CALGARY, AB, March 24, 2022 /CNW/ - Kiwetinohk Energy
Corp. (TSX: KEC) today announced its 2021 annual results that
include record adjusted funds flow from operations, transformative
acquisitions providing strong netbacks and recycle ratios,
significant growth in reserves per share and an attractive return
on average capital employed for shareholders. In addition, the
Company reported year-end reserves information, filed its 2021
Annual Information Form (AIF) and announced its intention to file a
base shelf prospectus to improve its access to capital as the
Company continues to evaluate opportunities including potential
acquisitions, acceleration of development programs or general
corporate purposes.
"Kiwetinohk significantly increased its production and reserves
in 2021 through counter-cyclic acquisitions and is also seeing the
early results of a successful winter drilling program," said CEO
Pat Carlson. "As we position the
Company within the energy transition, the Green Energy team also
delivered excellent progress on its power development portfolio,
hitting key project development and regulatory approval process
milestones on our first solar and high-efficiency natural gas-fired
power projects.
The high-quality upstream resources we have now accumulated
underpin the further advancement of our energy transition strategy.
Integration of natural gas with gas-fired power and carbon capture,
utilization and storage (CCUS) coupled with renewable power will
allow us to deliver clean, reliable and dispatchable energy that is
low cost for consumers and profitable for Kiwetinohk and our
shareholders. Kiwetinohk is developing future markets for natural
gas production where we will be able to track and capture
emissions, eliminating Scope 3 emissions in the process."
Q4 2021 and 2021 Year-End Highlights
- Successfully completed the Simonette Acquisition and
amalgamation of Distinction Energy Corp. (Distinction) during the
year resulting in significantly increased production compared to
the prior year.
-
- Production volumes averaged 12,422 boe/d and 9,801 boe/d during
the quarter and year ended December 31,
2021, respectively.
- During the year, the Company acquired 34.4 million boe of
Proved Developed Producing1 (PDP) reserves based on
updated independent year-end reserves estimates, representing a
significant increase over 2020 year-end PDP reserves of 0.9 million
boe.
-
- The additional PDP reserves were acquired for $11.72/boe delivering a strong recycle
ratio2 of 3.5x based on fourth quarter 2021 operating
netbacks.
- The Company also increased Proved and Proved plus Probable
reserve volumes by 248% and 274% to 106.2 MMboe and 180.2 MMboe,
respectively, or reserve volumes per share by 50% and 62% to 2.4
and 4.2 boe per share, respectively.
- Kiwetinohk generated record adjusted funds flow from
operations3 for the quarter and year ended December 31, 2021 of $30.8
million and $69.8 million,
respectively, due to successful acquisitions and improved commodity
prices.
-
- Capital investment activity provided an attractive return on
average capital employed for the year of 25% demonstrating the
value of the transactions.
- Kiwetinohk filled 100% of its Alliance pipeline capacity of
103.0 MMcf/d (after temporary assignments) during the fourth
quarter of 2021 with production and purchased gas volumes.
-
- Natural gas marketing activities resulted in realized net
marketing income of $2.9 million
during the fourth quarter of 2021 and $6.8
million for the year ended December
31, 2021 before settlements of risk management
contracts.
- The Company invested $32.0
million and $50.9 million in
capital expenditures (excluding acquisitions) for the quarter and
year ended December 31, 2021 as it
initiated its drilling program in its Fox
Creek core area.
-
- The expenditures included the drilling and completion
expenditures related to two Duvernay wells in the Simonette area and two
Montney wells in the Placid area
and a vertical test to evaluate the Middle Montney during the
fourth quarter of 2021.
- During the year the Company made significant development
progress across its 1,800 MW power development portfolio.
-
- Kiwetinohk advanced work in the AESO staging process to secure
grid access with 4 of 5 projects progressing in Stage 2.
- With stakeholder consultation near completion and a favorable
Alberta Environment and Parks (AEP) referral letter received on
March 21, the Company is targeting an
Alberta Utilities Commission (AUC) submission for the 400 MW Solar
1 project in the second quarter 2022.
- The Company is also targeting to submit AUC and AEP industrial
applications for the 101 MW Firm Renewable 1 project in the second
quarter 2022.
- On December 13, 2021, the
Company's $225.0 million Senior
Secured Extendible Revolving Facility (Credit Facility) was
increased to $315.0 million.
-
- Available borrowing capacity on the Credit Facility at
December 31, 2021 was $228.0 million.
_________________________________________
1
|
Oil and natural gas
reserves are as determined by the Company's independent qualified
reserve evaluator with an effective date of December 31 for the
year shown in accordance with the Canadian Oil and Gas Evaluation
Handbook and are shown as net working interest reserves before
royalties.
|
2
|
Recycle ratio is
calculated as operating netback on a per boe basis divided by the
costs of acquisitions over estimated PDP reserves. Recycle ratio is
used by the Company as a key measure of profitability and the
Company's ability to generate cash flows over the cost of produced
barrels.
|
3
|
Non-GAAP measure that
does not have any standardized meaning under IFRS and therefore may
not be comparable to similar measures presented by other entities.
Please refer to the Corporation's MD&A as at and for the three
and twelve months ended December 31, 2021 under the section
"Non-GAAP Measures" available on Kiwetinohk's SEDAR profile at
www.sedar.com.
|
Financial and
operating results
|
|
|
|
|
|
|
|
Q4
2021
|
Q4
2020
|
2021
|
2020
|
Production
|
|
|
|
|
|
Condensate
(bbl/d)
|
|
3,092
|
13
|
2,644
|
35
|
Light oil
(bbl/d)
|
|
844
|
374
|
457
|
429
|
Heavy oil
(bbl/d)
|
|
13
|
43
|
29
|
15
|
NGLs (bbl/d)
|
|
1,572
|
41
|
1,180
|
64
|
Natural gas
(Mcf/d)
|
|
41,410
|
1,045
|
32,942
|
1,367
|
Total
(boe/d)
|
|
12,442
|
645
|
9,801
|
771
|
Oil and condensate % of
production
|
|
32%
|
67%
|
32%
|
62%
|
NGL % of
production
|
|
13%
|
6%
|
12%
|
8%
|
Natural gas % of
production
|
|
55%
|
27%
|
56%
|
30%
|
Realized
prices
|
|
|
|
|
|
Condensate
($/bbl)
|
|
99.21
|
55.56
|
84.94
|
55.47
|
Light oil
($/bbl))
|
|
92.29
|
48.57
|
82.46
|
48.13
|
Heavy oil
($/bbl)
|
|
81.60
|
35.58
|
59.22
|
34.40
|
NGLs ($/bbl)
|
|
65.61
|
14.04
|
52.60
|
7.09
|
Natural gas
($/Mcf)
|
|
6.64
|
2.66
|
5.29
|
2.28
|
Total
($/boe)
|
|
61.48
|
36.83
|
51.06
|
34.60
|
Royalty recovery
(expense) ($/boe)
|
|
(6.80)
|
1.57
|
(5.46)
|
(2.14)
|
Operating expenses
($/boe)
|
|
(8.28)
|
(9.94)
|
(8.18)
|
(9.66)
|
Transportation expenses
($/boe)
|
|
(5.20)
|
(1.06)
|
(5.09)
|
(0.80)
|
Operating netback
1 ($/boe)
|
|
41.20
|
27.40
|
32.33
|
22.00
|
Marketing income
($/boe)
|
|
2.50
|
-
|
1.91
|
-
|
Realized loss on risk
management contracts ($/boe) 5
|
|
(11.86)
|
-
|
(10.15)
|
-
|
Adjusted operating
netback 1
|
|
31.84
|
27.40
|
24.09
|
22.00
|
Financial
results ($000s, except per share amounts)
|
|
|
|
|
|
Commodity sales from
production
|
|
70,267
|
2,186
|
182,668
|
9,758
|
Net marketing income
(loss) 1
|
|
2,854
|
-
|
6,831
|
-
|
Cash flow from (used
in) operating activities
|
|
25,518
|
(777)
|
35,820
|
(1,661)
|
Adjusted funds flow
from (used in) operations 1
|
|
30,763
|
(290)
|
69,829
|
(1,279)
|
Per share basic
2,3
|
|
0.71
|
(0.02)
|
2.20
|
(0.09)
|
Per share diluted
2,3
|
|
0.71
|
(0.02)
|
2.20
|
(0.09)
|
Net debt to adjusted
funds flow from operations 1
|
|
|
|
0.74
|
N/A
|
Free funds flow
(deficiency) from operations 1
|
|
(1,195)
|
(1,125)
|
18,929
|
(7,571)
|
Net income
(loss)
|
|
44,306
|
9,732
|
(22,315)
|
(4,869)
|
Per share basic
2,3
|
|
1.02
|
0.64
|
(0.70)
|
(0.36)
|
Per share diluted
2,3
|
|
1.02
|
0.64
|
(0.70)
|
(0.36)
|
Capital expenditures
prior to acquisitions
|
|
31,958
|
835
|
50,900
|
6,292
|
Acquisitions
|
|
-
|
-
|
282,414
|
-
|
Total capital
expenditures
|
|
31,958
|
835
|
333,314
|
6,292
|
Balance sheet
($000s, except share amounts)
|
|
|
|
|
|
Total assets
|
|
614,337
|
172,993
|
614,337
|
172,993
|
Long-term
liabilities
|
|
124,587
|
3,448
|
124,587
|
3,448
|
Net debt (surplus)
1
|
|
51,512
|
(54,401)
|
51,512
|
(54,401)
|
Adjusted working
capital deficit (surplus) 1
|
|
18,644
|
(54,401)
|
18,644
|
(54,401)
|
Weighted average shares
outstanding 2,3
|
|
|
|
|
|
Basic and
diluted
|
|
43,622,942
|
15,202,845
|
31,689,093
|
13,540,477
|
Shares outstanding end
of period 2,3
|
|
43,674,583
|
18,723,718
|
43,674,583
|
18,723,718
|
Return on average
capital employed (ROACE) 1
|
|
|
|
25%
|
(1%)
|
Reserves
|
|
|
|
|
|
Proved reserves (MMboe)
4
|
|
|
|
106.1
|
30.5
|
Proved reserves per
share (boe) 4
|
|
|
|
2.4
|
1.6
|
Proved plus probable
reserves (MMboe) 4
|
|
|
|
180.2
|
48.1
|
Proved plus probable
reserves per share (boe) 4
|
|
|
|
4.2
|
2.6
|
1 – Non-GAAP measure
that does not have any standardized meaning under IFRS and
therefore may not be comparable to similar measures presented by
other entities. Please refer to the Corporation's MD&A as at
and for the three and twelve months ended December 31, 2021 under
the section "Non-GAAP Measures" available on Kiwetinohk's SEDAR
profile at www.sedar.com
|
2 – As part of the
Arrangement, Kiwetinohk consolidated the outstanding Kiwetinohk
common shares, stock options and performance warrants on a 10 to 1
basis. All information related to common shares, stock options,
performance warrants and per share amounts, have been restated to
reflect the share consolidation for all periods
presented.
|
3 – Per share amounts
are based on weighted average basic and diluted shares,
respectively.
|
4 – Oil and natural gas
reserves are as determined by the Company's independent qualified
reserve evaluator with an effective date of December 31 for the
years shown in accordance with the Canadian Oil and Gas Evaluation
Handbook and are shown as net working interest reserves before
royalties.
|
5 – Realized loss on
risk management contracts includes settlement of hedges of physical
production and on marketing activity.
|
6 - See "Oil and Gas
Disclosure" for NI 51-101 product type information.
|
Upstream operational update
The Company initiated its drilling program in the Fox Creek area during the fourth quarter with
the spudding of 4 wells. Kiwetinohk plans to drill a further 11
wells during 2022. The well designs planned for the program are
targeting longer lateral lengths, as well as increased completion
volumes and pump rates. The design strategy seeks to reduce capital
costs per lateral metre and per barrel of recoverable resources as
the wells are expected to access and more effectively stimulate
increased reservoir volumes. As Kiwetinohk has recently initiated
its first drilling program following the completion of major
acquisitions, management expects to incur incremental capital costs
as new well designs are tested and new learnings are incorporated
over the course of the drilling program. Improved capital
efficiencies are anticipated over the course of the program and
into subsequent years as cost efficiencies are realized and well
performance from enhanced well designs is optimized.
During the fourth quarter of 2021, the Company rig released two
Duvernay horizontal wells from the
existing 9-07 pad in the Simonette area. One well came on
stream at the end of February and is currently producing 3.0-3.5
MMcf/d of natural gas and liquids and 800-900 boe/d of
condensate. The early-stage practice is to bring these wells
on stream slowly by keeping the well choked back. The Company
is very encouraged by the early performance of this well. A
second well completed at the same time encountered some
difficulties while milling out the plugs from the fracture
stimulation operation. The operation is currently attempting
to recover tubing and the milling bit from the well prior to
bringing this well online, and the Company is targeting to start
production from this well early in the second quarter of 2022.
Drilling costs for the two wells averaged just over $6.5 million per well. Completion costs for the
first well that is currently on production is expected to come in
between $9-10 million. The second
well, where the problems have occurred, is expected to see
significant cost overruns due to the complications encountered. It
is expected that these costs will be lower on subsequent wells,
which has already been seen on more recent activity.
The Company also drilled two Placid-area wells in the
Montney formation. Completion
operations finished in mid-March 2022
and the flow back operation recently commenced through test
facilities, with initial well results expected in April 2022. Drilling costs for the two wells
averaged just over $4 million per
well. Completion costs for these two wells is expected to average
$5.5 million per well.
In early 2022, the Company drilled two Duvernay horizontal wells on pad 12-28 in the
northern part of the Simonette area that are currently waiting to
be completed and brought on-line. Drilling costs for these two
wells averaged just under $5 million
per well. In addition, the Company is drilling four Duvernay horizontal wells on pad 4-34 also in
the Simonette area, which will be completed and brought on-line in
the second half of 2022.
Equip and tie-in costs across the development program are
expected to average approximately $1
million per well.
Health & Safety
As part of integration of the
Simonette assets and Distinction Energy and the approach of
construction of power projects, Kiwetinohk is implementing a new
health and safety program that applies best practices across all
operations. The Company continues to exercise caution with respect
to COVID-19 risks by following local government and public health
direction and other safeguards.
Reserves
McDaniel & Associates Consultants Ltd. conducted an
independent reserves evaluation, effective December 31, 2021, which was prepared in
accordance with the definitions, standards and procedures contained
in the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) and
National Instrument 51-101 - Standards of Disclosure for Oil and
Gas Activities (NI 51-101). Additional reserve information as
required under NI 51-101 is included in our AIF.
Reserve highlights through the year include:
- Significant growth in reserves as a result of the Distinction
and Simonette acquisitions which added 156 million boe of Proved
plus Probable Reserves.
- Proved reserves increased 248% from 30.5 million boe in 2020 to
106.2 million boe in 2021 and Proved plus Probable reserves
increased 274% from 48.1 million boe in 2020 to 180.2 million boe
in 2021.
- Proved plus Probable net present value (NPV) at 15% increased
to $1.5 billion representing a 26%
increase over the 2021 mid-year reserve report and 638% over the
2020 year-end reserve report.
- The Company re-prioritized its development plans following
acquisitions during the year to higher-return undeveloped land
locations resulting in a $46 million
impairment in Q1 2021.
- Based on a fourth quarter average production rate of 12,422
boe/d, the reserve life index is 23.4 years based on Proved
reserves and 39.7 years based on Proved plus Probable
reserves.
Acquisition cost:
With the benefit of having
investment capital available from its 2018 initial financing, the
Company was able to acquire oil and gas reserves in 2020 and 2021
during low periods in the commodity price cycle. The following
table summarizes reserves acquired and acquisition costs.
Reserve
category
|
Acquisition
reserves1 (MMboe)
|
Acquisition
cost2
($MM)
|
Acquisition
cost2
($ /
boe)
|
Recycle
Ratio3
*
|
Proved developed
producing
|
34.4
|
403.2
|
11.72
|
3.5x
|
Total proved
|
100.8
|
403.2
|
4.00
|
10.3x
|
Total proved plus
probable
|
156.1
|
403.2
|
2.58
|
15.9x
|
Notes:
|
(1)
|
Acquisition reserves
include reserves acquired as part of the Simonette Acquisition and
Distinction business combination.
|
(2)
|
Acquisition cost is
$296.4 million from the Simonette Acquisition and $187.6 million
from the Distinction business
combination less $95.8 million of cash acquired, plus contingent
consideration of $5 million paid in January 2022 and
includes an estimated $10 million second contingent
payment.
|
(3)
|
Recycle ratio is
calculated as the Q4 2021 operating netback of $41.20 / boe divided
by the acquisition cost per reserve
category boe volume.
|
Reserve summary:
Gross
reserves1, 3
at December 31,
2021
|
Heavy
oil
Mbbl
|
Tight
oil
Mbbl
|
Shale
gas
MMcf
|
NGLs2
Mbbl
|
Total
Mboe
|
Proved developed
producing
|
15.1
|
1,370.1
|
100,288.3
|
13,733.4
|
31,833.3
|
Proved developed
non-producing
|
-
|
-
|
8,653.9
|
1,105.7
|
2,548.0
|
Proved
undeveloped
|
113.1
|
-
|
205,830.5
|
37,367.4
|
71,785.5
|
Total proved
|
128.2
|
1370.1
|
314,772.8
|
52,206.5
|
106,166.9
|
Probable
|
204.1
|
269.0
|
244,603.9
|
32,799.0
|
74,039.4
|
Total proved plus
probable
|
332.3
|
1,639.1
|
559,376.7
|
85,005.5
|
180,206.3
|
Percent
|
0.2%
|
0.9%
|
51.7%
|
47.2%
|
100%
|
Notes:
|
(1)
|
Gross reserves are
working interest reserves before royalty deductions.
|
(2)
|
Figures include natural
gas liquids (NGL) for both conventional and unconventional
reservoirs, including condensate, pentane plus, propane, butane and
ethane. Condensate is expected to be extracted in the field and
sold separately from other NGL or sold with other NGL delivered to
fractionation facilities. Other NGL (propane, butane and ethane)
are expected to be extracted in the field by Kiwetinohk.
|
(3)
|
These figures are
derived from volumes that are arithmetic sums of multiple estimates
of reserves categories or sub-categories, which statistical
principles indicate may be misleading as to volumes that may
actually be recovered. Readers should review the estimates of
individual classes of reserves and appreciate the differing
probabilities of recovery associated with each class as explained
under the heading "Glossary, Selected Abbreviations and Selected
Conversions" in Appendix "A" of the Company's AIF.
|
Net present values of future net revenue:
($ million before
tax)1, 2, 3
|
NPV
0%
|
NPV
10%
|
NPV
15%
|
NPV
20%
|
Proved developed
producing
|
644.9
|
469.0
|
405.1
|
358.1
|
Proved developed
non-producing
|
85.9
|
67.2
|
61.8
|
57.6
|
Proved
undeveloped
|
1,567.0
|
736.5
|
541.7
|
409.5
|
Total
proved
|
2,297.8
|
1,272.8
|
1,008.6
|
825.2
|
Total
probable
|
1,781.7
|
672.1
|
475.9
|
356.8
|
Total proved plus
probable
|
4,079.5
|
1,944.8
|
1,484.1
|
1,182.0
|
Notes:
|
(1)
|
Estimates of
future net revenue do not represent fair market value.
|
(2)
|
These figures are
derived from volumes that are arithmetic sums of multiple estimates
of reserves categories or sub-categories, which statistical
principles indicate may be misleading as to volumes that may
actually be recovered. Readers should review the estimates of
individual classes of reserves and appreciate the differing
probabilities of recovery associated with each class as explained
under the heading "Glossary, Selected Abbreviations and Selected
Conversions" in Appendix "A" of the Company's AIF.
|
(3)
|
The unit values are
based on net reserve volumes from the Company's NI 51-101 reserve
report using forecast pricing and foreign exchange rates at January
1, 2022.
|
Green energy development update
The Company's longer-term goal is to profitably provide
consumers with clean, reliable, dispatchable, low-cost energy.
In that pursuit Kiwetinohk is advancing five solar and
gas-fired power projects. These five projects are in the
initial development phase in which the Company is advancing site
control, grid access, consultation, regulatory approvals and
front-end engineering and design (FEED). The Company has made
significant development progress across its 1,800 MW (nameplate
capacity) solar and gas-fired power portfolio. Kiwetinohk advanced
work in the AESO staging process to secure grid access with 4 of 5
projects progressing in Stage 2. With stakeholder consultation near
completion and an AEP referral letter concluding the project is low
risk to wildlife and wildlife habitat, the Company is targeting to
submit an AUC application for the 400 MW Solar 1 project in the
second quarter. The Company is also targeting to submit AUC and AEP
industrial applications for the 101 MW Firm Renewable 1 project in
the second quarter.
The Company continues to evaluate CCUS technologies and
potential investments as part of its plan to deliver clean energy
from its gas-fired power plants. Kiwetinohk has also progressed its
evaluation of a blue hydrogen production project in partnership
with a midstream infrastructure company and an industrial
partner.
Kiwetinohk estimates the 400 MW Solar 1 and 101 MW Firm
Renewable 1 projects can attain FID by year-end 2022, subject to
regulatory review timelines. The Company has revised its target FID
for the Firm Renewable 1 project from Q3 to Q4 2022 to account for
potential regulatory delays, and increased its installed capital
cost estimate by $11 million to
$156 million based on potential
increases in material and equipment costs and supply chain
challenges in a post pandemic environment. Kiwetinohk has also
revised its indicative FID and COD for NGCC 2 to Q4 2023 and Q4
2026, respectively, to account for potential delays in regulatory
reviews, CCUS policies and programs and supply chain.
As at March 23, 2022 early-stage
development and design factors and the status of each project are
summarized in the following tables:
|
Solar
1
|
Solar
2
|
Firm Renewable
1
|
NGCC
1
|
NGCC
2
|
Nameplate/Net
to Grid Capacity
|
400 MW
|
300 MW
|
101 MW
97 MW
|
500 MW
460 MW
|
500MW
460 MW
|
AESO
Stage
|
2
|
1
|
2
|
2
|
2
|
Site
Control
|
Options
secured
|
Options
secured
|
Land acquisition in
progress
|
Options
secured
|
Land acquisition in
progress
|
Public
Consultation
|
Underway
|
Planning
underway
|
Completed
|
Planning
underway
|
Planning
underway
|
Regulatory /
Environmental
|
AEP referral letter
received; AUC Q2 2022
|
AEP application
submitted
|
AUC and AEP Q2
2022
|
Planning
underway
|
Planning
underway
|
Engineering
|
Pre-FEED complete;
FEED near completion
|
BD complete
|
FEED
complete
|
BD complete;
Pre-FEED underway
|
BD complete; Pre-FEED
underway
|
Targeted
FID
|
Q3 2022
|
Q2 2023
|
Q4 2022
|
Q3 2024
|
Q4 2023
|
Targeted COD
4
|
Q4 2024
|
Q2 2025
|
Q4 2024
|
Q3 2027
|
Q4 2026
|
Total installed
capital cost
($ million) 1, 2, 3
|
$655
(Class 3)
|
$492
(Class 3)
|
$156
(Class 3)
|
$875
(Class 4)
|
$875
(Class 4)
|
1 – Total installed
cost estimates are classified in a manner consistent with American
Association of Cost Engineering (AACE) standards.
|
2 – Total installed
cost numbers exclude carbon capture and sequestration. CCUS costs
are estimated to be an incremental 60 to 80% of the total installed
cost based on an engineering study by Gas Liquids Engineering
(GLE).
|
3 – None of the
Company's planned power generation projects have a final design,
performance projection or cost estimate, or full regulatory
approval or internal or external funding. There is no assurance
that the power generation projects will proceed as described or at
all.
|
4 – If a FID decision
is reached the Company will advance the project towards an
estimated Commercial Operations Date (COD).
|
Environment, Social and Governance (ESG)
Kiwetinohk is completing a thorough review of its environmental,
social and governance (ESG) risks and management strategies and
plans to publish its first ESG report in mid-2022 in alignment with
the Sustainability Accounting Standards Board (SASB) data standards
for Oil & Gas – Exploration and Production and with the Task
Force on Climate-related Financial Disclosure (TCFD) framework.
Guidance
Kiwetinohk's priority is to deliver attractive returns on
capital employed during the year through profitable investment in
high quality assets to position the Company to deliver strong free
cash flow generation and growth in future years. The Company's
annual capital expenditures and production guidance for 2022
remains unchanged and is provided below.
|
|
|
|
|
2022
Guidance
|
Operational &
financial guidance
|
|
Low
|
High
|
Production (2022
average) 1
|
(Mboe/d)
|
13.0
|
15.0
|
Oil &
liquids
|
(Mbbl/d)
|
6.5
|
7.5
|
Natural
gas
|
(MMcf/d)
|
39.0
|
45.0
|
Production by
market
|
(%)
|
100
|
100
|
Chicago
|
(%)
|
87
|
97
|
AECO
|
(%)
|
3
|
13
|
Royalty rate
(Crown)
|
(%)
|
12
|
15
|
Operating
costs1
|
($/boe)
|
7.50
|
8.50
|
Transportation
(excluding marketing activities)
|
($/boe)
|
5.00
|
6.00
|
G&A expense before
share-based compensation 2
|
($MM)
|
15.0
|
18.0
|
Cash taxes
|
($MM)
|
-
|
-
|
|
|
|
|
Capital
guidance
|
|
Low
|
High
|
Capital
|
($MM)
|
210
|
240
|
Green
Energy
|
($MM)
|
10
|
20
|
Upstream
|
($MM)
|
200
|
220
|
New Fox Creek wells
(gross)
|
(wells)
|
11
|
Duvernay
|
(wells)
|
10
|
Montney
|
(wells)
|
1
|
|
|
|
|
|
|
|
|
Sensitivities
|
|
Low
|
High
|
Adjusted funds flow
from operations 3, 5
|
|
|
|
US$60/bbl
WTI & US$3.25/MMBtu HH
|
($MM)
|
$120
|
$130
|
US$70/bbl
WTI & US$3.75/MMBtu HH
|
($MM)
|
$145
|
$155
|
US$80/bbl
WTI & US$4.25/MMBtu HH
|
($MM)
|
$165
|
$175
|
|
|
|
Net debt to adjusted
funds flow from operations 4, 5
|
|
|
US$60/bbl
WTI & US$3.25/MMBtu HH
|
*
|
1.3x
|
|
US$70/bbl
WTI & US$3.75/MMBtu HH
|
*
|
1.0x
|
|
US$80/bbl
WTI & US$4.25/MMBtu HH
|
*
|
0.7x
|
|
|
|
|
|
|
|
|
|
|
|
|
1 – Production and cash
operating costs include a provision for scheduled plant turnarounds
at Fox Creek.
|
2 – Includes all cash
G&A expenses for all divisions of the Company – Corporate,
Upstream, Green Energy (power & hydrogen) and Business
Development.
|
3 – Adjusted funds flow
from (used in) operations is cash flow from (used in) operating
activities before changes in net change in non-cash working capital
from operating activities, asset retirement obligations,
restructuring costs, acquisition costs and settlement agreement
costs.
|
4 – Net Debt to
adjusted funds flow from (used in) operations is net debt (surplus)
divided by adjusted funds flow from (used in) operations. Net debt
is comprised of loans and borrowings plus adjusted working capital
deficit (surplus) and represents the Company's net financing
obligations.
|
5 – This Non-GAAP
measure does not have any standardized meaning under IFRS and
therefore may not be comparable to similar measures presented by
other entities. Please refer to the Corporation's MD&A as at
and for the three and twelve months ended December 31, 2021 under
the section "Non-GAAP Measures" available on Kiwetinohk's SEDAR
profile at www.sedar.com.
|
The Company continues to make significant progress in advancing
its Alberta-based diversified
solar and gas-fired development power portfolio and currently
expects to spend between $10 and
$20 million in 2022 on project
planning, approvals, engineering and design and securing of
financing required to advance projects to a final investment
decision (FID). This capital budget is expected to enable the
Company to maintain its current schedule of development activities
for its existing portfolio of power development projects and also
evaluate other early-stage development projects for potential
acquisition. The Company expects its first solar and Firm
Renewable projects to reach FID by the end of the year and it has
provided an updated timeline for its green energy project portfolio
as further described in the Corporation's MD&A as at and for
the three and twelve months ended December
31, 2021 under the section Green Energy Development
Update.
The 2022 upstream capital budget is currently established in a
range between $200 to $220 million and is focused the Fox Creek area where the Company plans to
drill 11 gross wells. Kiwetinohk expects to bring four wells
drilled in late 2021 onto production in the first half of 2022. Six
of 11 new wells planned for 2022 are expected to come onto
production in the second half of the year, with the remaining five
expected to come onto production in the first half of 2023. The
capital program is expected to be fully funded from cash flow from
operating activities and available debt capacity and is anticipated
to deliver strong baseline cash flow in 2022 and thereafter. The
wells drilled and completed in 2022 are expected to more than
arrest declines, growing production to further fill the Company's
facilities at Fox Creek, which are
currently operating at less than half of available capacity. The
Company has updated its previously communicated first quarter
production estimates of 11,000 to 12,000 boe/d to be in line with
fourth quarter levels of 12,000 to 13,000 boe/d. The Company still
expects production to increase from first quarter of 2022 projected
levels to 20,000 to 21,000 boe/d during the first quarter of
2023.
Operating costs are anticipated to be higher in the first half
of 2022 impacted by inflationary cost pressure in the field,
production declines, cold weather impacts and scheduled plant
turnarounds in Fox Creek. With
additional production coming onstream through 2022 the Company
expects operating costs per boe to improve as increased production
volumes fill more of the Company's facilities at Fox Creek and fixed operating costs are spread
over a larger production volume.
Base shelf prospectus
The Company intends to file a preliminary short-form base shelf
prospectus (Prospectus) to provide financing flexibility and
additional options for quicker access to equity and/or debt markets
as it continues to pursue potential acquisition
opportunities. The Prospectus is expected to provide
Kiwetinohk, the right but not the obligation to issue securities of
up to $500 million over a period of
25 months. There are no immediate plans to raise equity, debt or
other forms of financing and net proceeds from the sale of any
securities issued under the Prospectus could have a wide range of
uses including to complete asset or corporate acquisitions, to
finance potential future growth opportunities, to repay
indebtedness, to finance the Company's ongoing capital program, or
for other general corporate purposes.
Subsequent events
Mr. Timothy Schneider has given
notice of his retirement from the Board of Directors effective
March 23, 2022 and will not stand for
election at the Company's 2022 Annual General Meeting. Mr.
Schneider was President and Chief Executive Officer of Distinction
Energy Corp. (formerly Delphi Energy Corp.) from October 2020 to April
2021 and served in such positions during Distinction's court
supervised CCAA proceedings that resulted in the restructuring of
Distinction on October 16, 2020
pursuant to a CCAA plan of compromise and arrangement. During
his time with Kiwetinohk, Mr. Schneider was a member of the Audit
Committee and Governance and Nominating Committee.
Kevin Brown, Chairman, said "On
behalf of Kiwetinohk's Board of Directors, I want to thank Tim for
his contributions and insights as a director and for helping
Kiwetinohk to close on a number of significant and strategic
acquisitions in 2021. We wish Mr. Schneider success and all
the best in his future pursuits."
Conference call
Management of Kiwetinohk will host a conference call at
9 AM MT (11 AM
ET) to discuss results and field questions.
Participants will be able to listen to the conference call by
dialing 1-888-220-8451 (North America toll free) or
1-647-484-0475 (Toronto and area). A recording will be
available for replay until March 31,
2022 by dialing 1-888-203-1112 and using the replay code
6873969.
About Kiwetinohk
We, at Kiwetinohk, are passionate about climate change and the
future of energy. Kiwetinohk's mission is to build a
profitable energy transition business providing clean, reliable,
dispatchable, low-cost energy. Kiwetinohk develops and
produces natural gas and related products and is in the process of
developing renewable power, natural gas-fired power, carbon capture
and hydrogen clean energy projects. We view climate change with a
sense of urgency, and we want to make a difference.
Kiwetinohk's common shares trade on the Toronto Stock Exchange
under the symbol KEC.
Additional details are available within the year-end documents
available on Kiwetinohk's website at www.kiwetinohk.com and SEDAR
at www.sedar.com.
Advisories
This press release is for informational purposes only and is not
intended to and does not constitute, or form any part of, an offer
to sell or the solicitation of an offer to subscribe for or buy or
an invitation to purchase or subscribe for any securities in any
jurisdiction, nor shall there be any sale or issuance of securities
in any jurisdiction in contravention of applicable law or
regulation. In particular, this press release is not an offer of
securities for sale in Canada or
the United States.
Oil and Gas Disclosure
The term "boe" may be misleading, particularly if used in
isolation. A boe conversion rate of six thousand cubic feet of
natural gas per barrel of oil (6 mcf:1 bbl) is based on an energy
equivalency conversion method primarily applicable at the burner
tip and do not represent a value equivalency at the wellhead. Given
that the value ratio based on the current price of crude oil as
compared to natural gas is significantly different from an energy
equivalency of 6:1, utilizing a conversion ratio of 6:1 may be
misleading as an indication of value.
Readers should review the estimates of individual classes of
reserves and appreciate the differing probabilities of recovery
associated with each class as explained under the heading
"Glossary, Selected Abbreviations and Selected Conversions" in
Appendix "A" of the Company's AIF.
In this press release, "light oil" refers to light and medium
crude oil, "heavy oil" refers to heavy crude oil and "natural gas"
refers to conventional natural gas, in each case as defined in NI
51-101.
Forward looking information
Certain information set forth in this news release contains
forward-looking information and statements including, without
limitation, management's business strategy, management's assessment
of future plans and operations. Such forward-looking statements or
information are provided for the purpose of providing information
about management's current expectations and plans relating to the
future. Forward-looking statements or information typically contain
statements with words such as "anticipate", "believe", "expect",
"plan", "intend", "estimate", "project", "potential" or similar
words suggesting future outcomes or statements regarding future
performance and outlook. Readers are cautioned that assumptions
used in the preparation of such information may prove to be
incorrect. Events or circumstances may cause actual results to
differ materially from those predicted as a result of numerous
known and unknown risks, uncertainties and other factors, many of
which are beyond the control of the Company.
In particular, this news release contains forward-looking
statements pertaining to the following:
- the timing for bringing the Company's second Duvernay horizontal well from the existing
9-07 pad online;
- the timing for having initial test results from recently
released Placid wells;
- the timing for bringing the Company's four Duvernay horizontal wells on pad 4-34
online;
- the timing for publishing the Company's upstream emissions
intensity and GH reduction strategy;
- the Company's 2022 capital expenditures budget and allocations
thereof, related drilling and project development plans and the
effects thereof;
- 2022 and 2023 production guidance;
- the Company's 2022 operational and financial guidance;
- the timing for the Company's first solar and Firm Renewable
projects reaching FID; and
- the estimates of reserves and future net revenue related
thereto.
In addition to other factors and assumptions that may be
identified in this news release, assumptions have been made
regarding, among other things:
- the timing and costs of the Company's capital projects;
- the impact of increasing competition;
- the general stability of the economic and political environment
in which the Company operates;
- the ability of the Company to obtain qualified staff, equipment
and services in a timely and cost efficient manner;
- future commodity and power prices;
- currency, exchange and interest rates;
- the regulatory framework regarding royalties, taxes, power,
renewable and environmental matters in the jurisdictions in which
the Company operates; and
- the ability of the Company to successfully market its
products.
Readers are cautioned that the foregoing list is not exhaustive
of all factors and assumptions that have been used. Although the
Company believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue
reliance should not be placed on forward-looking statements as the
Company can give no assurance that such expectations will prove to
be correct.
Forward-looking statements or information involve a number of
risks and uncertainties that could cause actual results to differ
materially from those anticipated by the Company and described in
the forward-looking statements or information. These risks and
uncertainties include, among other things:
- the ability of management to execute its business plan;
- general economic and business conditions;
- the risk of instability affecting the jurisdictions in which
the Company operates;
- the risks of the power and renewable industries;
- operational and construction risks associated with certain
projects;
- the possibility that government policies or laws may change or
governmental approvals may be delayed or withheld;
- uncertainty involving the forces that power certain renewable
projects;
- the Company's ability to enter into or renew leases;
- potential delays or changes in plans with respect to power and
solar projects or capital expenditures;
- fluctuations in commodity and power prices, foreign currency
exchange rates and interest rates;
- risks inherent in the Company's marketing operations, including
credit risk;
- health, safety, environmental and construction risks;
- risks associated with existing and potential future lawsuits
and regulatory actions against the Company;
- uncertainties as to the availability and cost of financing;
and
- financial risks affecting the value of the Company's
investments.
Readers are cautioned that the foregoing list is not exhaustive
of all possible risks and uncertainties.
The forward-looking statements and information contained in this
news release speak only as of the date of this news release and the
Company undertakes no obligation to publicly update or revise any
forward-looking statements or information, except as expressly
required by applicable securities laws.
Non-GAAP Measures
This news release contains measures that do not have a
standardized meaning under generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures
presented by other entities. These performance measures
presented in this document should not be considered in isolation or
as a substitute for performance measures prepared in accordance
with GAAP and should be read in conjunction with the consolidated
financial statements of the Company. Readers are cautioned that
these non-GAAP measures do not have any standardized meanings and
should not be used to make comparisons between Kiwetinohk and other
companies without also taking into account any differences in the
method by which the calculations are prepared.
Please refer to the Corporation's MD&A as at and for the
three and twelve months ended December 31,
2021 under the section "Non-GAAP Measures" available on
Kiwetinohk's SEDAR profile at www.sedar.com
Future-Oriented Financial Information
Financial outlook and future-oriented financial information
contained in this press release about prospective financial
performance, financial position or cash flows is based on
assumptions about future events, including economic conditions and
proposed courses of action, based on management's assessment of the
relevant information currently available. In particular, this press
release contains expected adjusted funds flow, return on capital
employed, capital costs of the Company's proposed power generation
capital projects, forecast economics of the Company's oil and gas
assets and 2022 financial outlook information for the Company,
including expected royalty rates, operating costs, transportation
expenses, corporate G&A expenses, cash taxes, adjusted funds
flow from (used in) operations, and net debt per adjusted funds
flow from (used in) operations. These projections contain
forward-looking statements and are based on a number of material
assumptions and factors set out above and are provided to give the
reader a better understanding of the potential future performance
of the Company in certain areas. Actual results may differ
significantly from the projections presented herein. These
projections may also be considered to contain future oriented
financial information or a financial outlook. The actual results of
the Company's operations for any period will likely vary from the
amounts set forth in these projections, and such variations may be
material. See above and "Risk Factors" in the Company's AIF
published on the Company's profile on SEDAR at www.sedar.com for a
further discussion of the risks that could cause actual results to
vary. The future oriented financial information and financial
outlooks contained in this press release have been approved by
management as of the date of this press release. Readers are
cautioned that any such financial outlook and future-oriented
financial information contained herein should not be used for
purposes other than those for which it is disclosed herein.
Abbreviations
|
|
$/bbl
|
dollars per
barrel
|
$/boe
|
dollars per barrel
equivalent
|
$MM
|
millions of
dollars
|
bbl/d
|
barrels per
day
|
boe
|
barrel of oil
equivalent, including crude oil, condensate, natural gas liquids,
and natural gas (converted on the basis of one boe per six mcf of
natural gas)
|
HH
|
Henry Hub
|
Mbbl/d
|
millions of barrels per
day
|
Mboe/d
|
millions of barrels of
oil equivalent per day
|
Mcf/d
|
thousand cubic standard
feet per day
|
MMboe
|
million barrels of oil
equivalent
|
MMBtu
|
million British thermal
units
|
MMcf/d
|
million cubic feet per
day
|
WTI
|
West Texas
Intermediate
|
FOR MORE INFORMATION ON KIWETINOHK,
PLEASE CONTACT:
Mark
Friesen, Director, Investor
Relations
IR phone: (587)
392-4395
IR email: IR@kiwetinohk.com
Address: Suite 1900, 250 - 2 Street S.W.
Calgary, Alberta T2P
0C1
Pat
Carlson,
CEO
Jakub
Brogowski, CFO
SOURCE Kiwetinohk Energy