CALGARY,
AB, March 2, 2023 /PRNewswire/ - 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,
2022.
KEY HIGHLIGHTS
- Generated significant excess cash flow of approximately
$1.2 billion, driven by a strong
netback asset base.
- Reduced net debt by approximately $850
million, or over 40 percent.
- Returned nearly $500 million to
shareholders through dividends and share repurchases totaling over
five percent of the float.
- Increased drilling inventory in the Kaybob Duvernay to over 20
years while optimizing portfolio through non-core
dispositions.
- Increased NAV per share by 30 to 35 percent across all
categories and replaced 113 percent of 2022 production on a 2P
basis.
- Generated strong FD&A recycle ratios, including change in
FDC, of 3.4 and 2.3 times based on PDP and 2P reserves.
- Achieved best safety scores in company history and remain on
track to meet or exceed land, emissions and water targets.
- Expect to generate significant excess cash flow of
approximately $1.0 billion in 2023 at
US$75/bbl WTI.
"Our success in 2022 demonstrates our ability to execute our
long-term strategy of capital discipline, balance sheet strength,
sustainability and returning capital to our shareholders," said
Craig Bryksa, President and CEO of
Crescent Point. "Since beginning this transformation five years
ago, we have delivered consistent and compounding benefits for our
shareholders. Our multi-basin portfolio generates significant
excess cash flow driven by industry leading netbacks, which we have
further enhanced through the addition of our Kaybob Duvernay asset.
This, combined with our superior technical, operational and safety
performance, positions us to deliver substantial returns to
shareholders now and well into the future."
FINANCIAL HIGHLIGHTS
- Adjusted funds flow totaled over $2.2
billion for the year ended December
31, 2022, or $3.91 per share
diluted, driven by a strong operating netback of $62.94 per boe. In fourth quarter, adjusted funds
flow totaled $522.8 million, or
$0.93 per share diluted.
- For the year ended December 31,
2022, development capital expenditures, which included
drilling and development, facilities and seismic costs, totaled
$956.1 million, in-line with the
Company's annual guidance of $950
million.
- Net debt as at December 31, 2022
was less than $1.2 billion,
reflecting a reduction of $850.3
million, or over 40 percent since the beginning of 2022. On
January 11, 2023, Crescent Point
closed its acquisition of additional Kaybob Duvernay assets, which
included a net cash payment of approximately $370 million. As of the acquisition close,
Crescent Point's net debt was approximately $1.5 billion.
- For the year ended December 31,
2022, Crescent Point reported net income of approximately
$1.5 billion. The Company's 2022 net
income includes the positive contribution of a $0.4 billion ($0.3
billion after-tax) non-cash impairment reversal due to
higher commodity prices, net of increased cost assumptions due to
inflation.
- As part of its risk management program, Crescent Point has
hedged approximately 15 percent of its total production in 2023,
net of royalty interest, including over 20 percent in the first
half of the year.
RETURN OF CAPITAL HIGHLIGHTS
- In July 2022, the Company updated
its return of capital framework to target the return of up to 50
percent of its discretionary excess cash flow, in addition to its
base dividend, through a combination of share repurchases and
special dividends.
- The Company's total return of capital to its shareholders in
2022 was $483.3 million comprised of
base dividends, share repurchases and special dividends. This
included $287.8 million in the second
half of the year under its updated framework, or approximately 60
percent of its excess cash flow.
- During fourth quarter, Crescent Point repurchased 8.6 million
shares for $86.6 million, bringing
total repurchases to 31.3 million shares for $294.2 million in 2022, representing over five
percent of its public float. The Company remains active on its
normal course issuer bid ("NCIB") and has repurchased 3.2 million
shares for $30.0 million to-date in
2023. Crescent Point has filed notice with the Toronto Stock
Exchange ("TSX") of the intention to renew its NCIB, which is due
to expire on March 8, 2023.
- The Company's Board of Directors ("Board") has declared a
special cash dividend, based on fourth quarter 2022 results, of
$0.032 per share payable on
March 17, 2023, to shareholders of
record as of the close of business on March
10, 2023.
- As previously announced, Crescent Point's Board approved and
declared a first quarter 2023 dividend of $0.10 per share, payable on April 3, 2023 to shareholders of record on
March 15, 2023. This equates to an
annualized dividend of $0.40 per
share, an increase of 25 percent from the prior level or 122
percent since the beginning of 2022.
Adjusted funds flow,
adjusted funds flow per share diluted, excess cash flow, recycle
ratio, operating netback, 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 132,282 boe/d in 2022,
comprised of over 80 percent oil and liquids, in-line with
production guidance of 132,000 boe/d. Crescent Point's average
production in fourth quarter 2022 was 134,124 boe/d.
- In the Kaybob Duvernay, the Company brought its sixth fully
operated multi-well pad on-stream in early 2023. This multi-well
pad, which was located in the liquids-rich phase of the basin,
generated an average 30-day initial production (IP) rate of
approximately 1,235 boe/d per well (51% condensate, 15% NGLs). This
strong performance further demonstrates Crescent Point's
consistency in its operational execution in the play.
- The Kaybob Duvernay asset continues to generate significant
excess cash flow driven by strong netbacks and high mix of
condensate production. As a result, Crescent Point expects to
achieve a two-year payback period on its original Kaybob
acquisition of approximately $900
million by the end of first quarter 2023.
- In January 2023, the Company
closed its previously announced acquisition of additional assets in
the Kaybob Duvernay, which included approximately 130 net drilling
locations and over 4,000 boe/d of production. The Company has
identified over 20 years of inventory in the play, based on current
production.
- In the second half of 2022, Crescent Point began leveraging
open hole multi-lateral drilling techniques in the Viewfield
Bakken. The Company's most recent eight-leg wells have delivered
strong IP30 rates averaging over 225 bbl/d per well. This
innovation has materially improved returns by enhancing estimated
ultimate reserves, lowering water cuts and improving capital
efficiencies. The Company has identified approximately 150
additional locations with potential for open hole multi-lateral
drilling within the play, equating to approximately four years of
additional drilling inventory. Crescent Point plans to drill
several of these wells in 2023, while also exploring the potential
to implement this technique in other areas within its asset
portfolio.
- As part of its ongoing commitment to decline mitigation, the
Company converted approximately 105 producing wells to water
injection wells through its secondary recovery waterflood program
in 2022. Crescent Point plans to convert a similar number of
producing wells to water injection wells in 2023, while continuing
to advance other decline mitigation projects.
- Through its continued commitment to strong environmental,
social and governance ("ESG") practices, Crescent Point achieved
its Scope 1 emissions intensity reduction target of 50 percent,
including a 70 percent reduction in absolute methane emissions,
well ahead of its expected 2025 timeframe. The Company subsequently
introduced a target to further reduce its Scope 1 and 2 emissions
intensity by 38 percent by 2030, relative to its 2020 baseline.
Crescent Point also announced two new water targets to build upon
its existing strong water management performance, including a 50
percent reduction in surface freshwater use in southeast
Saskatchewan completions by 2025.
Furthermore, the Company has made significant progress toward its
target to reduce its inactive well inventory by 30 percent by 2031
and expects to achieve this target ahead of schedule.
- Crescent Point achieved its best serious incident frequency
("SIF") and total recordable incident frequency ("TRIF") scores in
the Company's history, demonstrating its ongoing commitment to safe
operations.
- Crescent Point's continued commitment to ESG practices was
recognized by Morgan Stanley Capital International ("MSCI") Inc. in
2022, as previously announced. In its ESG Ratings assessment, MSCI
increased the Company's rating for the second consecutive year,
improving its score to "AA".
RESERVES HIGHLIGHTS
"Our 2022 reserves highlight the success of our long-term
strategy and development activities, particularly in the Kaybob
Duvernay," said Bryksa. "Our proved plus probable reserves
additions more than replaced our annual production and resulted in
strong recycle ratios. Looking forward, we see significant
opportunity to further enhance shareholder value through ongoing
optimization and potential reserves growth, including in the Kaybob
Duvernay where approximately 75 percent of locations are currently
unbooked."
- As at year-end 2022, Crescent Point's Proved plus Probable
("2P") reserves totaled 713.1 million boe ("MMboe"), Proved ("1P")
reserves totaled 481.9 MMboe and Proved Developed Producing ("PDP")
reserves totaled 301.3 MMboe. These totals exclude any reserves
attributed to the Company's recent acquisition in the Kaybob
Duvernay which closed in January
2023.
- On a 2P basis, Crescent Point achieved reserve additions of
54.6 MMboe, replacing 113 percent of its 2022 production, excluding
acquisitions and dispositions ("A&D"). The majority of these
reserve additions originated from the Company's Kaybob Duvernay
asset, which contributed organic 2P reserve adds of 50.0 MMboe,
primarily through drilling and development activities. The
remaining reserve additions were identified throughout the
Company's other assets.
- The Company's 2P reserve life index ("RLI") is approximately 15
years based on 2022 annual average production.
- Crescent Point generated 2P finding, development and
acquisition ("FD&A") costs, including change in future
development capital ("FDC"), of $27.56 per boe, producing a recycle ratio of 2.3
times based on an operating netback of $62.94 per boe in 2022. The Company's PDP
FD&A costs, including change in FDC, totaled $18.77 per boe, resulting in a recycle ratio of
3.4 times.
- Strong performance from the Company's Kaybob Duvernay asset
resulted in an attractive F&D of approximately $12.00 per boe for wells brought on-stream in
2022, equating to a strong recycle ratio of over 5.0 times.
- The independent engineers have ascribed booked reserves in the
Kaybob Duvernay, on the wells Crescent Point has drilled and
completed since entering the play, ranging from approximately 700
Mboe (62% condensate, 11% NGLs) to 2,000 Mboe (21% condensate, 22%
NGLs).
- Crescent Point's 2P net asset value ("NAV") was $21.50 per share at year-end 2022, based on
independent engineering pricing. On a 1P and PDP basis, the
Company's NAV was $15.14 and
$10.38 per share, respectively. These
NAV forecasts, which include the reduction of net debt at year-end,
represent an increase of approximately 30 to 35 percent compared to
the prior year. The independent engineering price forecast assumes
an average WTI price of approximately US$78.50/bbl in the first five years.
Additional information on the Company's 2022 reserves is
provided in its Annual Information Form ("AIF") for the year-ended
December 31, 2022.
OUTLOOK
Crescent Point's 2022 results demonstrate the success and
consistency of its operational, financial and strategic
execution.
The Company remains on track with its previously released 2023
average production guidance of 138,000 to 142,000 boe/d. Since last
updating its annual guidance, Crescent Point has advanced plans to
add a second rig in the Kaybob Duvernay in fourth quarter 2023 to
further accelerate the development of its high-return inventory in
the play. The addition of this rig is not expected to impact the
Company's capital expenditures budget, which remains unchanged at
$1.0 to $1.1
billion.
Crescent Point's 2023 budget is expected to generate significant
excess cash flow of approximately $1.0
billion at US$75/bbl WTI,
providing returns of over $600
million directly to shareholders, based on its framework.
These returns are in addition to per-share growth and expected net
debt reduction of approximately $400
million during the year.
Within its five-year plan, the Company expects to generate over
$4.2 billion of cumulative after-tax
excess cash flow from 2023 to 2027, assuming US$75/bbl WTI. Crescent Point's five-year outlook
is supported by its Kaybob Duvernay play which is now expected to
grow to over 60,000 boe/d in 2027, highlighting the continued
outperformance of this asset. The Company's five-year plan remains
disciplined, with a continued focus on returns and long-term
sustainability.
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.
|
Summary of Reserves
The Company's reserves were independently evaluated by McDaniel
& Associates Consultants Ltd. ("McDaniel") as at December 31, 2022. 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, 2022 (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
|
118,455
|
108,945
|
38,102
|
33,802
|
18,986
|
15,886
|
74,510
|
64,332
|
Proved Developed
Non-Producing
|
2,395
|
1,984
|
337
|
323
|
2,323
|
2,108
|
2,719
|
2,211
|
Proved
Undeveloped
|
48,806
|
44,385
|
10,757
|
10,023
|
1,731
|
1,583
|
69,253
|
58,722
|
Total
Proved
|
169,657
|
155,313
|
49,197
|
44,148
|
23,039
|
19,578
|
146,482
|
125,266
|
Total
Probable
|
101,378
|
91,946
|
36,550
|
32,419
|
7,230
|
6,127
|
52,892
|
42,655
|
Total Proved plus
Probable
|
271,034
|
247,259
|
85,747
|
76,567
|
30,268
|
25,705
|
199,374
|
167,920
|
|
Shale
Gas
(MMcf)
|
Natural
Gas
(MMcf)
|
Total
(Mboe)
|
Reserves
Category
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Proved Developed
Producing
|
271,834
|
247,578
|
35,719
|
32,243
|
301,312
|
269,601
|
Proved Developed
Non-Producing
|
13,953
|
12,435
|
69
|
59
|
10,111
|
8,709
|
Proved
Undeveloped
|
235,901
|
212,657
|
3,491
|
3,251
|
170,446
|
150,698
|
Total
Proved
|
521,688
|
472,670
|
39,279
|
35,553
|
481,868
|
429,008
|
Total
Probable
|
175,480
|
152,970
|
23,599
|
21,366
|
231,230
|
202,203
|
Total Proved plus
Probable
|
697,167
|
625,640
|
62,877
|
56,919
|
713,098
|
631,211
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2022, 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, 2022
(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
|
301,312
|
9,407
|
7,530
|
6,288
|
5,448
|
Total
Proved
|
481,868
|
14,592
|
11,153
|
8,932
|
7,441
|
Total Proved plus
Probable
|
713,098
|
23,972
|
16,523
|
12,460
|
9,969
|
(1)
|
Price deck based on
three evaluator's average (McDaniel, GLJ Ltd. and Sproule
Associates Ltd.) December 31, 2022, 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,
2021
|
181,545
|
107,868
|
289,413
|
61,122
|
40,574
|
101,696
|
24,259
|
7,255
|
31,514
|
Extensions and
Improved Recovery
|
2,511
|
(178)
|
2,333
|
2,000
|
741
|
2,741
|
93
|
30
|
123
|
Technical
Revisions
|
2,462
|
(6,096)
|
(3,634)
|
(1,115)
|
(2,301)
|
(3,416)
|
(447)
|
(157)
|
(605)
|
Acquisitions
|
139
|
43
|
182
|
-
|
-
|
-
|
-
|
-
|
-
|
Dispositions
|
(710)
|
(1,023)
|
(1,733)
|
(9,052)
|
(3,046)
|
(12,098)
|
-
|
-
|
-
|
Economic
Factors
|
3,368
|
764
|
4,133
|
1,453
|
582
|
2,034
|
603
|
102
|
706
|
Production
|
(19,659)
|
-
|
(19,659)
|
(5,210)
|
-
|
(5,210)
|
(1,470)
|
-
|
(1,470)
|
December 31,
2022
|
169,657
|
101,378
|
271,034
|
49,197
|
36,550
|
85,747
|
23,039
|
7,230
|
30,268
|
|
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,
2021
|
130,029
|
47,742
|
177,772
|
444,884
|
158,493
|
603,377
|
43,612
|
25,077
|
68,690
|
Extensions and
Improved Recovery
|
20,614
|
5,283
|
25,896
|
90,983
|
22,017
|
113,000
|
684
|
299
|
983
|
Technical
Revisions
|
4,410
|
(1,253)
|
3,157
|
5,167
|
(10,983)
|
(5,816)
|
(2,149)
|
(1,955)
|
(4,104)
|
Acquisitions
|
10,046
|
2,494
|
12,540
|
61,482
|
15,322
|
76,804
|
-
|
-
|
-
|
Dispositions
|
(7,065)
|
(1,824)
|
(8,890)
|
(38,086)
|
(10,679)
|
(48,765)
|
(1,290)
|
(371)
|
(1,661)
|
Economic
Factors
|
1,791
|
451
|
2,242
|
5,037
|
1,310
|
6,347
|
2,247
|
549
|
2,796
|
Production
|
(13,343)
|
-
|
(13,343)
|
(47,779)
|
-
|
(47,779)
|
(3,826)
|
-
|
(3,826)
|
December 31,
2022
|
146,482
|
52,892
|
199,374
|
521,688
|
175,480
|
697,167
|
39,279
|
23,599
|
62,877
|
|
Total Oil
Equivalent
(Mboe)
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
December 31,
2021
|
478,371
|
234,035
|
712,406
|
Extensions and
Improved Recovery
|
40,496
|
9,595
|
50,090
|
Technical
Revisions
|
5,813
|
(11,964)
|
(6,151)
|
Acquisitions
|
20,432
|
5,090
|
25,523
|
Dispositions
|
(23,390)
|
(7,735)
|
(31,125)
|
Economic
Factors
|
8,429
|
2,209
|
10,639
|
Production
|
(48,283)
|
-
|
(48,283)
|
December 31,
2022
|
481,868
|
231,230
|
713,098
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2022, 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 2022
|
F&D
|
Change in
FDC on F&D
|
F&D Total
(incl. change
in FDC)
|
FD&A
|
Change in
FDC
|
FD&A Total
(incl. change
in FDC)
|
Capital ($
millions)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
975
|
597
|
1,572
|
782
|
568
|
1,350
|
Total Proved
|
975
|
383
|
1,359
|
782
|
387
|
1,170
|
Proved Developed
Producing
|
975
|
28
|
1,004
|
782
|
28
|
811
|
|
|
|
|
|
|
|
Reserves
Additions (Mboe)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
54,578
|
-
|
54,578
|
48,975
|
-
|
48,975
|
Total Proved
|
54,738
|
-
|
54,738
|
51,780
|
-
|
51,780
|
Proved Developed
Producing
|
49,209
|
-
|
49,209
|
43,183
|
-
|
43,183
|
|
|
|
|
|
|
|
Costs ($/boe)
(1)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
$17.87
|
-
|
$28.80
|
$15.97
|
-
|
$27.56
|
Total Proved
|
$17.82
|
-
|
$24.82
|
$15.11
|
-
|
$22.59
|
Proved Developed
Producing
|
$19.82
|
-
|
$20.39
|
$18.12
|
-
|
$18.77
|
|
|
|
|
|
|
|
Recycle Ratio
(2)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
3.5
|
-
|
2.2
|
3.9
|
-
|
2.3
|
Total Proved
|
3.5
|
-
|
2.5
|
4.2
|
-
|
2.8
|
Proved Developed
Producing
|
3.2
|
-
|
3.1
|
3.5
|
-
|
3.4
|
(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 2022 operating netback of $62.94 per
boe.
|
Future Development Capital
At year-end 2022, FDC for 2P reserves totaled $5.1 billion, compared to $4.6 billion at year-end 2021. The Company's FDC
increased by approximately $570
million, primarily driven by higher cost assumptions related
to inflation and the addition of new drilling locations. This FDC
equates to a conservative program that is also aligned with the
Company's current level of capital spending and five-year plan.
Company Annual
Capital Expenditures ($ millions)
|
|
Canada
|
U.S.
|
Total
|
Year
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
2023
|
468
|
521
|
271
|
401
|
739
|
922
|
2024
|
608
|
732
|
36
|
232
|
644
|
964
|
2025
|
763
|
898
|
8
|
63
|
771
|
962
|
2026
|
624
|
725
|
-
|
-
|
624
|
725
|
2027
|
552
|
702
|
-
|
-
|
552
|
702
|
2028
|
52
|
652
|
-
|
-
|
52
|
652
|
2029
|
4
|
201
|
-
|
-
|
4
|
201
|
2030
|
5
|
5
|
-
|
-
|
5
|
5
|
2031
|
6
|
6
|
-
|
-
|
6
|
6
|
2032
|
2
|
2
|
-
|
-
|
2
|
2
|
2033
|
1
|
1
|
-
|
-
|
1
|
1
|
2034
|
1
|
1
|
-
|
-
|
1
|
1
|
Subtotal
(1)
|
3,087
|
4,446
|
315
|
696
|
3,402
|
5,143
|
Remainder
|
2
|
2
|
-
|
-
|
2
|
2
|
Total
(1)
|
3,089
|
4,448
|
315
|
696
|
3,404
|
5,145
|
10%
Discounted
|
2,432
|
3,327
|
293
|
626
|
2,724
|
3,953
|
(1)
|
Numbers may not add due
to rounding.
|
CONFERENCE CALL DETAILS
Crescent Point management will host a conference call on
Thursday, March 2, 2023 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.
Alternatively, the conference call can be accessed by dialing
1–888–390–0605.
The webcast will be archived for replay and can be accessed on
Crescent Point's conference calls and webcasts webpage under the
invest tab. The replay will be available approximately one hour
following completion of the call.
Shareholders and investors can also find the Company's most
recent investor presentation on Crescent Point's website.
2023 GUIDANCE
The Company's guidance for 2023 is as follows:
Total Annual Average
Production (boe/d) (1)
|
138,000 -
142,000
|
Capital
Expenditures
|
|
Development capital
expenditures ($ millions)
|
$1,000 -
$1,100
|
Capitalized
administration ($ millions)
|
$40
|
Total ($ million)
(2)
|
$1,040 -
$1,140
|
Other Information
for 2023 Guidance
|
|
Reclamation activities
($ millions) (3)
|
$40
|
Capital lease payments
($ millions)
|
$20
|
Annual operating
expenses ($/boe)
|
$14.25 -
$15.25
|
Royalties
|
13.75% -
14.25%
|
1)
|
Total annual average
production (boe/d) is comprised of approximately 80% Oil,
Condensate & NGLs and 20% 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
|
$0.10
|
Additional Return of
Capital
|
|
% of discretionary
excess cash flow (1)(2)
|
50 %
|
1)
|
Discretionary excess
cash flow is calculated as excess cash flow less base
dividends
|
2)
|
This % is part of a
framework that targets to return up to 50% of discretionary excess
cash flow to shareholders
|
The Company's audited consolidated financial statements and
management's discussion and analysis for the year ended
December 31, 2022, will be available
on the System for Electronic Document Analysis and Retrieval
("SEDAR") at www.sedar.com, on EDGAR at
www.sec.gov/edgar.shtml and on Crescent Point's website at
www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
|
Three months ended
December 31
|
Year ended December
31
|
(Cdn$ millions except
per share and per boe amounts)
|
2022
|
2021
|
2022
|
2021
|
Financial
|
|
|
|
|
Cash flow from
operating activities
|
589.5
|
492.4
|
2,192.2
|
1,495.8
|
Adjusted funds flow
from operations
|
522.8
|
432.5
|
2,232.4
|
1,476.9
|
Per share
(2)
|
0.93
|
0.74
|
3.91
|
2.57
|
Net income
(loss)
|
(498.1)
|
121.6
|
1,483.4
|
2,364.1
|
Per share
(2)
|
(0.90)
|
0.21
|
2.60
|
4.11
|
Adjusted net earnings
from operations (1)
|
209.8
|
160.0
|
965.7
|
515.3
|
Per share (1)
(2)
|
0.38
|
0.27
|
1.69
|
0.90
|
Dividends
declared
|
118.8
|
26.0
|
200.6
|
47.8
|
Per share
(2)
|
0.2150
|
0.0450
|
0.3600
|
0.0825
|
Net debt
|
1,154.7
|
2,005.0
|
1,154.7
|
2,005.0
|
Net debt to adjusted
funds flow from operations (3)
|
0.5
|
1.4
|
0.5
|
1.4
|
Weighted average shares
outstanding
|
|
|
|
|
Basic
|
555.2
|
582.1
|
566.7
|
569.2
|
Diluted
|
559.2
|
587.7
|
571.1
|
575.1
|
Operating
|
|
|
|
|
Average daily
production
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
90,759
|
88,544
|
91,679
|
95,839
|
NGLs
(bbls/d)
|
17,770
|
20,884
|
17,039
|
17,769
|
Natural gas
(mcf/d)
|
153,572
|
125,871
|
141,384
|
114,452
|
Total
(boe/d)
|
134,124
|
130,407
|
132,282
|
132,683
|
Average selling prices
(4)
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
103.42
|
91.27
|
115.72
|
78.43
|
NGLs
($/bbl)
|
38.55
|
47.59
|
45.02
|
42.33
|
Natural gas
($/mcf)
|
6.37
|
5.66
|
6.60
|
4.51
|
Total
($/boe)
|
82.39
|
75.05
|
93.06
|
66.21
|
Netback
($/boe)
|
|
|
|
|
Oil and gas
sales
|
82.39
|
75.05
|
93.06
|
66.21
|
Royalties
|
(10.61)
|
(9.57)
|
(12.45)
|
(8.44)
|
Operating
expenses
|
(14.50)
|
(12.85)
|
(14.77)
|
(12.91)
|
Transportation
expenses
|
(3.09)
|
(2.48)
|
(2.90)
|
(2.43)
|
Operating
netback
|
54.19
|
50.15
|
62.94
|
42.43
|
Realized loss on
commodity derivatives
|
(7.75)
|
(9.60)
|
(13.29)
|
(7.45)
|
Other
(5)
|
(4.07)
|
(4.50)
|
(3.41)
|
(4.48)
|
Adjusted funds flow
from operations netback (1)
|
42.37
|
36.05
|
46.24
|
30.50
|
Capital
Expenditures
|
|
|
|
|
Capital acquisitions
(6)
|
1.3
|
5.2
|
90.7
|
942.4
|
Capital dispositions
(6)
|
1.2
|
(0.1)
|
(283.6)
|
(99.0)
|
Development capital
expenditures
|
|
|
|
|
Drilling and
development
|
213.9
|
198.9
|
865.7
|
523.7
|
Facilities and
seismic
|
32.5
|
30.6
|
90.4
|
100.5
|
Total
|
246.4
|
229.5
|
956.1
|
624.2
|
Land
expenditures
|
4.2
|
0.8
|
19.2
|
4.9
|
(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 dispositions,
net represent total consideration for the transactions, including
long-term debt and working capital assumed, and exclude transaction
costs.
|
Specified Financial Measures
Throughout this press release, the Company uses the terms
"adjusted funds flow" (equivalent to "adjusted funds flow from
operations"), "adjusted funds flow from operations per share -
diluted", "adjusted net earnings from operations", "adjusted net
earnings from operations per share - diluted", "total return of
capital", "excess cash flow", "discretionary excess cash flow",
"base dividends, "net debt", "net debt to adjusted funds flow"
(equivalent to "net debt to adjusted funds flow from operations"
and "leverage ratio"), "total operating netback", "total netback",
"operating netback", "netback", "recycle ratio", "adjusted funds
flow from operations netback" and "adjusted working capital
(surplus) deficiency". 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, 2022, which
section is incorporated herein by reference, and available on SEDAR
at www.sedar.com 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, total netback and adjusted funds flow from
operations netback:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
($ millions)
|
2022
|
|
2021
|
|
% Change
|
|
2022
|
|
2021
|
|
% Change
|
|
Oil and gas
sales
|
1,016.6
|
|
900.4
|
|
13
|
|
4,493.1
|
|
3,206.5
|
|
40
|
|
Royalties
|
(130.9)
|
|
(114.8)
|
|
14
|
|
(600.9)
|
|
(408.8)
|
|
47
|
|
Operating
expenses
|
(178.9)
|
|
(154.2)
|
|
16
|
|
(713.1)
|
|
(625.3)
|
|
14
|
|
Transportation
expenses
|
(38.1)
|
|
(29.8)
|
|
28
|
|
(139.8)
|
|
(117.7)
|
|
19
|
|
Total operating
netback
|
668.7
|
|
601.6
|
|
11
|
|
3,039.3
|
|
2,054.7
|
|
48
|
|
Realized loss on
commodity derivatives
|
(95.6)
|
|
(115.2)
|
|
(17)
|
|
(641.8)
|
|
(360.8)
|
|
78
|
|
Total
netback
|
573.1
|
|
486.4
|
|
18
|
|
2,397.5
|
|
1,693.9
|
|
42
|
|
Other
(1)
|
(50.3)
|
|
(53.9)
|
|
(7)
|
|
(165.1)
|
|
(217.0)
|
|
(24)
|
|
Total adjusted funds
flow from operations netback
|
522.8
|
|
432.5
|
|
21
|
|
2,232.4
|
|
1,476.9
|
|
51
|
|
(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 cash flow from operating activities
to adjusted funds flow from operations, excess cash flow and
discretionary excess cash flow:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
($ millions)
|
2022
|
|
2021
|
|
% Change
|
|
2022
|
|
2021
|
|
% Change
|
|
Cash flow from
operating activities
|
589.5
|
|
492.4
|
|
20
|
|
2,192.2
|
|
1,495.8
|
|
47
|
|
Changes in non-cash
working capital
|
(71.8)
|
|
(69.1)
|
|
4
|
|
15.0
|
|
(51.6)
|
|
(129)
|
|
Transaction
costs
|
1.8
|
|
0.3
|
|
500
|
|
5.1
|
|
12.5
|
|
(59)
|
|
Decommissioning
expenditures (1)
|
3.3
|
|
8.9
|
|
(63)
|
|
20.1
|
|
20.2
|
|
—
|
|
Adjusted funds flow
from operations
|
522.8
|
|
432.5
|
|
21
|
|
2,232.4
|
|
1,476.9
|
|
51
|
|
Capital
expenditures
|
(264.9)
|
|
(242.9)
|
|
9
|
|
(1,027.4)
|
|
(676.1)
|
|
52
|
|
Payments on lease
liability
|
(5.1)
|
|
(5.6)
|
|
(9)
|
|
(20.4)
|
|
(21.2)
|
|
(4)
|
|
Decommissioning
expenditures
|
(3.3)
|
|
(8.9)
|
|
(63)
|
|
(20.1)
|
|
(20.2)
|
|
—
|
|
Other items
(2)
|
1.9
|
|
7.3
|
|
(74)
|
|
(12.3)
|
|
29.0
|
|
(142)
|
|
Excess cash
flow
|
251.4
|
|
182.4
|
|
38
|
|
1,152.2
|
|
788.4
|
|
46
|
|
Base
dividends
|
(44.3)
|
|
(17.4)
|
|
155
|
|
(152.2)
|
|
(21.7)
|
|
601
|
|
Discretionary excess
cash flow
|
207.1
|
|
165.0
|
|
26
|
|
1,000.0
|
|
766.7
|
|
30
|
|
(1)
|
Excludes amounts
received from government grant programs.
|
(2)
|
Other items include,
but are not limited to, unrealized gains on equity derivative
contracts, sale of long-term investments and transaction costs.
Other items exclude net acquisitions and dispositions.
|
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 dividends declared to base
dividends:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
($ millions)
|
2022
|
|
2021
|
|
% Change
|
|
2022
|
|
2021
|
|
% Change
|
|
Dividends
declared
|
118.8
|
|
26.0
|
|
357
|
|
200.6
|
|
47.8
|
|
320
|
|
Dividend timing
adjustment (1)
|
(55.1)
|
|
(8.6)
|
|
541
|
|
(29.0)
|
|
(26.1)
|
|
11
|
|
Special
dividends
|
(19.4)
|
|
—
|
|
100
|
|
(19.4)
|
|
—
|
|
100
|
|
Base
dividends
|
44.3
|
|
17.4
|
|
155
|
|
152.2
|
|
21.7
|
|
601
|
|
(1)
|
Dividends declared
where the declaration date and record date are in different
periods.
|
The following table reconciles adjusted working capital (surplus)
deficiency:
($ millions)
|
2022
|
|
2021
|
|
% Change
|
|
Accounts payable and
accrued liabilities
|
448.2
|
|
450.7
|
|
(1)
|
|
Dividends
payable
|
99.4
|
|
43.5
|
|
129
|
|
Long-term compensation
liability (1)
|
59.2
|
|
42.6
|
|
39
|
|
Cash
|
(289.9)
|
|
(13.5)
|
|
2,047
|
|
Accounts
receivable
|
(327.8)
|
|
(314.3)
|
|
4
|
|
Prepaids and deposits
(2)
|
(84.2)
|
|
(7.4)
|
|
1,038
|
|
Adjusted working
capital (surplus) deficiency
|
(95.1)
|
|
201.6
|
|
(147)
|
|
(1)
|
Includes current
portion of long-term compensation liability and is net of equity
derivative contracts.
|
(2)
|
Includes deposit on
acquisition.
|
The following table reconciles long-term debt to net debt:
($ millions)
|
2022
|
|
2021
|
|
% Change
|
|
Long-term debt
(1)
|
1,441.5
|
|
1,970.2
|
|
(27)
|
|
Adjusted working
capital (surplus) deficiency
|
(95.1)
|
|
201.6
|
|
(147)
|
|
Unrealized foreign
exchange on translation of US dollar long-term debt
|
(191.7)
|
|
(166.8)
|
|
15
|
|
Net debt
|
1,154.7
|
|
2,005.0
|
|
(42)
|
|
(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)
|
2022
|
|
2021
|
|
% Change
|
|
2022
|
|
2021
|
|
% Change
|
|
Net income
(loss)
|
(498.1)
|
|
121.6
|
|
(510)
|
|
1,483.4
|
|
2,364.1
|
|
(37)
|
|
Amortization of E&E
undeveloped land
|
2.8
|
|
9.6
|
|
(71)
|
|
15.2
|
|
51.0
|
|
(70)
|
|
Impairment (impairment
reversal)
|
1,056.3
|
|
—
|
|
100
|
|
(428.6)
|
|
(2,514.4)
|
|
(83)
|
|
Unrealized derivative
(gains) losses
|
(53.7)
|
|
(87.1)
|
|
(38)
|
|
(171.0)
|
|
141.4
|
|
(221)
|
|
Unrealized foreign
exchange (gain) loss on translation
of hedged US dollar long-term debt
|
(16.1)
|
|
(13.1)
|
|
23
|
|
27.7
|
|
(37.0)
|
|
(175)
|
|
Unrealized gain on
long-term investments
|
—
|
|
—
|
|
(100)
|
|
—
|
|
(3.1)
|
|
(100)
|
|
Gain on sale of
long-term investments
|
—
|
|
—
|
|
(100)
|
|
—
|
|
(7.0)
|
|
(100)
|
|
Net (gain) loss on
capital dispositions
|
0.2
|
|
—
|
|
100
|
|
(25.9)
|
|
(58.4)
|
|
(56)
|
|
Deferred tax
adjustments
|
(281.6)
|
|
129.0
|
|
(318)
|
|
64.9
|
|
578.7
|
|
(89)
|
|
Adjusted net earnings
from operations
|
209.8
|
|
160.0
|
|
31
|
|
965.7
|
|
515.3
|
|
87
|
|
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.
In 2021, the Company's Kaybob Duvernay asset generated a recycle
ratio of 3.7 times based F&D for wells brought on-stream.
|
F&D
|
F&D Total
(incl. change
in FDC)
|
FD&A
|
FD&A Total
(incl. change
in FDC)
|
2021 Recycle
Ratios
|
|
|
|
|
Total Proved plus
Probable
|
2.4
|
1.6
|
2.7
|
2.2
|
Total Proved
|
3.8
|
2.9
|
3.3
|
2.5
|
Proved Developed
Producing
|
3.3
|
3.5
|
2.6
|
2.7
|
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 2023 is a forward-looking non-GAAP measures
and are 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, 2022.
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:
drilling inventory in the Kaybob Duvernay; expected 2023 excess
cash flow at the WTI prices stated; delivering substantial returns
to shareholders; expected payout of the sixth fully operated
multi-well pad in the Kaybob Duvernay; two-year payback on the
original Kaybob Duvernay acquisition; plans to drill additional
open hole multi-lateral wells in 2023; hedging expectations; years
of inventory in the Kaybob Duvernay play; exploring the
implementation of open hole multi-lateral wells elsewhere in the
Company's portfolio; plans to convert an additional producing wells
to water injection wells in 2023, while continuing to advance other
decline mitigation projects; reducing scope 1 and 2 emissions
intensity by 38 percent by 2030, relative to its 2020 baseline;
water targets including a 50 percent reduction in surface
freshwater use in southeast Saskatchewan completions by 2025; target to
reduce inactive well inventory by 30 percent by 2031 and
expectations of achieving this target ahead of schedule;
significant opportunity to further enhance shareholder value
through ongoing optimization and potential reserves growth,
including in the Kaybob Duvernay; adding a second rig in the Kaybob
Duvernay in fourth quarter 2023; 2023 budget is expected to
generate excess cash flow of approximately $1.0 billion at US$75/bbl WTI, allowing for the return of
significant capital to shareholders, in addition to per-share
growth and further net debt reduction; based on its return of
capital framework and 2023 budget, expectations of returning over
$600 million directly back to
shareholders at US$75/bbl WTI,
including base dividend; the Company plans to remain active on its
share repurchase program; focus on further improving balance sheet
strength; generating approximately $4.2
billion of cumulative after-tax excess cash flow from 2023
to 2027, assuming US$75/bbl WTI; net
present values of reserves; forecast company annual capital
expenditures; Crescent Point's five-year excess cash flow outlook
being supported by plans to grow its Kaybob Duvernay asset to over
60,000 boe/d in 2027; Crescent Point plans to remain disciplined as
it executes its five-year plan, with a continued focus on returns
and long-term sustainability; Crescent Point's 2023 production and
development capital expenditures guidance; and other information
for Crescent Point's 2023 guidance, including capitalized
administration, reclamation activities, capital lease payments,
annual operating expenses and royalties; return of capital outlook,
including base dividend, and the additional return of capital
targeted as a percentage of discretionary 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, 2022. 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, 2022, which is accessible at
www.sedar.com.
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,
2022 under "Risk Factors" and our Management's Discussion
and Analysis for the year ended December 31,
2022, 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, 2022, 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, blowouts and business closures and social distancing
measures mandated by public health authorities in response to
COVID-19; uncertainty regarding the benefits and costs of
acquisitions and dispositions; failure to complete acquisitions and
dispositions; 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; 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, including as a result of the COVID-19
pandemic; uncertainties associated with regulatory approvals;
uncertainty of government policy changes; uncertainty regarding the
benefits and costs of dispositions; failure to complete
acquisitions and dispositions; uncertainties associated with credit
facilities and counterparty credit risk; changes in income tax
laws, tax laws, crown royalty rates and incentive programs relating
to the oil and gas industry; the wide-ranging impacts of the
COVID-19 pandemic, including on demand, health and supply chain;
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 2023 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 2022 and 2021, the
aggregate average production for fourth quarter of 2022 and 2021,
and the references to "natural gas", "crude oil" and "condensante"
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
|
|
2022
|
2021
|
2022
|
2021
|
Light & Medium
Crude Oil (bbl/d)
|
13,671
|
15,517
|
14,274
|
17,859
|
Heavy Crude Oil
(bbl/d)
|
3,870
|
4,226
|
4,027
|
4,203
|
Tight Oil
(bbl/d)
|
52,095
|
55,965
|
53,861
|
62,492
|
Total Crude Oil
(bbl/d)
|
69,636
|
75,708
|
72,162
|
84,554
|
|
|
|
|
|
NGLs (bbl/d)
|
38,893
|
33,720
|
36,556
|
29,054
|
|
|
|
|
|
Shale Gas
(mcf/d)
|
142,803
|
115,482
|
130,902
|
103,124
|
Conventional Natural
Gas (mcf/d)
|
10,769
|
10,389
|
10,482
|
11,328
|
Total Natural Gas
(mcf/d)
|
153,572
|
125,871
|
141,384
|
114,452
|
|
|
|
|
|
Total
(boe/d)
|
134,124
|
130,407
|
132,282
|
132,683
|
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
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) or 2P 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 based on three evaluators' average (McDaniel, GLJ
Ltd. and Sproule Associates Ltd.) December
31, 2022 escalated price forecast, the fair value for the
Company's oil and gas hedges based on such December 31, 2022 escalated price forecast, 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. Booked type well
data was audited by independent reserves evaluator, McDaniel,
effective December 31, 2022.
Initial 30 day production on the Company's sixth fully operated
multi-well pad in the Kaybob Duvernay consists of 51% condensate,
15% NGLs and 34% shale gas. Viewfield Bakken most recent eight-leg
wells with IP30 averaging 225 bbl/d per well consisted of 100%
tight oil.
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", "payout 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.
Payout is the point at which all costs associated with leasing,
exploring, drilling and operating have been recovered from the
production of a well. It is an indication of profitability.
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 NGL 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 NGL 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,
NGL 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.
The reserve data provided in this news release presents only a
portion of the disclosure required under National Instrument
51-101. This press release discloses approximately 130 net drilling
locations associated with the acquisition of additional assets in
the Kaybob Duvernay, of which none are booked at year-end 2022.
This press release references over 20 years of inventory in the
Kaybob Duvernay play and the potential for open hole multi-lateral
drilling within the Viewfield Bakken play to add approximately four
years of additional drilling inventory, which amounts include
booked and unbooked locations. This press release discloses
approximately 150 additional potential net drilling locations in
the Viewfield Bakken of which none are booked at year-end 2022. All
of the required information will be contained in the Company's
Annual Information Form for the year ended December 31, 2022, which will be filed on SEDAR
(accessible at www.sedar.com) and EDGAR (accessible at
www.sec.gov/edgar.shtml) on or before March 2, 2023 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.