CALGARY,
AB, Feb. 29, 2024 /CNW/ - Crescent Point
Energy Corp. ("Crescent Point" or the "Company") (TSX: CPG) (NYSE:
CPG) is pleased to announce its operating and financial results for
the year ended December 31, 2023.
KEY HIGHLIGHTS
- Transformed portfolio, increasing premium inventory to over 20
years and enhancing excess cash flow profile.
- Replaced over 900 percent of 2023 production on a 2P reserves
basis including strategic A&D, or 150 percent organically.
- Generated $980 million of excess
cash flow in 2023, with capital expenditures and production in-line
with guidance.
- Returned approximately $600
million, or 60 percent of excess cash flow, to shareholders
in 2023.
- Increasing quarterly base dividend by 15 percent to
$0.115 per share, or $0.46 per share annually.
- Generated a strong FD&A recycle ratio of 2.5 times in 2023,
including change in FDC, based on 2P reserves.
- Excess cash flow of $830 million
expected in 2024 at US$75 WTI, with
60 percent returned to shareholders.
- Five-year plan expected to generate strong per share growth and
cumulative excess cash flow of $4.7
billion at US$70 WTI.
"This past year was pivotal in our company's history as we
successfully transformed our portfolio," said Craig Bryksa, President and CEO of Crescent
Point. "Through this execution, we have materially enhanced the
long-term sustainability of our business, including by increasing
our premium drilling inventory to over 20 years and enhancing our
excess cash flow profile on a per share basis. Our strategic
priorities going forward are operational execution, balance sheet
strength and increasing return of capital to shareholders."
FINANCIAL HIGHLIGHTS
- Adjusted funds flow totaled over $2.3
billion for the year ended December
31, 2023, or $4.27 per share
diluted, driven by a strong operating netback of $43.71 per boe. In fourth quarter, adjusted funds
flow totaled $574.5 million, or
$1.03 per share diluted.
- For the year ended December 31,
2023, development capital expenditures, which included
drilling and development, facilities and seismic costs, totaled
$1.14 billion, within the Company's
annual guidance range of $1.05
billion to $1.15 billion.
- The Company's net debt as at December
31, 2023 was approximately $3.7
billion. Throughout 2023, Crescent Point executed on its
portfolio strategy which included material additions in the Alberta
Montney along with non-core asset dispositions. During fourth
quarter 2023, Crescent Point entered into agreements to dispose of
its Swan Hills and Turner Valley assets in Alberta, which have closed or are expected to
close in first quarter 2024.
- For the year ended December 31,
2023, Crescent Point reported net income from continuing
operations of $799.4 million, or
$1.46 per share diluted. The
Company's total net income for 2023, including discontinued
operations, was $570.3 million, or
$1.04 per share diluted, which
included net non-cash charges of $106.7
million related to the disposition of its U.S. assets.
- The Company has hedged approximately 45 percent of its oil and
liquids production and over 30 percent of its natural gas
production in 2024, net of royalty interest. The Company has also
diversified its pricing exposure for natural gas, with the majority
of its production through 2025 receiving a combination of fixed
prices and pricing related to major U.S. markets.
RETURN OF CAPITAL HIGHLIGHTS
- The Company's total return of capital to shareholders in 2023,
including the base dividend, was $599.5
million, or approximately 60 percent of its annual excess
cash flow.
- During fourth quarter, Crescent Point prioritized share
buybacks within its return of capital framework, repurchasing 8.4
million shares for $83.8 million. The
Company repurchased a total of 34.6 million shares for $349.9 million in 2023, representing over six
percent of its public float at the start of the year. Crescent
Point intends to file with the Toronto Stock Exchange ("TSX") a
notice of intention to renew its normal course issuer bid ("NCIB"),
which is due to expire on March 8,
2024.
- Crescent Point's Board of Directors has approved and declared a
first quarter 2024 base dividend of $0.115 per share, an increase of 15 percent from
the prior level. The base dividend is payable on April 1, 2024 to shareholders of record on
March 15, 2024. This base dividend
increase equates to an annualized base dividend of $0.46 per share.
|
Adjusted funds flow,
adjusted funds flow per share diluted, excess cash flow, recycle
ratio, total return of capital and net debt are specified financial
measures - refer to the Specified Financial Measures section in
this press release for further information. All financial figures
are approximate and in Canadian dollars unless otherwise noted.
This press release contains forward-looking information and
references to specified financial measures. Significant related
assumptions and risk factors, and reconciliations are described
under the Specified Financial Measures, Forward-Looking Statements
and Reserves and Drilling Data sections of this press release,
respectively. Further information breaking down the production
information contained in this press release by product type can be
found in the "Product Type Production Information" section of this
press release.
|
OPERATIONAL HIGHLIGHTS
- Achieved annual average production of 159,411 boe/d in 2023,
within the Company's annual production guidance range of 156,000 to
161,000 boe/d, notwithstanding the downtime associated with the
Alberta wildfires earlier in the
year. Crescent Point's average production in fourth quarter 2023
was 162,269 boe/d.
- In the Kaybob Duvernay, the Company delivered consistent
results throughout 2023, demonstrating the strength of its
operational execution. Crescent Point brought on stream over 20
wells during the year through four multi-well pads. These pads
generated average peak 30-day rates ranging from 1,000 boe/d to
1,550 boe/d (75% to 85% liquids) per well within the Volatile Oil
window and 1,425 boe/d (60% liquids) per well in the Liquids-Rich
window. During fourth quarter, Crescent Point added a second rig in
the Kaybob Duvernay to accelerate the development of its
high-return inventory.
- Crescent Point has also continued to achieve strong operational
momentum in the Alberta Montney since its initial entry into the
play in second quarter 2023. The Company brought on stream over 25
wells during the remainder of the year through nine multi-well
pads. These pads generated average peak 30-day rates ranging from
1,200 boe/d to 2,000 boe/d (70% to 85% liquids) per well in Gold
Creek West, 1,000 boe/d to 1,350 boe/d (45% to 75% liquids) per
well in Gold Creek and 775 boe/d (85% liquids) per well in
Karr East.
- Crescent Point's open hole multi-lateral ("OHML") well
development program in southeast Saskatchewan included nine eight-leg wells
during 2023. The Company's most recent OHML well achieved a peak-30
day rate of over 300 bbl/d (100% light oil), further highlighting
the strong drilling economics of this program. Crescent Point also
continued to advance its decline mitigation initiatives in 2023,
including by successfully converting approximately 100 producing
wells to water injection wells. These initiatives support the
Company's low base decline rate of approximately 15 percent in its
Saskatchewan assets, further
enhancing its strong excess cash flow generation from these
assets.
- In 2023, Crescent Point achieved the best safety scores in the
Company's history, demonstrating its ongoing commitment to safe
operations.
- During 2023, Crescent Point continued to demonstrate its
commitment to strong environmental, social and governance ("ESG")
practices as it progresses toward each of its environmental
targets, including reducing its Scope 1 and 2 emissions intensity,
surface freshwater use and inactive well inventory. The Company
remains on track to meet or exceed each of these environmental
targets. Crescent Point has significantly improved its
environmental profile, reducing both its Scope 1 emissions
intensity and asset retirement liabilities by approximately 60
percent since beginning its portfolio transformation.
RESERVES HIGHLIGHTS
"Our 2023 reserves highlight the benefits of our strategic
portfolio transformation and our technical team's strong ongoing
operational execution," said Bryksa. "We organically replaced 150
percent of our 2023 annual production on a proved plus probable
basis, primarily driven by drilling and development activity in the
Kaybob Duvernay. In 2024, we see opportunities to further enhance
shareholder value by realizing potential cost efficiencies and
productivity enhancements. At year-end 2023, over 70 percent of our
premium locations in the Alberta Montney and approximately 60
percent in the Kaybob Duvernay remain unbooked, allowing for future
reserves growth."
- The Company's reserves at year-end 2023 increased across all
categories driven by organic additions and strategic acquisitions,
net of non-core dispositions. Proved plus Probable ("2P") reserves
totaled 1,201.3 million boe ("MMboe"), Proved ("1P") reserves
totaled 768.3 MMboe and Proved Developed Producing ("PDP") reserves
totaled 381.1 MMboe.
- The Company's 2P reserve life index ("RLI") is approximately 16
years based on mid-point of 2024 annual average production
guidance.
- Crescent Point achieved net reserve additions of 88.7 MMboe on
a 2P basis, excluding acquisitions and dispositions ("A&D"),
replacing approximately 150 percent of its 2023 annual production.
These reserve additions primarily originated from the Company's
Kaybob Duvernay asset, which contributed reserve adds at an
attractive finding and development ("F&D") cost, including
change in future development capital ("FDC"), of approximately
$13.50 per boe. These Kaybob Duvernay
reserve additions resulted in a strong recycle ratio of over 3.0
times.
- Reserve additions within Crescent Point's Alberta Montney asset
are captured under the Company's acquired reserves, given the
timing of its initial entry into the play in second quarter 2023.
Including strategic acquisitions, net of dispositions, Crescent
Point added 457.7 MMboe of 2P reserves. This addition contributed
to the significant increase in 2P reserves in 2023 of approximately
70 percent and replaced over 900 percent of the Company's 2023
annual production.
- Crescent Point generated 2P finding, development and
acquisition ("FD&A") cost, including change in FDC, of
$17.70 per boe, producing a recycle
ratio of 2.5 times based on an operating netback of $43.71 per boe in 2023.
- Crescent Point's 2P net asset value ("NAV") was $22.45 per share at year-end 2023, based on
independent engineering pricing. On a PDP and 1P basis, the
Company's NAV was $7.63 and
$14.07 per share, respectively. The
independent engineering price forecast assumes an average WTI price
of approximately US$76.35/bbl and
AECO price of approximately $3.60/Mcf
in the first five years. The Company's NAV at year-end 2023 does
not include unbooked locations, primarily in the Kaybob Duvernay
and Alberta Montney, allowing for future reserves additions.
Additional information on the Company's 2023 reserves is
provided in its Annual Information Form ("AIF") for the year-ended
December 31, 2023.
OUTLOOK
Crescent Point's strategic priorities remain focused on
operational execution, balance sheet strength and increasing return
of capital to shareholders.
The Company's previously released 2024 annual average production
guidance of 198,000 to 206,000 boe/d and development capital
expenditures budget of $1.4 billion
to $1.5 billion remain unchanged.
This budget remains disciplined and flexible, with a continued
focus on allocating capital to the highest-return assets.
Approximately 45 percent of Crescent Point's 2024 budget is
allocated to the Alberta Montney, 35 percent to Kaybob Duvernay and
20 percent to Saskatchewan. The
Company's 2024 capital budget, including its base dividend, remains
fully funded at approximately US$55/bbl WTI.
Within its operations, Crescent Point continues to target
additional efficiencies and improved productivity by further
enhancing drilling and completions optimization, including
optimizing wells drilled per section on its recently acquired
Alberta Montney assets and drilling longer lateral wells in the
Kaybob Duvernay. In Saskatchewan,
the Company continues to build on its operational momentum through
the advancement of its OHML drilling and decline mitigation
programs.
Crescent Point's 2024 budget is expected to generate significant
excess cash flow of approximately $830
million at average commodity prices of approximately
US$75/bbl WTI and $2.30/Mcf AECO for the full year. The Company's
funds flow sensitivity is approximately $30
million for every US$1/bbl
change in WTI and $20 million for
every $0.25/Mcf change in AECO for
the remainder of the year.
Crescent Point plans to continue allocating 60 percent of its
excess cash flow to shareholders through the base dividend and
share repurchases, with the remaining 40 percent directed toward
the balance sheet. The Company's leverage ratio, or net debt to
adjusted funds flow, is expected to be approximately 1.2 times by
year-end 2024, based on average commodity prices of approximately
US$75/bbl WTI and $2.30/Mcf AECO for the full year.
The Company plans to increase the percentage of excess cash flow
it returns to shareholders over time as it further strengthens its
balance sheet. Crescent Point's strategy is focused on delivering
meaningful and sustainable total returns through a combination of
return of capital, per-share growth and balance sheet strength.
INVESTOR DAY
Crescent Point will host an Investor Day on March 20, 2024 to discus its corporate strategy,
operational results and long-term development plan.
For more details, please refer to the press release dated
February 15, 2024.
CONFERENCE CALL DETAILS
Crescent Point management will host a conference call on
Thursday, February 29, 2024 at
10:00 a.m. MT (12:00 p.m. ET) to discuss the Company's results
and outlook. A slide deck will accompany the conference call and
can be found on Crescent Point's website.
Participants can listen to this event online via webcast. To
join the call without operator assistance, participants may
register online by entering their phone number to receive an
instant automated call back. Alternatively, the conference call can
be accessed with operated assistance by dialing 1‑888‑390‑0605.
Participants will be able to take part in a question and answer
session following management's opening remarks through both the
webcast dashboard and the conference line.
The webcast will be archived for replay and can be accessed
online at Crescent Point's conference calls and webcasts page. The
replay will be available shortly after the completion of the
call.
Shareholders and investors can also find the Company's most
recent investor presentation on Crescent Point's website.
|
Net debt to adjusted
funds flow is a specified financial measure - refer to the
Specified Financial Measures section in this press release for
further information.
|
2024 GUIDANCE
The Company's guidance for 2024 is as follows:
|
Total Annual Average
Production (boe/d) (1)
|
198,000 -
206,000
|
|
|
Capital
Expenditures
|
|
|
Development capital
expenditures ($ millions)
|
$1,400 -
$1,500
|
|
Capitalized
administration ($ millions)
|
$40
|
|
Total ($ million)
(2)
|
$1,440 -
$1,540
|
|
|
Other Information
for 2024 Guidance
|
|
|
Reclamation activities
($ millions) (3)
|
$40
|
|
Capital lease payments
($ millions)
|
$20
|
|
Annual operating
expenses ($/boe)
|
$12.75 -
$13.75
|
|
Royalties
|
10.00% -
11.00%
|
|
1)
|
Total annual average
production (boe/d) is comprised of approximately 65% Oil,
Condensate & NGLs and 35% Natural Gas
|
|
2)
|
Land expenditures and
net property acquisitions and dispositions are not included.
Development capital expenditures spend is allocated on an
approximate basis as follows: 90% drilling & development and
10% facilities & seismic
|
|
3)
|
Reflects Crescent
Point's portion of its expected total budget
|
RETURN OF CAPITAL OUTLOOK
|
Base
Dividend
|
|
|
Current quarterly base
dividend per share
|
$0.115
|
|
Total Return of
Capital
|
|
|
% of excess cash flow
(1)
|
60 %
|
|
1)
Total return of capital
is based on a framework that targets to return to shareholders 60%
of excess cash flow on an annual basis
|
The Company's audited consolidated financial statements and
management's discussion and analysis for the year ended
December 31, 2023, will be available
on the System for Electronic Document Analysis and Retrieval
("SEDAR") at www.sedarplus.com, on EDGAR at
www.sec.gov/edgar.shtml and on Crescent Point's website at
www.crescentpointenergy.com.
Summary of Reserves
The Company's reserves were independently evaluated by McDaniel
& Associates Consultants Ltd. ("McDaniel") as at December 31, 2023. The reserves evaluation and
reporting was conducted in accordance with the definitions,
standards and procedures contained in the COGEH and National
Instrument 51-101 Standards for Disclosure of Oil and Gas
Activities ("NI 51-101").
As at December 31, 2023 (1)
(2) (3) (4)
|
Tight
Oil
(Mbbls)
|
Light and Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
Natural Gas
Liquids
(Mbbls)
|
|
Reserves
Category
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
Proved Developed
Producing
|
131,979
|
118,448
|
37,020
|
33,181
|
17,173
|
14,417
|
82,447
|
69,988
|
|
Proved Developed
Non-Producing
|
587
|
539
|
252
|
244
|
2,260
|
2,089
|
149
|
134
|
|
Proved
Undeveloped
|
106,423
|
91,180
|
9,551
|
8,892
|
1,729
|
1,582
|
107,124
|
90,233
|
|
Total
Proved
|
238,989
|
210,168
|
46,823
|
42,318
|
21,163
|
18,088
|
189,720
|
160,355
|
|
Total
Probable
|
142,434
|
119,830
|
33,119
|
29,445
|
6,677
|
5,671
|
93,735
|
73,064
|
|
Total Proved plus
Probable
|
381,422
|
329,998
|
79,942
|
71,763
|
27,840
|
23,760
|
283,455
|
233,418
|
|
Shale
Gas
(MMcf)
|
Natural
Gas
(MMcf)
|
Total
(Mboe)
|
|
Reserves
Category
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|
Proved Developed
Producing
|
636,829
|
584,298
|
38,074
|
34,551
|
381,103
|
339,176
|
|
Proved Developed
Non-Producing
|
1,603
|
1,510
|
64
|
54
|
3,527
|
3,267
|
|
Proved
Undeveloped
|
949,769
|
860,513
|
3,013
|
2,834
|
383,624
|
335,779
|
|
Total
Proved
|
1,588,202
|
1,446,322
|
41,151
|
37,440
|
768,254
|
678,222
|
|
Total
Probable
|
917,729
|
805,980
|
24,721
|
22,440
|
433,040
|
366,080
|
|
Total Proved plus
Probable
|
2,505,931
|
2,252,302
|
65,872
|
59,879
|
1,201,294
|
1,044,302
|
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2023, escalated price forecast.
|
|
(2)
|
"Gross Reserves" are
the total Company's working-interest share before the deduction of
any royalties and without including any royalty interest of the
Company.
|
|
(3)
|
"Net Reserves" are the
total Company's interest share after deducting royalties and
including any royalty interest.
|
|
(4)
|
Numbers may not add due
to rounding.
|
Summary of Before Tax Net Present Values
As at December 31, 2023
(1)
|
|
|
Before Tax Net
Present Value ($ millions)
|
|
|
|
Discount
Rate
|
|
Price
Deck
|
Reserves
Category
|
Gross Reserves
(Mboe)
|
0 %
|
5 %
|
10 %
|
15 %
|
|
Three Evaluator
Average
|
Proved Developed
Producing
|
381,103
|
10,035
|
8,130
|
6,792
|
5,868
|
|
Total
Proved
|
768,254
|
18,053
|
13,709
|
10,808
|
8,834
|
|
Total Proved plus
Probable
|
1,201,294
|
31,466
|
21,634
|
16,024
|
12,527
|
|
(1) Price deck based on
three evaluator's average (McDaniel, GLJ Ltd. and Sproule
Associates Ltd.) December 31, 2023, escalated price
forecast.
|
RESERVES RECONCILIATION
Gross Reserves (1) (2) (3) (4)
|
Tight
Oil
(Mbbls)
|
Light and Medium
Oil
(Mbbls)
|
Heavy
Oil
(Mbbls)
|
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
Proved
|
Probable
|
Proved
plus
Probable
|
Proved
|
Probable
|
Proved
plus
Probable
|
|
December 31,
2022
|
169,657
|
101,378
|
271,034
|
49,197
|
36,550
|
85,747
|
23,039
|
7,230
|
30,268
|
|
Extensions and
Improved Recovery
|
6,982
|
(1,517)
|
5,465
|
388
|
(149)
|
239
|
-
|
-
|
-
|
|
Technical
Revisions
|
2,183
|
(4,415)
|
(2,232)
|
1,643
|
(3,370)
|
(1,727)
|
(675)
|
(580)
|
(1,255)
|
|
Acquisitions
|
111,332
|
74,357
|
185,689
|
126
|
22
|
148
|
-
|
-
|
-
|
|
Dispositions
|
(29,001)
|
(27,601)
|
(56,602)
|
(376)
|
(190)
|
(565)
|
-
|
-
|
-
|
|
Economic
Factors
|
1,161
|
232
|
1,393
|
468
|
255
|
723
|
193
|
27
|
220
|
|
Production
|
(23,326)
|
-
|
(23,326)
|
(4,623)
|
-
|
(4,623)
|
(1,394)
|
-
|
(1,394)
|
|
December 31,
2023
|
238,989
|
142,434
|
381,422
|
46,823
|
33,119
|
79,942
|
21,163
|
6,677
|
27,840
|
|
Natural Gas
Liquids
(Mbbls)
|
Shale
Gas
(MMcf)
|
Natural
Gas
(MMcf)
|
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
Proved
|
Probable
|
Proved
plus
Probable
|
Proved
|
Probable
|
Proved
plus
Probable
|
|
December 31,
2022
|
146,482
|
52,892
|
199,374
|
521,688
|
175,480
|
697,167
|
39,279
|
23,599
|
62,877
|
|
Extensions and
Improved Recovery
|
18,017
|
28,950
|
46,968
|
80,000
|
196,761
|
276,761
|
158
|
(157)
|
-
|
|
Technical
Revisions
|
(4,919)
|
(5,213)
|
(10,132)
|
15,063
|
(5,454)
|
9,609
|
4,034
|
58
|
4,092
|
|
Acquisitions
|
55,257
|
25,209
|
80,466
|
1,082,973
|
581,238
|
1,664,211
|
2,684
|
927
|
3,610
|
|
Dispositions
|
(10,262)
|
(8,257)
|
(18,519)
|
(34,516)
|
(30,627)
|
(65,143)
|
(176)
|
(38)
|
(215)
|
|
Economic
Factors
|
305
|
153
|
458
|
1,165
|
331
|
1,497
|
(899)
|
333
|
(566)
|
|
Production
|
(15,160)
|
-
|
(15,160)
|
(78,170)
|
-
|
(78,170)
|
(3,928)
|
-
|
(3,928)
|
|
December 31,
2023
|
189,720
|
93,735
|
283,455
|
1,588,202
|
917,729
|
2,505,931
|
41,151
|
24,721
|
65,872
|
|
Total Oil
Equivalent
(Mboe)
|
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
|
December 31,
2022
|
481,868
|
231,230
|
713,098
|
|
Extensions and
Improved Recovery
|
38,747
|
60,052
|
98,799
|
|
Technical
Revisions
|
1,415
|
(14,477)
|
(13,062)
|
|
Acquisitions
|
347,657
|
196,616
|
544,273
|
|
Dispositions
|
(45,420)
|
(41,159)
|
(86,579)
|
|
Economic
Factors
|
2,172
|
778
|
2,949
|
|
Production
|
(58,185)
|
-
|
(58,185)
|
|
December 31,
2023
|
768,254
|
433,040
|
1,201,294
|
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2023, escalated price forecast.
|
|
(2)
|
"Gross Reserves" are
the total Company's working-interest share before the deduction of
any royalties and without including any royalty interest of the
Company.
|
|
(3)
|
Numbers may not add due
to rounding
|
Finding, Development and Acquisition Costs for 2023
|
Proved
Developed
Producing
|
Total
Proved
|
Total Proved
plus Probable
|
|
Capital ($
millions)
|
|
|
|
|
F&D
|
1,172
|
1,172
|
1,172
|
|
Change in FDC on
F&D
|
(14)
|
54
|
585
|
|
F&D Total (incl.
change in FDC)
|
1,159
|
1,226
|
1,757
|
|
FD&A
|
5,148
|
5,148
|
5,148
|
|
Change in FDC on
FD&A
|
32
|
2,952
|
4,520
|
|
FD&A Total (incl.
change in FDC)
|
5,180
|
8,101
|
9,669
|
|
|
|
|
|
Reserves Additions
(Mboe)
|
|
|
|
|
Reserves
Additions
|
32,354
|
42,334
|
88,687
|
|
Reserves Additions
incl. A&D
|
137,976
|
344,571
|
546,380
|
|
|
|
|
|
Costs
($/boe) & Recycle Ratio (1)(2)
|
|
|
|
|
F&D Total (incl.
change in FDC)
|
$35.82
|
$28.96
|
$19.82
|
|
Recycle
Ratio
|
1.2
|
1.5
|
2.2
|
|
FD&A Total (incl.
change in FDC)
|
$37.54
|
$23.51
|
$17.70
|
|
Recycle
Ratio
|
1.2
|
1.9
|
2.5
|
|
(1)
|
Numbers may not add due
to rounding.
|
|
(2)
|
F&D and FD&A
are calculated by dividing the identified capital expenditures by
the applicable reserves additions. These can include or exclude
changes in future development capital costs.
|
|
(3)
|
Recycle ratio is
calculated as operating netback before hedging divided by F&D
or FD&A costs. Based on a 2023 operating netback of $43.71 per
boe.
|
|
(4)
|
F&D and FD&A
costs includes capital expenditures associated with assets disposed
of during the year.
|
Future Development Capital
At year-end 2023, FDC for 2P reserves totaled $9.7 billion, compared to $5.1 billion at year-end 2022. The Company's FDC
increased by approximately $4.5
billion, primarily driven by location additions from its
Alberta Montney and Kaybob Duvernay plays.
|
Company Annual
Capital Expenditures ($ millions)
|
|
Year
|
Total
Proved
|
Total Proved
plus Probable
|
|
2024
|
1,233
|
1,372
|
|
2025
|
1,240
|
1,437
|
|
2026
|
1,462
|
1,585
|
|
2027
|
1,429
|
1,738
|
|
2028
|
888
|
1,708
|
|
2029
|
26
|
1,095
|
|
2030
|
11
|
603
|
|
2031
|
12
|
19
|
|
2032
|
13
|
19
|
|
2033
|
9
|
9
|
|
2034
|
7
|
9
|
|
2035
|
6
|
9
|
|
Subtotal
(1)
|
6,336
|
9,603
|
|
Remainder
|
21
|
62
|
|
Total
(1)
|
6,356
|
9,665
|
|
10%
Discounted
|
5,076
|
7,196
|
|
(1) Numbers may not add
due to rounding.
|
CONSOLIDATED FINANCIAL AND OPERATING HIGHLIGHTS
|
Three months ended
December 31
|
Year ended December
31
|
|
(Cdn$ millions except
per share and per boe amounts)
|
2023
|
2022
|
2023
|
2022
|
|
Financial
|
|
|
|
|
|
Cash flow from
operating activities
|
611.3
|
589.5
|
2,195.7
|
2,192.2
|
|
Adjusted funds flow
from operations (1)
|
574.5
|
522.8
|
2,339.1
|
2,232.4
|
|
Per share (1)
(2)
|
1.03
|
0.93
|
4.27
|
3.91
|
|
Net income
(loss)
|
951.2
|
(498.1)
|
570.3
|
1,483.4
|
|
Per share
(2)
|
1.70
|
(0.90)
|
1.04
|
2.60
|
|
Adjusted net earnings
from operations (1)
|
192.8
|
209.8
|
932.6
|
965.7
|
|
Per share (1)
(2)
|
0.34
|
0.38
|
1.70
|
1.69
|
|
Dividends
declared
|
68.3
|
118.8
|
211.9
|
200.6
|
|
Per share
(2)
|
0.120
|
0.215
|
0.387
|
0.360
|
|
Net debt
(1)
|
3,738.1
|
1,154.7
|
3,738.1
|
1,154.7
|
|
Net debt to adjusted
funds flow from operations (1) (3)
|
1.6
|
0.5
|
1.6
|
0.5
|
|
Weighted average shares
outstanding
|
|
|
|
|
|
Basic
|
556.5
|
555.2
|
545.6
|
566.7
|
|
Diluted
|
559.1
|
559.2
|
548.3
|
571.1
|
|
Operating
|
|
|
|
|
|
Average daily
production
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
102,350
|
90,759
|
102,906
|
91,679
|
|
NGLs
(bbls/d)
|
17,528
|
17,770
|
19,017
|
17,039
|
|
Natural gas
(mcf/d)
|
254,345
|
153,572
|
224,926
|
141,384
|
|
Total
(boe/d)
|
162,269
|
134,124
|
159,411
|
132,282
|
|
Average selling prices
(4)
|
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
95.78
|
103.42
|
97.23
|
115.72
|
|
NGLs
($/bbl)
|
28.08
|
38.55
|
29.86
|
45.02
|
|
Natural gas
($/mcf)
|
2.79
|
6.37
|
3.08
|
6.60
|
|
Total
($/boe)
|
67.82
|
82.39
|
70.67
|
93.06
|
|
Netback
($/boe)
|
|
|
|
|
|
Oil and gas
sales
|
67.82
|
82.39
|
70.67
|
93.06
|
|
Royalties
|
(8.17)
|
(10.61)
|
(9.13)
|
(12.45)
|
|
Operating
expenses
|
(14.24)
|
(14.50)
|
(14.62)
|
(14.77)
|
|
Transportation
expenses
|
(3.82)
|
(3.09)
|
(3.21)
|
(2.90)
|
|
Operating
netback
|
41.59
|
54.19
|
43.71
|
62.94
|
|
Realized gain (loss)
on commodity derivatives
|
0.17
|
(7.75)
|
0.19
|
(13.29)
|
|
Other
(5)
|
(3.28)
|
(4.07)
|
(3.70)
|
(3.41)
|
|
Adjusted funds flow
from operations netback (1)
|
38.48
|
42.37
|
40.20
|
46.24
|
|
Capital
Expenditures
|
|
|
|
|
|
Total capital
acquisitions (1) (6)
|
2,513.9
|
1.3
|
4,589.7
|
90.7
|
|
Total capital
dispositions (1) (6)
|
(602.4)
|
1.2
|
(613.6)
|
(283.6)
|
|
Development capital
expenditures
|
|
|
|
|
|
Drilling and
development
|
239.1
|
213.9
|
1,016.9
|
865.7
|
|
Facilities and
seismic
|
39.8
|
32.5
|
121.8
|
90.4
|
|
Total
|
278.9
|
246.4
|
1,138.7
|
956.1
|
|
Land
expenditures
|
2.2
|
4.2
|
33.6
|
19.2
|
|
(1)
|
Specified financial
measure that does not have any standardized meaning prescribed by
IFRS and, therefore, may not be comparable with the calculation of
similar measures presented by other entities. Refer to the
Specified Financial Measures section for further
information.
|
|
(2)
|
The per share amounts
(with the exception of dividends per share) are the per share –
diluted amounts.
|
|
(3)
|
Net debt to adjusted
funds flow from operations is calculated as the period end net debt
divided by the sum of adjusted funds flow from operations for the
trailing four quarters.
|
|
(4)
|
The average selling
prices reported are before realized derivatives and
transportation.
|
|
(5)
|
Other includes net
purchased products, general and administrative expenses, interest
on long-term debt, foreign exchange, cash-settled share-based
compensation and certain cash items and excludes transaction costs,
foreign exchange on US dollar long-term debt and certain non-cash
items.
|
|
(6)
|
Capital acquisitions
and dispositions, net represent total consideration for the
transactions, including long-term debt and working capital assumed,
and exclude transaction costs.
|
FINANCIAL AND OPERATING HIGHLIGHTS FROM CONTINUING
OPERATIONS
|
Three months ended
December 31
|
Year ended December
31
|
|
(Cdn$ millions except
per share and per boe amounts)
|
2023
|
2022
|
2023
|
2022
|
|
Financial
|
|
|
|
|
|
Cash flow from
operating activities from continuing operations
|
524.0
|
507.5
|
1,796.7
|
1,828.7
|
|
Adjusted funds flow
from continuing operations (1)
|
535.1
|
430.9
|
1,975.6
|
1,848.6
|
|
Per share (1)
(2)
|
0.96
|
0.77
|
3.60
|
3.24
|
|
Net income (loss) from
continuing operations
|
302.6
|
(577.8)
|
799.4
|
1,146.7
|
|
Per share
(2)
|
0.54
|
(1.04)
|
1.46
|
2.01
|
|
Adjusted net earnings
from continuing operations (1)
|
210.0
|
165.5
|
795.9
|
764.1
|
|
Per share (1)
(2)
|
0.37
|
0.30
|
1.45
|
1.34
|
|
Weighted average shares
outstanding
|
|
|
|
|
|
Basic
|
556.5
|
555.2
|
545.6
|
566.7
|
|
Diluted
|
559.1
|
559.2
|
548.3
|
571.1
|
|
Operating
|
|
|
|
|
|
Average daily
production from continuing operations
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
96,144
|
78,052
|
88,087
|
79,323
|
|
NGLs
(bbls/d)
|
16,023
|
13,427
|
15,026
|
13,079
|
|
Natural gas
(mcf/d)
|
248,306
|
139,206
|
211,275
|
128,099
|
|
Production from
continuing operations (boe/d)
|
153,551
|
114,680
|
138,326
|
113,752
|
|
Average selling prices
from continuing operations (3)
|
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
94.64
|
101.86
|
95.87
|
114.64
|
|
NGLs
($/bbl)
|
30.53
|
41.76
|
32.86
|
47.10
|
|
Natural gas
($/mcf)
|
2.83
|
6.35
|
3.06
|
6.48
|
|
Total
($/boe)
|
67.01
|
81.91
|
69.30
|
92.66
|
|
Netback from
Continuing Operations ($/boe)
|
|
|
|
|
|
Oil and gas
sales
|
67.01
|
81.91
|
69.30
|
92.66
|
|
Royalties
|
(7.50)
|
(8.73)
|
(7.43)
|
(10.49)
|
|
Operating
expenses
|
(14.48)
|
(15.19)
|
(15.26)
|
(15.13)
|
|
Transportation
expenses
|
(3.96)
|
(3.40)
|
(3.45)
|
(3.16)
|
|
Operating
netback
|
41.07
|
54.59
|
43.16
|
63.88
|
|
Realized gain (loss)
on commodity derivatives
|
0.18
|
(9.06)
|
0.31
|
(15.46)
|
|
Other
(4)
|
(3.37)
|
(4.69)
|
(4.34)
|
(3.90)
|
|
Adjusted funds flow
from continuing operations netback (1)
|
37.88
|
40.84
|
39.13
|
44.52
|
|
Capital
Expenditures
|
|
|
|
|
|
Development capital
expenditures from continuing operations
|
276.0
|
160.5
|
844.9
|
698.0
|
|
(1)
|
Specified financial
measure that does not have any standardized meaning prescribed by
IFRS and, therefore, may not be comparable with the calculation of
similar measures presented by other entities. Refer to the
Specified Financial Measures section for further
information.
|
|
(2)
|
The per share amounts
(with the exception of dividends per share) are the per share –
diluted amounts.
|
|
(3)
|
The average selling
prices reported are before realized derivatives and
transportation.
|
|
(4)
|
Other includes net
purchased products, general and administrative expenses, interest
on long-term debt, foreign exchange, cash-settled share-based
compensation and certain cash items and excludes transaction costs,
foreign exchange on US dollar long-term debt and certain non-cash
items.
|
Specified Financial Measures
Throughout this press release, the Company uses the terms "total
operating netback", "total operating netback from continuing
operations", "total operating netback from discontinued
operations", "total netback", "total netback from continuing
operations", "total netback from discontinued operations",
"operating netback", "netback", "adjusted funds flow from
operations" (or "adjusted FFO"), "adjusted funds flow from
continuing operations", "adjusted funds flow from discontinued
operations", "excess cash flow", "adjusted working capital
(surplus) deficiency", "net debt", "enterprise value", "net debt to
adjusted funds flow from operations", "net debt as a percentage of
enterprise value", "adjusted net earnings from operations",
"adjusted net earnings from continuing operations", "adjusted net
earnings from continuing operations per share – diluted", "adjusted
net earnings from discontinued operations", "adjusted net earnings
from discontinued operations per share – diluted", "adjusted net
earnings from operations per share", "adjusted net earnings from
operations per share - diluted", "total capital acquisitions" and
"total capital dispositions". These terms do not have any
standardized meaning as prescribed by IFRS and, therefore, may not
be comparable with the calculation of similar measures presented by
other issuers. For information on the composition of these measures
and how the Company uses these measures, refer to the Specified
Financial Measures section of the Company's MD&A for the year
ended December 31, 2023, which
section is incorporated herein by reference, and available on
SEDAR+ at www.sedarplus.ca and on EDGAR at
www.sec.gov/edgar.
Adjusted funds flow from operations netback is a non-GAAP
financial ratio and is calculated as adjusted funds flow from
operations divided by total production. Adjusted funds flow from
operations netback is a common metric used in the oil and gas
industry and is used to measure operating results on a per boe
basis.
The following table reconciles oil and gas sales to total
operating netback and total netback from continuing operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Oil and gas
sales
|
946.7
|
|
864.2
|
|
10
|
|
3,499.0
|
|
3,847.0
|
|
(9)
|
|
|
Royalties
|
(105.9)
|
|
(92.1)
|
|
15
|
|
(375.3)
|
|
(435.5)
|
|
(14)
|
|
|
Operating
expenses
|
(204.5)
|
|
(160.3)
|
|
28
|
|
(770.5)
|
|
(628.2)
|
|
23
|
|
|
Transportation
expenses
|
(56.0)
|
|
(35.9)
|
|
56
|
|
(174.3)
|
|
(131.0)
|
|
33
|
|
|
Total operating netback
from continuing operations
|
580.3
|
|
575.9
|
|
1
|
|
2,178.9
|
|
2,652.3
|
|
(18)
|
|
|
Realized gain (loss) on
commodity derivatives
|
2.5
|
|
(95.6)
|
|
(103)
|
|
15.5
|
|
(641.8)
|
|
(102)
|
|
|
Total netback from
continuing operations
|
582.8
|
|
480.3
|
|
21
|
|
2,194.4
|
|
2,010.5
|
|
9
|
|
|
Other
(1)
|
(47.7)
|
|
(49.4)
|
|
(3)
|
|
(218.8)
|
|
(161.9)
|
|
35
|
|
|
Total adjusted funds
flow from continuing operations netback
|
535.1
|
|
430.9
|
|
24
|
|
1,975.6
|
|
1,848.6
|
|
7
|
|
|
(1) Other
includes net purchased products, general and administrative
expenses, interest on long-term debt, foreign exchange,
cash-settled share-based compensation and certain cash items and
excludes transaction costs, foreign exchange on US dollar long-term
debt and certain non-cash items.
|
The following table reconciles oil and gas sales to total
operating netback and total netback from discontinued
operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Oil and gas
sales
|
65.7
|
|
152.4
|
|
(57)
|
|
612.9
|
|
646.1
|
|
(5)
|
|
|
Royalties
|
(16.1)
|
|
(38.8)
|
|
(59)
|
|
(155.9)
|
|
(165.4)
|
|
(6)
|
|
|
Operating
expenses
|
(8.1)
|
|
(18.6)
|
|
(56)
|
|
(80.0)
|
|
(84.9)
|
|
(6)
|
|
|
Transportation
expenses
|
(1.0)
|
|
(2.2)
|
|
(55)
|
|
(12.2)
|
|
(8.8)
|
|
39
|
|
|
Total operating netback
from discontinued operations
|
40.5
|
|
92.8
|
|
(56)
|
|
364.8
|
|
387.0
|
|
(6)
|
|
|
Realized loss on
commodity derivatives
|
—
|
|
—
|
|
100
|
|
(4.5)
|
|
—
|
|
100
|
|
|
Total netback from
discontinued operations
|
40.5
|
|
92.8
|
|
(56)
|
|
360.3
|
|
387.0
|
|
(7)
|
|
|
Other
(1)
|
(1.1)
|
|
(0.9)
|
|
22
|
|
3.2
|
|
(3.2)
|
|
(200)
|
|
|
Total adjusted funds
flow from discontinued operations netback
|
39.4
|
|
91.9
|
|
(57)
|
|
363.5
|
|
383.8
|
|
(5)
|
|
|
(1) Other includes
general and administrative expenses, cash-settled share-based
compensation and certain cash items and excludes transaction costs
and certain non-cash items.
|
The following tables reconcile total operating netback and total
netback from continuing and discontinued operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Total operating netback
from continuing operations
|
580.3
|
|
575.9
|
|
1
|
|
2,178.9
|
|
2,652.3
|
|
(18)
|
|
|
Total operating netback
from discontinued operations
|
40.5
|
|
92.8
|
|
(56)
|
|
364.8
|
|
387.0
|
|
(6)
|
|
|
Total operating
netback
|
620.8
|
|
668.7
|
|
(7)
|
|
2,543.7
|
|
3,039.3
|
|
(16)
|
|
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Total netback from
continuing operations
|
582.8
|
|
480.3
|
|
21
|
|
2,194.4
|
|
2,010.5
|
|
9
|
|
|
Total netback from
discontinued operations
|
40.5
|
|
92.8
|
|
(56)
|
|
360.3
|
|
387.0
|
|
(7)
|
|
|
Total
netback
|
623.3
|
|
573.1
|
|
9
|
|
2,554.7
|
|
2,397.5
|
|
7
|
|
|
Other
(1)
|
(48.8)
|
|
(50.3)
|
|
(3)
|
|
(215.6)
|
|
(165.1)
|
|
31
|
|
|
Total adjusted funds
flow from operations netback
|
574.5
|
|
522.8
|
|
10
|
|
2,339.1
|
|
2,232.4
|
|
5
|
|
|
(1) Other includes net
purchased products, general and administrative expenses, interest
on long-term debt, foreign exchange, cash-settled share-based
compensation and certain cash items and excludes transaction costs,
foreign exchange on US dollar long-term debt and certain non-cash
items.
|
The following table reconciles dividends declared to base
dividends:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Dividends
declared
|
68.3
|
|
118.8
|
|
(43)
|
|
211.9
|
|
200.6
|
|
6
|
|
|
Dividend timing
adjustment (1)
|
—
|
|
(55.1)
|
|
(100)
|
|
55.2
|
|
(29.0)
|
|
(290)
|
|
|
Special
dividends
|
(11.4)
|
|
(19.4)
|
|
(41)
|
|
(47.7)
|
|
(19.4)
|
|
146
|
|
|
Base
dividends
|
56.9
|
|
44.3
|
|
28
|
|
219.4
|
|
152.2
|
|
44
|
|
|
(1) Dividends declared
where the declaration date and record date are in different
periods.
|
The following table reconciles cash flow from operating
activities to adjusted funds flow from operations and excess cash
flow:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
(1)
|
|
% Change
|
|
2023
|
|
2022
(1)
|
|
% Change
|
|
|
Cash flow from
operating activities
|
611.3
|
|
589.5
|
|
4
|
|
2,195.7
|
|
2,192.2
|
|
—
|
|
|
Changes in non-cash
working capital
|
(82.0)
|
|
(71.8)
|
|
14
|
|
54.9
|
|
15.0
|
|
266
|
|
|
Transaction
costs
|
31.8
|
|
1.8
|
|
1,667
|
|
48.5
|
|
5.1
|
|
851
|
|
|
Decommissioning
expenditures (2)
|
13.4
|
|
3.3
|
|
306
|
|
40.0
|
|
20.1
|
|
99
|
|
|
Adjusted funds flow
from operations
|
574.5
|
|
522.8
|
|
10
|
|
2,339.1
|
|
2,232.4
|
|
5
|
|
|
Development capital and
other expenditures
|
(292.1)
|
|
(264.9)
|
|
10
|
|
(1,220.5)
|
|
(1,027.4)
|
|
19
|
|
|
Payments on lease
liability
|
(4.6)
|
|
(5.1)
|
|
(10)
|
|
(20.8)
|
|
(20.4)
|
|
2
|
|
|
Decommissioning
expenditures
|
(13.4)
|
|
(3.3)
|
|
306
|
|
(40.0)
|
|
(20.1)
|
|
99
|
|
|
Unrealized gain (loss)
on equity derivative contracts
|
(5.7)
|
|
6.4
|
|
(189)
|
|
(29.3)
|
|
(2.9)
|
|
910
|
|
|
Transaction
costs
|
(31.8)
|
|
(1.8)
|
|
1,667
|
|
(48.5)
|
|
(5.1)
|
|
851
|
|
|
Other items
(3)
|
1.9
|
|
(2.7)
|
|
(170)
|
|
1.6
|
|
(4.3)
|
|
(137)
|
|
|
Excess cash
flow
|
228.8
|
|
251.4
|
|
(9)
|
|
981.6
|
|
1,152.2
|
|
(15)
|
|
|
(1) Comparative period
revised to reflect current period presentation.
|
|
(2) Excludes amounts
received from government grant programs.
|
|
(3) Other items exclude
net acquisitions and dispositions.
|
The following table reconciles cash flow from operating
activities from discontinued operations to adjusted funds flow from
discontinued operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Cash flow from
operating activities from discontinued operations
|
87.3
|
|
82.0
|
|
6
|
|
399.0
|
|
363.5
|
|
10
|
|
|
Changes in non-cash
working capital
|
(57.0)
|
|
9.4
|
|
(706)
|
|
(44.6)
|
|
19.8
|
|
(325)
|
|
|
Transaction
costs
|
8.7
|
|
0.5
|
|
1,640
|
|
8.7
|
|
0.5
|
|
1,640
|
|
|
Decommissioning
expenditures (1)
|
0.4
|
|
—
|
|
100
|
|
0.4
|
|
—
|
|
100
|
|
|
Adjusted funds flow
from discontinued operations
|
39.4
|
|
91.9
|
|
(57)
|
|
363.5
|
|
383.8
|
|
(5)
|
|
|
(1) Excludes amounts
received from government grant programs.
|
The following tables reconcile cash flow from operating
activities and adjusted funds flow from operations from continuing
and discontinued operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Cash flow from
operating activities from continuing operations
|
524.0
|
|
507.5
|
|
3
|
|
1,796.7
|
|
1,828.7
|
|
(2)
|
|
|
Cash flow from
operating activities from discontinued operations
|
87.3
|
|
82.0
|
|
6
|
|
399.0
|
|
363.5
|
|
10
|
|
|
Cash flow from
operating activities
|
611.3
|
|
589.5
|
|
4
|
|
2,195.7
|
|
2,192.2
|
|
—
|
|
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Adjusted funds flow
from continuing operations
|
535.1
|
|
430.9
|
|
24
|
|
1,975.6
|
|
1,848.6
|
|
7
|
|
|
Adjusted funds flow
from discontinued operations
|
39.4
|
|
91.9
|
|
(57)
|
|
363.5
|
|
383.8
|
|
(5)
|
|
|
Adjusted funds flow
from operations
|
574.5
|
|
522.8
|
|
10
|
|
2,339.1
|
|
2,232.4
|
|
5
|
|
Adjusted funds flow from operations per share - diluted is a
supplementary financial measure and is calculated as adjusted funds
flow from operations divided by the number of weighted average
diluted shares outstanding.
The following table reconciles adjusted working capital
(surplus) deficiency:
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
|
Accounts payable and
accrued liabilities
|
634.9
|
|
448.2
|
|
42
|
|
|
Dividends
payable
|
56.8
|
|
99.4
|
|
(43)
|
|
|
Long-term compensation
liability (1)
|
66.8
|
|
59.2
|
|
13
|
|
|
Cash
|
(17.3)
|
|
(289.9)
|
|
(94)
|
|
|
Accounts
receivable
|
(377.9)
|
|
(327.8)
|
|
15
|
|
|
Prepaids and
deposits
|
(87.8)
|
|
(65.5)
|
|
34
|
|
|
Other current assets
(2)
|
(79.2)
|
|
(18.7)
|
|
324
|
|
|
Adjusted working
capital (surplus) deficiency
|
196.3
|
|
(95.1)
|
|
(306)
|
|
|
(1) Includes current
portion of long-term compensation liability and is net of equity
derivative contracts.
|
|
(2) Includes deferred
consideration receivable and deposit on acquisition.
|
The following table reconciles long-term debt to net debt:
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
|
Long-term debt
(1)
|
3,566.3
|
|
1,441.5
|
|
147
|
|
|
Adjusted working
capital (surplus) deficiency
|
196.3
|
|
(95.1)
|
|
(306)
|
|
|
Unrealized foreign
exchange on translation of hedged US dollar long-term
debt
|
(24.5)
|
|
(191.7)
|
|
(87)
|
|
|
Net debt
|
3,738.1
|
|
1,154.7
|
|
224
|
|
|
(1) Includes current
portion of long-term debt.
|
The following table reconciles net income (loss) to adjusted net
earnings from operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Net income
(loss)
|
951.2
|
|
(498.1)
|
|
(291)
|
|
570.3
|
|
1,483.4
|
|
(62)
|
|
|
Amortization of E&E
undeveloped land
|
12.0
|
|
2.8
|
|
329
|
|
30.9
|
|
15.2
|
|
103
|
|
|
Impairment (impairment
reversal)
|
48.4
|
|
1,056.3
|
|
(95)
|
|
822.2
|
|
(428.6)
|
|
(292)
|
|
|
Unrealized derivative
(gains) losses
|
(98.5)
|
|
(53.7)
|
|
83
|
|
56.9
|
|
(171.0)
|
|
(133)
|
|
|
Unrealized foreign
exchange (gain) loss on translation of hedged US dollar long-term
debt
|
(95.4)
|
|
(16.1)
|
|
493
|
|
(168.6)
|
|
27.7
|
|
(709)
|
|
|
Net (gain) loss on
capital dispositions
|
13.7
|
|
0.2
|
|
6,750
|
|
9.6
|
|
(25.9)
|
|
(137)
|
|
|
Reclassification of
cumulative foreign currency translation of discontinued foreign
operations
|
(621.7)
|
|
—
|
|
100
|
|
(621.7)
|
|
—
|
|
100
|
|
|
Deferred tax
adjustments
|
(16.9)
|
|
(281.6)
|
|
(94)
|
|
233.0
|
|
64.9
|
|
259
|
|
|
Adjusted net earnings
from operations
|
192.8
|
|
209.8
|
|
(8)
|
|
932.6
|
|
965.7
|
|
(3)
|
|
The following table reconciles net income (loss) from
discontinued operations to adjusted net earnings from discontinued
operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Net income (loss) from
discontinued operations
|
648.6
|
|
79.7
|
|
714
|
|
(229.1)
|
|
336.7
|
|
(168)
|
|
|
Amortization of E&E
undeveloped land
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
100
|
|
|
Impairment (impairment
reversal)
|
—
|
|
—
|
|
—
|
|
728.4
|
|
(71.3)
|
|
(1,122)
|
|
|
Unrealized derivative
(gains) losses
|
(5.1)
|
|
—
|
|
100
|
|
18.9
|
|
—
|
|
100
|
|
|
Net loss on capital
dispositions
|
9.0
|
|
0.2
|
|
4,400
|
|
9.0
|
|
0.2
|
|
4,400
|
|
|
Reclassification of
cumulative foreign currency translation of discontinued foreign
operations
|
(621.7)
|
|
—
|
|
100
|
|
(621.7)
|
|
—
|
|
100
|
|
|
Deferred tax
adjustments
|
(48.0)
|
|
(35.6)
|
|
35
|
|
231.2
|
|
(64.0)
|
|
(461)
|
|
|
Adjusted net earnings
(loss) from discontinued operations
|
(17.2)
|
|
44.3
|
|
(139)
|
|
136.7
|
|
201.6
|
|
(32)
|
|
The following table reconciles adjusted net earnings from
continuing and discontinued operations:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Adjusted net earnings
from continuing operations
|
210.0
|
|
165.5
|
|
27
|
|
795.9
|
|
764.1
|
|
4
|
|
|
Adjusted net earnings
(loss) from discontinued operations
|
(17.2)
|
|
44.3
|
|
(139)
|
|
136.7
|
|
201.6
|
|
(32)
|
|
|
Adjusted net earnings
from operations
|
192.8
|
|
209.8
|
|
(8)
|
|
932.6
|
|
965.7
|
|
(3)
|
|
The following table reconciles capital acquisitions, net of cash
acquired to total capital acquisitions:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Capital acquisitions,
net of cash acquired
|
1,540.4
|
|
1.3
|
|
118,392
|
|
3,616.2
|
|
90.7
|
|
3,887
|
|
|
Common shares issued on
capital acquisition
|
493.0
|
|
—
|
|
100
|
|
493.0
|
|
—
|
|
100
|
|
|
Working capital
acquired through capital acquisition
|
116.7
|
|
—
|
|
100
|
|
116.7
|
|
—
|
|
100
|
|
|
Long-term debt acquired
through capital acquisition
|
363.8
|
|
—
|
|
100
|
|
363.8
|
|
—
|
|
100
|
|
|
Total capital
acquisitions
|
2,513.9
|
|
1.3
|
|
193,277
|
|
4,589.7
|
|
90.7
|
|
4,960
|
|
The following table reconciles capital dispositions to total
capital dispositions:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
|
($ millions)
|
2023
|
|
2022
|
|
% Change
|
|
2023
|
|
2022
|
|
% Change
|
|
|
Capital
dispositions
|
(593.3)
|
|
1.2
|
|
(49,542)
|
|
(604.5)
|
|
(283.6)
|
|
113
|
|
|
Working capital
disposed through capital disposition
|
(9.1)
|
|
—
|
|
100
|
|
(9.1)
|
|
—
|
|
100
|
|
|
Total capital
dispositions
|
(602.4)
|
|
1.2
|
|
(50,300)
|
|
(613.6)
|
|
(283.6)
|
|
116
|
|
Total return of capital is a supplementary financial measure and
is comprised of base dividends, special dividends and share
repurchases, adjusted for the timing of special dividend
payments.
Excess cash flow for 2024 is a forward-looking non-GAAP measures
and is calculated consistently with the measures disclosed in the
Company's MD&A. Refer to the Specified Financial Measures
section of the Company's MD&A for the year ended December 31, 2023.
Recycle ratio is a non-GAAP ratio and is calculated as operating
netback before hedging divided by FD&A costs. Recycle ratios
may not be comparable year-over-year given significant changes
executed over the last three years. Recycle ratio is a common
metric used in the oil and gas industry and is used to measure
profitability on a per boe basis.
|
Proved
Developed
Producing
|
Total
Proved
|
Total Proved
plus Probable
|
|
2022 Recycle
Ratios
|
|
|
|
|
F&D Total (incl.
change in FDC)
|
3.1
|
2.5
|
2.2
|
|
FD&A Total (incl.
change in FDC)
|
3.4
|
2.8
|
2.3
|
In 2022, the Company's Kaybob Duvernay asset generated a recycle
ratio of 4.5 times based on F&D including FDC.
Management believes the presentation of the specified financial
measures above provide useful information to investors and
shareholders as the measures provide increased transparency and the
ability to better analyze performance against prior periods on a
comparable basis.
Notice to US Readers
The oil and natural gas reserves contained in this press release
have generally been prepared in accordance with Canadian disclosure
standards, which are not comparable in all respects of United States or other foreign disclosure
standards. For example, the United States Securities and Exchange
Commission (the "SEC") generally permits oil and gas issuers, in
their filings with the SEC, to disclose only proved reserves (as
defined in SEC rules), but permits the optional disclosure of
"probable reserves" and "possible reserves" (each as defined in SEC
rules). Canadian securities laws require oil and gas issuers, in
their filings with Canadian securities regulators, to disclose not
only proved reserves (which are defined differently from the SEC
rules) but also probable reserves and permits optional disclosure
of "possible reserves", each as defined in NI 51-101. Accordingly,
"proved reserves", "probable reserves" and "possible reserves"
disclosed in this news release may not be comparable to US
standards, and in this news release, Crescent Point has disclosed
reserves designated as "proved plus probable reserves". Probable
reserves are higher-risk and are generally believed to be less
likely to be accurately estimated or recovered than proved
reserves. "Possible reserves" are higher risk than "probable
reserves" and are generally believed to be less likely to be
accurately estimated or recovered than "probable reserves".
In addition, under Canadian disclosure requirements and industry
practice, reserves and production are reported using gross volumes,
which are volumes prior to deduction of royalties and similar
payments. The SEC rules require reserves and production to be
presented using net volumes, after deduction of applicable
royalties and similar payments. Moreover, Crescent Point has
determined and disclosed estimated future net revenue from its
reserves using forecast prices and costs, whereas the SEC rules
require that reserves be estimated using a 12-month average price,
calculated as the arithmetic average of the first-day-of-the-month
price for each month within the 12-month period prior to the end of
the reporting period. Consequently, Crescent Point's reserve
estimates and production volumes in this news release may not be
comparable to those made by companies using United States reporting and disclosure
standards. Further, the SEC rules are based on unescalated costs
and forecasts.
All amounts in the news release are stated in Canadian dollars
unless otherwise specified.
Forward-Looking Statements
Any "financial outlook" or "future oriented financial
information" in this press release, as defined by applicable
securities legislation has been approved by management of Crescent
Point. Such financial outlook or future oriented financial
information is provided for the purpose of providing information
about management's current expectations and plans relating to the
future. Readers are cautioned that reliance on such information may
not be appropriate for other purposes.
Certain statements contained in this press release constitute
"forward-looking statements" within the meaning of section 27A of
the Securities Act of 1933 and section 21E of the Securities
Exchange Act of 1934 and "forward-looking information" for the
purposes of Canadian securities regulation (collectively,
"forward-looking statements"). The Company has tried to identify
such forward-looking statements by use of such words as "could",
"should", "can", "anticipate", "expect", "believe", "will", "may",
"intend", "projected", "sustain", "continues", "strategy",
"potential", "projects", "grow", "take advantage", "estimate",
"well-positioned" and other similar expressions, but these words
are not the exclusive means of identifying such statements.
In particular, this press release contains forward-looking
statements pertaining, among other things, to the following:
premium inventory of over 20 years and enhanced excess cash flow
profile; dividend expectations; excess cash flow of $830 million expected in 2024 at US$75 WTI, with 60 percent returned to
shareholders; five-year plan expected to generate strong per share
growth and cumulative excess cash flow of $4.7 billion at US$70 WTI; enhanced the long-term sustainability
and excess cash flow per share; strategic priorities; the extent
and benefits of hedging; diversified pricing exposure for natural
gas; dividend expectations; timing for the closing of the sale of
Swan Hills and Turner Valley assets; acceleration of
high-return inventory in the Kaybob Duvernay; strong drilling
economics of the OHML program; low base decline rate of
approximately 15 percent in its Saskatchewan assets, further enhancing its
strong excess cash flow generation from these assets; opportunities
to further enhance shareholder value by realizing potential cost
efficiencies and productivity enhancements; unbooked locations and
future NAV and reserves growth; reserves life index; 2P NAV; the
budget remains disciplined and flexible, with a continued focus on
allocating capital to the highest-return assets; 2024 budget
allocation by area; 2024 budget, including base dividend, remains
fully funded at approximately US$55/bbl WTI; additional efficiencies and
improved productivity by further enhancing drilling and completions
optimization, including optimizing wells drilled per section on
Alberta Montney assets and drilling longer lateral wells in the
Kaybob Duvernay; advancement of OHML drilling and decline
mitigation programs; 2024 budget is expected to generate
significant excess cash flow of approximately $830 million at approximately US$75/bbl WTI and $2.30/Mcf AECO for the full year; plans to
continue allocating 60 percent of excess cash flow to shareholders
through the base dividend and share repurchases, with the remaining
40 percent directed toward the balance sheet; leverage ratio is
expected to be approximately 1.2 times at year-end 2024, based on
the commodity price assumptions stated herein; NCIB expectations;
2024 funds flow sensitivities; plans to increase the percentage of
excess cash flow returned to shareholders over time as balance
sheet strengthens; strategy focused on delivering meaningful and
sustainable total returns through a combination of return of
capital, per-share growth and balance sheet strength; Crescent
Point's 2024 production and development capital expenditures
guidance; and other information for Crescent Point's 2024 guidance,
including capitalized administration, reclamation activities,
capital lease payments, annual operating expenses and royalties;
and return of capital outlook, including base dividend, and the
additional return of capital targeted as a percentage of excess
cash flow.
Statements relating to "reserves" are also deemed to be
forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the reserves
described exist in the quantities predicted or estimated and that
the reserves can be profitably produced in the future. Actual
reserve values may be greater than or less than the estimates
provided herein.
Unless otherwise noted, reserves referenced herein are given as
at December 31, 2023. Also, estimates
of reserves and future net revenue for individual properties may
not reflect the same confidence level as estimates and future net
revenue for all properties due to the effect of aggregation. All
required reserve information for the Company is contained in its
Annual Information Form for the year ended December 31, 2023, which is accessible at
www.sedarplus.ca.
With respect to disclosure contained herein regarding resources
other than reserves, there is uncertainty that it will be
commercially viable to produce any portion of the resources and
there is significant uncertainty regarding the ultimate
recoverability of such resources.
All forward-looking statements are based on Crescent Point's
beliefs and assumptions based on information available at the time
the assumption was made. Crescent Point believes that the
expectations reflected in these forward-looking statements are
reasonable but no assurance can be given that these expectations
will prove to be correct and such forward-looking statements
included in this report should not be unduly relied upon. By their
nature, such forward-looking statements are subject to a number of
risks, uncertainties and assumptions, which could cause actual
results or other expectations to differ materially from those
anticipated, expressed or implied by such statements, including
those material risks discussed in the Company's Annual Information
Form for the year ended December 31,
2023 under "Risk Factors" and our Management's Discussion
and Analysis for the year ended December 31,
2023, under the headings "Risk Factors" and "Forward-Looking
Information". The material assumptions are disclosed in the
Management's Discussion and Analysis for the year ended
December 31, 2023, under the headings
"Overview", "Commodity Derivatives", "Liquidity and Capital
Resources" and "Guidance". In addition, risk factors include:
financial risk of marketing reserves at an acceptable price given
market conditions; volatility in market prices for oil and natural
gas, decisions or actions of OPEC and non-OPEC countries in respect
of supplies of oil and gas; delays in business operations or
delivery of services due to pipeline restrictions, rail blockades,
outbreaks, pandemics, and blowouts; the risk of carrying out
operations with minimal environmental impact; industry conditions
including changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced; uncertainties associated with estimating
oil and natural gas reserves; risks and uncertainties related to
oil and gas interests and operations on Indigenous lands; economic
risk of finding and producing reserves at a reasonable cost;
uncertainties associated with partner plans and approvals;
operational matters related to non-operated properties; increased
competition for, among other things, capital, acquisitions of
reserves and undeveloped lands; competition for and availability of
qualified personnel or management; incorrect assessments of the
value and likelihood of acquisitions and dispositions, and
exploration and development programs; unexpected geological,
technical, drilling, construction, processing and transportation
problems; the impacts of drought, wildfires and severe weather
events; availability of insurance; fluctuations in foreign exchange
and interest rates; stock market volatility; general economic,
market and business conditions, including uncertainty in the demand
for oil and gas and economic activity in general; changes in
interest rates and inflation; uncertainties associated with
regulatory approvals; geopolitical conflicts, including the Russian
invasion of Ukraine and the
conflict between Israel and Hamas;
uncertainty of government policy changes; the impact of the
implementation of the Canada-United States-Mexico Agreement;
uncertainty regarding the benefits and costs of dispositions;
failure to complete acquisitions and dispositions; uncertainties
associated with credit facilities and counterparty credit risk; and
changes in income tax laws, tax laws, crown royalty rates and
incentive programs relating to the oil and gas industry; and other
factors, many of which are outside the control of the Company. The
impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as
these are interdependent and Crescent Point's future course of
action depends on management's assessment of all information
available at the relevant time.
Included in this presentation are Crescent Point's 2024 guidance
in respect of capital expenditures and average annual production
and 5-year outlook information which are based on various
assumptions as to production levels, commodity prices and other
assumptions and are provided for illustration only and are based on
budgets and forecasts that have not been finalized and are subject
to a variety of contingencies including prior years' results. The
Company's return of capital framework is based on certain facts,
expectations and assumptions that may change and, therefore, this
framework may be amended as circumstances necessitate or require.
To the extent such estimates constitute a "financial outlook" or
"future oriented financial information" in this presentation, as
defined by applicable securities legislation, such information has
been approved by management of Crescent Point. Such financial
outlook or future oriented financial information is provided for
the purpose of providing information about management's current
expectations and plans relating to the future. Readers are
cautioned that reliance on such information may not be appropriate
for other purposes.
Additional information on these and other factors that could
affect Crescent Point's operations or financial results are
included in Crescent Point's reports on file with Canadian and U.S.
securities regulatory authorities. Readers are cautioned not to
place undue reliance on this forward-looking information, which is
given as of the date it is expressed herein. Crescent Point
undertakes no obligation to update publicly or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise, unless required to do so pursuant to
applicable law. All subsequent forward-looking statements, whether
written or oral, attributable to Crescent Point or persons acting
on the Company's behalf are expressly qualified in their entirety
by these cautionary statements.
Product Type Production Information
The Company's annual aggregate production for 2023 and 2022, the
aggregate average production for fourth quarter of 2023 and 2022,
and the references to "natural gas", "crude oil" and "condensate"
reported in this Press Release consist of the following product
types, as defined in NI 51-101 and using a conversion ratio of 6
mcf : 1 bbl where applicable:
|
Three months ended
December 31
|
Year ended December
31
|
|
2023
|
2022
|
2023
|
2022
|
|
Light & Medium
Crude Oil (bbl/d)
|
12,198
|
13,671
|
12,665
|
14,274
|
|
Heavy Crude Oil
(bbl/d)
|
3,795
|
3,870
|
3,818
|
4,027
|
|
Tight Oil
(bbl/d)
|
56,657
|
40,068
|
49,779
|
42,134
|
|
Total Crude Oil
(bbl/d)
|
72,650
|
57,609
|
66,262
|
60,435
|
|
|
|
|
|
|
NGLs (bbl/d)
|
39,517
|
33,871
|
36,851
|
31,967
|
|
|
|
|
|
|
Shale Gas
(mcf/d)
|
236,926
|
128,437
|
200,514
|
117,617
|
|
Conventional Natural
Gas (mcf/d)
|
11,380
|
10,769
|
10,761
|
10,482
|
|
Total Natural Gas
(mcf/d)
|
248,306
|
139,206
|
211,275
|
128,099
|
|
|
|
|
|
|
Total production from
continuing operations (boe/d)
|
153,551
|
114,681
|
138,326
|
113,752
|
|
Three months ended
December 31
|
Year ended December
31
|
|
2023
|
2022
|
2023
|
2022
|
|
Light & Medium
Crude Oil (bbl/d)
|
12,198
|
13,671
|
12,665
|
14,274
|
|
Heavy Crude Oil
(bbl/d)
|
3,795
|
3,870
|
3,818
|
4,027
|
|
Tight Oil
(bbl/d)
|
62,512
|
52,095
|
63,906
|
53,861
|
|
Total Crude Oil
(bbl/d)
|
78,505
|
69,636
|
80,389
|
72,162
|
|
|
|
|
|
|
NGLs (bbl/d)
|
41,373
|
38,893
|
41,534
|
36,556
|
|
|
|
|
|
|
Shale Gas
(mcf/d)
|
242,965
|
142,803
|
214,165
|
130,902
|
|
Conventional Natural
Gas (mcf/d)
|
11,380
|
10,769
|
10,761
|
10,482
|
|
Total Natural Gas
(mcf/d)
|
254,345
|
153,572
|
224,926
|
141,384
|
|
|
|
|
|
|
Total average daily
production (boe/d)
|
162,269
|
134,124
|
159,411
|
132,282
|
NI 51-101 includes condensate within the natural gas liquids
(NGLs) product type. The Company has disclosed condensate as
combined with crude oil and/or separately from other natural gas
liquids in this press release since the price of condensate as
compared to other natural gas liquids is currently significantly
higher and the Company believes that this crude oil and condensate
presentation provides a more accurate description of its operations
and results therefore.
DEFINITIONS
Decline rate is the reduction in rate of production
from one period to the next. This rate is usually expressed on an
annual basis.
Finding and development (F&D) costs are
calculated by dividing the development capital expenditures by the
applicable reserves additions. F&D costs can include or exclude
changes to future development capital costs.
Finding, development and acquisition costs
(FD&A) are equivalent to F&D costs plus the costs
of acquiring and disposing particular assets.
Future development capital (FDC) reflects the best
estimate of the cost required to bring undeveloped proved and
probable reserves on production. Changes in FDC can result
from acquisition and disposition activities, development plans
or changes in capital efficiencies due to inflation or reductions
in service costs and/or improvements to drilling and completion
methods.
Net asset value (NAV), 2P NAV, 1P NAV or PDP NAV is a
snapshot in time as at year-end, and is based on the Company's
reserves evaluated using the independent evaluators forecast for
future prices, costs and foreign exchange rates. The Company's NAV
is calculated on a before tax basis and is the sum of the present
value of proved and probable reserves, proved reserves or proved
developed producing reserves, respectively, based on three
evaluators' average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2023 escalated
price forecast, the fair value for the Company's oil and gas hedges
based on such December 31, 2023
escalated price forecast, the value of undeveloped land and
seismic, and less outstanding net debt. The NAV per share is
calculated on a fully diluted basis and a discount of 10
percent.
N1 51-101 means "National Instrument 51-101 -
Standards for Disclosure for Oil and Gas Activities".
Recycle Ratio is calculated as operating netback
divided by F&D or FD&A and is based on the netbacks
reported above.
Reserves are estimated remaining quantities of oil
and natural gas and related substances anticipated to be
recoverable from known accumulations, as of a given date, based on
the analysis of drilling, geological, geophysical and engineering
data; the use of established technology; and specified economic
conditions, which are generally accepted as being reasonable.
Proved reserves are reserves estimated to have a high degree of
certainty of recoverability. Probable reserves are less certain to
be recoverable than proved reserves and possible reserves are less
certain than probable reserves.
Reserve Life Index is calculated as proved plus
probable reserves divided by production.
Reserves and Drilling Data
The reserves information contained in this press release has
been prepared in accordance with NI 51-101.
Where applicable, a barrels of oil equivalent ("boe") conversion
rate of six thousand cubic feet of natural gas to one barrel
of oil equivalent (6mcf:1bbl) has been used based on an energy
equivalent conversion method primarily applicable at the burner
tip. Given that the value ratio based on the current price of crude
oil as compared to natural gas is significantly different than the
energy equivalency of the 6:1 conversion ratio, utilizing the 6:1
conversion ratio may be misleading as an indication of value.
Initial production is for a limited time frame only (30 days)
and may not be indicative of future performance. Peak IP30 refers
to the 30 consecutive days with the highest production rates since
a well has come on production and may not be indicative of future
performance. For additional product type information for our major
operating areas, refer to our Reserves Report. Booked type well
data was audited by independent reserves evaluator, McDaniel,
effective December 31, 2023.
This press release contains metrics commonly used in the oil and
natural gas industry, including "netbacks", "F&D costs",
"FD&A costs", "FDC", "NAV", "recycle ratio", "replacement rate"
and "reserve life index". These terms do not have a standardized
meaning and may not be comparable to similar measures presented by
other companies and, therefore, should not be used to make such
comparisons. Readers are cautioned as to the reliability of oil and
gas metrics used in this press release.
F&D costs, including change in FDC, and FD&A costs have
been presented in this news release because they provide a useful
measure of capital efficiency. F&D costs and FD&A costs,
including land, facility and seismic expenditures and excluding
change in FDC have also been presented in this news release because
they provide a useful measure of capital efficiency.
Management uses recycle ratio for its own performance
measurements and to provide shareholders with measures to compare
the Company's performance over time.
NAV is an estimate of the value of the Company's net assets.
Netback is calculated on a per boe basis as oil and gas sales,
less royalties, operating and transportation expenses and realized
derivative gains and losses. Netback is used by management to
measure operating results on a per boe basis to better analyze
performance against prior periods on a comparable basis.
Replacement rate is the amount of oil added to the Company's 2P
reserves, divided by production. It is a measure of the ability of
the Company to sustain production levels.
Reserve Life Index is calculated as set forth above, it is a
measure of the longevity of the Company's reserves.
There are numerous uncertainties inherent in estimating
quantities of crude oil, natural gas and NGLs reserves and the
future cash flows attributed to such reserves. The reserve and
associated cash flow information set forth above are estimates
only. In general, estimates of economically recoverable crude oil,
natural gas and NGLs reserves and the future net cash flows
therefrom are based upon a number of variable factors and
assumptions, such as historical production from the properties,
production rates, ultimate reserve recovery, timing and amount of
capital expenditures, marketability of oil and natural gas, royalty
rates, the assumed effects of regulation by governmental agencies
and future operating costs, all of which may vary materially. For
these reasons, estimates of the economically recoverable crude oil,
NGLs and natural gas reserves attributable to any particular group
of properties, classification of such reserves based on risk of
recovery and estimates of future net revenues associated with
reserves prepared by different engineers, or by the same engineers
at different times, may vary. The Company's actual production,
revenues, taxes and development and operating expenditures with
respect to its reserves will vary from estimates thereof and such
variations could be material.
Individual properties may not reflect the same confidence level
as estimates of reserves for all properties due to the effects of
aggregation. This press release contains estimates of the net
present value of the Company's future net revenue from our
reserves. Such amounts do not represent the fair market value of
our reserves. The recovery and reserve estimates of the Company's
reserves provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered.
This presentation references more than 20 years of premium
locations in corporate inventory, which amount includes over 4,000
booked and unbooked locations. Unbooked future drilling locations
are not associated with any reserves or contingent resources and
have been identified by the Company and have not been audited by
independent qualified reserves evaluators. The over 4,000 premium
locations consist of: (A) approximately 1,950 Kaybob Duvernay and
Alberta Montney premium locations, of which 596 are proved plus
probable locations, as assigned in the company's year end 2023
independent reserves evaluation in accordance with NI 51-101 and
the COGE Handbook, and an incremental 1,357 are unbooked locations
and (B) over 2,000 Saskatchewan
premium locations, of which 1,189 are proved plus probable
locations, as assigned in the company's year end 2023 independent
reserves evaluation in accordance with NI 51-101 and the COGE
Handbook; and an incremental 882 are unbooked locations.
The peak 30-day rates for the 20 wells brought on stream in the
Kaybob Duvernay in 2023 ranging consisted of average product types
of 74% condensate, 9% NGLs and 17% shale gas within the Volatile
Oil window and 43% condensate, 18% NGLs and 39% shale gas within
the Liquids-Rich window.
The average peak 30-day rates for the 25 wells brought on stream
in the Alberta Montney since initial entry into the play in second
quarter 2023 generated the following average product types: 72%
light and medium crude oil, 4% NGLs and 24% shale gas per well in
Gold Creek West; 52% light and medium crude oil, 9% NGLs and 39%
shale gas per well in Gold Creek and 82% light and medium crude
oil, 3% NGLs and 15% shale gas per well in Karr East.
The Company's most recent OHML achieved a peak-30 day rate of
over 300 bbl/d (100% light and medium crude oil).
The reserve data provided in this news release presents only a
portion of the disclosure required under National Instrument
51-101. All of the required information will be contained in the
Company's Annual Information Form for the year ended December 31, 2023, which will be filed on SEDAR+
(accessible at www.sedarplus.ca and EDGAR (accessible at
www.sec.gov/edgar.shtml) on or before February 29, 2024 and further supplemented by
Material Change Reports as applicable.
FOR MORE INFORMATION ON CRESCENT POINT ENERGY, PLEASE
CONTACT:
Shant Madian, Vice
President, Capital Markets
Sarfraz Somani, Manager,
Investor Relations
Telephone: (403) 693-0020 Toll-free (US and Canada): 888-693-0020 Fax: (403)
693-0070
Address: Crescent Point Energy Corp. Suite 2000, 585 - 8th
Avenue S.W. Calgary AB T2P 1G1
www.crescentpointenergy.com
Crescent Point shares are traded on the Toronto Stock Exchange
and New York Stock Exchange under the symbol CPG.
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SOURCE Crescent Point Energy Corp.