drilling strategies were tested
including changes to drilling mud systems, drill bit design,
strategies to improve steering, and techniques to increase
penetration rates. Tracer surveys were conducted on several
of the producing wells to understand relative contribution from
each lateral.
The different strategies employed resulted in a larger
variability in the peak 30-day average production per well ("IP
30") than initially anticipated. The IP 30's varied from 205
- 720 bbls/d of oil. A summary of results by section is as
follows:
Section
|
April
Producing
bbls/d per 8-leg
Well
|
Oil
Quality
Degree API
|
# of Laterals
Drilled
|
Production per
Lateral bbls/d
|
26-74-25W4
|
420
|
19
|
32
|
34 - 88
|
23-74-25W4
|
295
|
18
|
16
|
25 - 49
|
35-74-25W4
|
308
|
19
|
16
|
32 - 45
|
27-74-25W4
|
248
|
18
|
32
|
20 - 44
|
The combined learnings from the different drilling strategies
employed provide technical clarity and confidence going forward.
These will allow Headwater to improve production per lateral
during the next phase of planned drilling operations and provide
greater certainty on expected returns on capital deployed.
Enhanced Oil Recovery
Headwater commenced water injection into the 4-leg horizontal
injector, 02/16-35-74-25W4, on April
15, 2021. Headwater initially limited the injection
rate to 400 bbls/d and has since increased this to 600 bbls/d.
Based on early indications, this well appears to have
injection capacity in excess of 1,000 bbls/d. This is very
encouraging for full field waterflood implementation, as
injectability into the lower portion of the reservoir has been
validated. Source well deliverability is also confirmed with two
successful source well tests completed in the first quarter.
These results represent key milestones in moving towards full scale
waterflood implementation.
Exploration Update
Headwater is rapidly moving towards the licensing of eight
exploration wells in two prospect areas of Marten Hills. The
current budget contemplates drilling four of these tests with a
start date in mid-August. Once success is confirmed on the
prospects, Headwater will return and drill the remaining four
additional delineation wells on these prospects in the fourth
quarter of 2021.
Multiple additional exploration prospects in the Clearwater and other formations have been
identified throughout our land base. The current plan
contemplates drilling three to five additional exploration
prospects by the end of the first quarter of 2022.
Gas Conservation
Facility construction on the joint gas processing facility
continues with expected commissioning in early July 2021. This facility will allow
Headwater to achieve gas conservation from all production in the
core development area of Marten Hills.
Guidance Increase
At the end of the first quarter Headwater took steps to prepare
for an earlier restart of drilling activities by placing rig mats
on three of our existing padsites. The pads have held
together very well during the second quarter, resulting in
Headwater being optimistic that drilling operations will recommence
by early July.
As a result of the success achieved to date, the Board of
Directors of Headwater has approved an increase to the Company's
2021 capital expenditure budget and associated production guidance
as follows:
|
Previous
|
Revised
|
Annual average daily
production (boe/d)
|
6,500 -
7,000
|
7,000 -
7,250
|
Fourth quarter 2021
daily production (boe/d)
|
8,000 -
8,500
|
9,000 -
9,500
|
Capital expenditures
($millions)
|
90 - 95
|
105 - 110
|
Exit adjusted working
capital ($millions)
|
80
|
60
|
The revised budget contemplates that three drilling rigs are
expected to spud in early July. The three drilling rigs will
initially drill within the core development area. Once access
is available into Headwater's exploration lands, one of the rigs
will be re-deployed to drill exploration tests in mid-August.
Outlook
Headwater has had an exceptional start to 2021, with the
successful execution of the Company's inaugural $37 million capital program. Production
from the marquee Clearwater assets
acquired from Cenovus in December
2020 has more than doubled, with significant per share
growth on the horizon.
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 and 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 revised 2021 guidance including
expected 2021 annual average production, fourth quarter 2021
average production, expected 2021 capital expenditures and
estimated exit adjusted working capital; the expectation that
Headwater's learnings from its first quarter 2021 results will
provide improvements in production per lateral during the next
phase of drilling operations and provide greater certainty on
expected returns on capital deployed; the expectation that
Headwater's 4-leg horizontal injection has injection capacity in
excess of 1,000 bbls/d; expectation of water source availability
for waterflood operations; the expectation that the gas plant will
be commissioned by early July and gas conservation will be
achieved; expected timing to license and drill certain exploration
wells; the expectation of significant per share growth; the
expectation to restart drilling operations by early July 2021. 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 and prevailing commodity
prices. 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,
2021, 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 2021
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 2021 guidance
include: WTI US$62.00/bbl, WCS
Cdn$61.75/bbl, AGT US$4.56/mmbtu and a foreign exchange rate of
US$/Cdn$ of 0.81.
NON-IFRS MEASURES: This document contains the terms "adjusted
funds flow from operations", "adjusted net income", "adjusted
working capital", "operating cash flow", "field netback",
"operating netback", and "adjusted funds flow netback", which do
not have standardized meanings prescribed by International
Financial Reporting Standards ("IFRS") and therefore may not be
comparable with the calculation of similar measures by other
companies. Management uses adjusted funds flow from operations to
analyze operating performance and leverage. Adjusted funds flow
from operations is calculated as cash flow provided by (used in)
operating activities before changes in non-cash working capital and
adding back transaction costs. Management uses adjusted net
income to assess financial performance that is more comparable
between periods and is calculated as net income or loss before the
remeasurement loss of the warrant liability. Adjusted working
capital is used by the Company to measure liquidity. Adjusted
working capital is defined as working capital excluding the effects
of the Company's financial derivatives and warrant liability.
Management uses operating cash flow as a measure of the company's
efficiency and its ability to fund future capital expenditures and
is calculated as sales received after royalties, production,
blending and transportation costs and realized gains (losses) on
financial derivatives. Management believes "field netback",
"operating netback" and "adjusted funds flow netback" are useful
supplemental measures to consider the profitability of the
Company's operations on a per unit basis using unblended sales
volumes and have been calculated in respect of field netback by
taking the amount of sales received after royalties and production
and blending and transportation costs, in respect of operating
netback by taking the amount of sales received after royalties,
production, blending and transportation costs and realized gains
(losses) on financial derivatives, and in respect of adjusted funds
flow netback by taking the amount of sales received after
royalties, production, blending and transportation costs, realized
gains (losses) on financial derivatives, general and administrative
costs, interest income and other (excluding accretion on
decommissioning liabilities) and decommissioning liabilities
settled. Additional information relating to certain of these
non-IFRS measures, including the reconciliation of cash flow from
operating activities to adjusted funds from operations, net income
or loss to adjusted net income or loss, working capital to adjusted
working capital, and sales to operating cash flow can be found in
the MD&A.
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
initial production 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. Additionally, such
rates may also include recovered "load oil" fluids used in well
completion stimulation. While encouraging, readers are cautioned
not to place reliance on such rates in calculating the aggregate
production for the Company. A pressure transient analysis or
well-test interpretation has not been carried out in respect of all
wells. Accordingly, the Company cautions that the test results
should be considered to be preliminary.
SOURCE Headwater Exploration Inc.