CALGARY, AB, March 3, 2022 /CNW/ - Crescent Point Energy
Corp. ("Crescent Point" or the "Company") (TSX: CPG) and (NYSE:
CPG) is pleased to announce its operating and financial results for
the year ended December 31, 2021 and
increased share repurchases.
KEY HIGHLIGHTS
- Generated over $785 million of
excess cash flow in 2021 with capital expenditures and production
in-line with annual guidance.
- Increased PDP reserves by 17 percent with a strong FD&A
recycle ratio of 2.7 times, including change in FDC.
- Replaced 197 percent of 2021 production on a 2P basis,
resulting in a FD&A recycle ratio of 2.2 times, including
change in FDC.
- Improved full-cycle returns in the Kaybob Duvernay through
additional well cost reductions now totaling 20 percent.
- Achieved strong IP rate of over 825 boe/d per well, based on
approximately 30 days, on first fully operated Kaybob Duvernay
pad.
- Fully repaid $670 million of debt
to acquire the Kaybob Duvernay assets, in addition to reducing net
debt by $144 million in 2021.
- Disciplined 2022 budget, which is expected to generate
approximately $1.1 billion of excess
cash flow at US$80/bbl WTI.
- Increasing planned share repurchases to up to $150 million, to be executed by mid-2022, from
$100 million announced
previously.
- On track to meet or exceed targets to reduce emissions
intensity and inactive wells, highlighting strong ESG
practices.
"Our discipline and execution over the past few years positioned
us to not only capitalize on strategic opportunities during 2021,
but also to begin returning additional capital to shareholders,"
said Craig Bryksa, President and CEO
of Crescent Point. "We are very pleased with our initial success in
the Kaybob Duvernay, including our strong operational execution
that has resulted in increased rates of return. Due to our
continued discipline and focus, we are on track to achieve our
near-term leverage targets over the next six months at current
commodity prices. As we continue to strengthen our balance sheet we
will look to provide increased returns to shareholders in the
context of a more defined return of capital framework."
FINANCIAL HIGHLIGHTS
- For the year ended December 31,
2021, adjusted funds flow totaled $1.48 billion, or $2.57 per share diluted, driven by a strong
operating netback of $42.43 per boe.
In fourth quarter, adjusted funds flow totaled $432.5 million, or $0.74 per share diluted.
- For the year ended December 31,
2021, development capital expenditures, which included
drilling and development, facilities and seismic costs, totaled
$624.2 million, in-line with the
Company's annual guidance of $625
million.
- Crescent Point's net debt as at December
31, 2021 was approximately $2.0
billion. The Company fully repaid approximately $670 million of debt incurred to acquire the
Kaybob Duvernay assets, in addition to reducing its net debt by
$144 million in 2021. In total,
approximately $815 million of funds
were directed to the balance sheet in 2021, including proceeds from
dispositions.
- As previously announced, Crescent Point successfully renewed
and extended its unsecured, covenant-based credit facilities of
$2.3 billion with a maturity date of
November 2025. The Company retains
significant liquidity with an unutilized credit capacity of
approximately $2.0 billion as at
December 31, 2021.
- For the year ended December 31,
2021, Crescent Point reported net income of approximately
$2.4 billion, primarily driven by a
$2.5 billion ($1.9 billion after-tax) reversal of non-cash
impairment in second quarter due to an increase in forward
commodity prices and the independent engineers' price forecast. In
fourth quarter, net income totaled $121.6
million.
RETURN OF CAPITAL HIGHLIGHTS
- As previously announced, the Company's Board of Directors
("Board") approved and declared a first quarter 2022 dividend of
$0.045 per share, payable on
April 1, 2022 to shareholders of
record on March 15, 2022. This
equates to an annualized dividend of $0.18 per share, an increase of 50 percent from
the prior level.
- The Board has approved the return of additional capital to
shareholders given the continued strength in commodity prices and
Crescent Point's improving financial position. The Company is
increasing its total planned share repurchases to up to
$150 million, which it expects to
execute by mid-2022, from $100
million announced previously. These planned repurchases were
initiated in December 2021 with
approximately 8.1 million shares repurchased and cancelled to-date
for total consideration of approximately $60
million. Crescent Point has filed notice with the Toronto
Stock Exchange ("TSX") of the intention to renew its normal course
issuer bid ("NCIB"), which is due to expire on March 8, 2022.
Adjusted funds flow,
adjusted funds flow per share diluted, excess cash flow, recycle
ratio, operating netback, net debt and net debt to adjusted funds
flow 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 132,683 boe/d in 2021,
comprised of over 80 percent oil and liquids, and in-line with the
previously increased annual guidance.
- The Company continues to gain operational momentum in its
Kaybob Duvernay play, realizing ongoing operational efficiencies
and cost reductions. Recent well costs are trending at
approximately $8.25 million,
including drilling, completion, equip and tie-in, down from
$8.75 million previously announced.
Crescent Point has now removed approximately $2.0 million of per well costs, or approximately
20 percent, since entering the play in second quarter 2021. These
savings have improved expected full-cycle rates of return and
provide additional insulation to the Company's capital budget in
the current inflationary environment.
- Crescent Point's Kaybob Duvernay wells are expected to generate
full-cycle rates of return of over 120 percent and a payout of less
than a year, at current commodity prices and budgeted cost
inflation assumptions. These economics are based on an average of
booked Proved plus Probable ("2P") reserves per well within the
Company's current drilling program. These returns exclude any
potential improvements to recoverable reserves resulting from
Crescent Point utilizing a larger frac design than the prior
operator. The Company will seek to further enhance returns in the
play through ongoing drilling and completions optimization.
- Crescent Point recently brought onstream its first fully
operated five-well pad in the Kaybob Duvernay, with approximately
30 days of production data now available. Initial production ("IP")
rates from these wells exceeded the 2P booked type well
expectations, with an average IP rate of over 825 boe/d per well
(74% condensate, 6% NGL and 20% shale gas). Crescent Point also
completed and brought on production two multi-well pads, with a 50
percent working interest, as part of its previously announced
farm-in agreement with a Kaybob Duvernay operator. The combined
30-day IP rate, net to the Company, for these three pads totaled
over 11,000 boe/d (51% condensate, 9% NGL and 40% shale gas). This
data includes a normal clean-up period for each well where pressure
is maintained and production rates are moderated.
- Crescent Point continued to enhance returns by realizing
efficiencies across its asset base in 2021, including reducing its
drilling days within its Viewfield, Shaunavon and North
Dakota resource plays by 10 to 15 percent. Such improvements
provide the Company with sustainable cost efficiencies and further
highlight its commitment to ongoing operational execution.
- The Company continued to advance its various decline mitigation
initiatives in 2021, which included the successful conversion of
approximately 135 producing wells to water injection wells.
Crescent Point expects to execute a similar waterflood program in
2022. The Company also continues to progress its other decline
mitigation programs, including the expansion of its polymer floods
and pilot program to test carbon dioxide (CO2)
sequestration and enhanced oil recovery in Saskatchewan.
- As part of its continued commitment to strong environmental,
social and governance ("ESG") practices, Crescent Point increased
its target for emissions intensity reduction to 50 percent, up from
30 percent, by 2025, as previously announced. This target includes
a 70 percent reduction in methane emissions. The Company is on
track to meet or exceed its existing targets ahead of schedule and
plans to revisit its current emissions reduction goals in second
quarter 2022 in coordination with the release of its annual
sustainability report. Crescent Point also made progress toward its
target to reduce its inactive well count by approximately 30
percent by 2031 by safely retiring over 500 inactive wells during
the year. The Company plans to retire approximately 350 additional
wells in 2022.
RESERVES HIGHLIGHTS
"Our 2021 reserves and strong recycle ratios benefited from the
addition of the Kaybob Duvernay asset, high-return development and
improved recoveries from our decline mitigation programs," said
Bryksa. "As a result, our proved developed producing net asset
value increased by approximately 15 percent on a per share basis,
excluding year-over-year changes in pricing. We remain encouraged
about the Kaybob Duvernay assets and the opportunity we have to
further enhance shareholder value by achieving additional cost
efficiencies, improving well productivity and adding
reserves."
- Crescent Point's 2P reserves increased by seven percent at
year-end 2021 to 712.4 million boe ("MMboe"), Proved ("1P")
reserves by 16 percent to 478.4 MMboe and Proved Developed
Producing ("PDP") reserves by 17 percent to 306.4 MMboe.
- On a 2P basis, the Company achieved reserve additions of 95.5
MMboe, replacing 197 percent of its 2021 production. Crescent Point
benefited from the strategic Kaybob Duvernay acquisition, organic
reserves additions, improved recovery factors associated with its
decline mitigation programs and economic factors due to higher
pricing. The Company's 2P reserve life index ("RLI") is
approximately 15 years.
- Crescent Point generated 2P finding, development and
acquisition ("FD&A") costs, including change in future
development capital ("FDC"), of $19.68 per boe, producing a recycle ratio of 2.2
times based on an operating netback of $42.43 per boe in 2021.
- On a PDP basis, the Company generated finding and development
("F&D") costs, including change in FDC, of $12.22 per boe, producing a recycle ratio of 3.5
times. Crescent Point's PDP FD&A costs, including change in
FDC, totaled $15.93 per boe,
resulting in a recycle ratio of 2.7 times.
- Crescent Point's 2P and 1P net asset value ("NAV") was
$16.56 and $11.18 per share, respectively, at year-end 2021,
based on independent engineering pricing. On a PDP basis, NAV was
$7.62 per share and increased by
approximately 15 percent compared to the prior year, adjusting for
year-over-year changes in pricing and excluding land and seismic.
This NAV forecast assumes an average WTI price of approximately
US$69/bbl in the first five
years.
- Crescent Point's 2P FDC increased by approximately $400 million, or 10 percent, to $4.6 billion primarily driven by location
additions from its Kaybob Duvernay play. This FDC equates to a
conservative program that is also aligned with the Company's
current level of capital spending and five year plan.
In contrast to the prior year, Crescent Point elected to use a
single independent evaluator to determine its 2021 corporate
reserves, providing consistency across the evaluation process.
Certain reserves metrics, including F&D costs, FD&A costs
and recycle ratios, may not be meaningful or comparable
year-over-year given significant portfolio changes executed over
the last three years. Additional information on the Company's 2021
reserves is provided in its Annual Information Form ("AIF") for the
year-ended December 31, 2021.
OUTLOOK
Crescent Point's strong 2021 results highlight the continued
success of its operational, financial and strategic execution.
The Company is on track to meet its 2022 average production
guidance of 133,000 to 137,000 boe/d within its development capital
expenditures budget of $825 to
$900 million. This budget remains
unchanged, despite a stronger commodity price environment, as
management remains disciplined and focused on generating
significant excess cash flow to create shareholder value. Crescent
Point's capital expenditures guidance also remains unchanged,
despite continued cost inflation pressures, due to the Company's
ongoing efforts to realize internal efficiencies and its supply
chain management. Assuming US$80/bbl
WTI for the remainder of the year, Crescent Point's budget is
expected to generate approximately $1.1
billion of excess cash flow in 2022.
The Company continues to prioritize its balance sheet as it
moves closer to achieving its near-term leverage target of
approximately 1.0 times net debt to adjusted funds flow at
US$55/bbl WTI, or approximately
$1.3 to $1.4
billion of absolute net debt. At current commodity prices,
Crescent Point expects to achieve this near-term debt target over
the next six months.
The Company will look to provide increased returns to
shareholders and a more defined return of capital framework as the
balance sheet continues to strengthen. Based on Crescent Point's
continued successes and improving outlook, the Company is
increasing its total planned share repurchases to up to
$150 million, which it expects to
execute by mid-2022, from $100
million announced previously.
Crescent Point is committed to a model that returns capital to
shareholders while also generating additional returns through
debt-adjusted per share growth.
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, 2021. 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, 2021 (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
|
118,028
|
109,274
|
46,241
|
41,857
|
20,230
|
16,839
|
71,949
|
63,859
|
Proved Developed
Non-Producing
|
1,761
|
1,462
|
528
|
505
|
2,352
|
2,136
|
504
|
418
|
Proved
Undeveloped
|
61,755
|
55,934
|
14,353
|
13,561
|
1,677
|
1,460
|
57,577
|
51,195
|
Total
Proved
|
181,545
|
166,669
|
61,122
|
55,922
|
24,259
|
20,434
|
130,029
|
115,471
|
Total
Probable
|
107,868
|
98,235
|
40,574
|
36,729
|
7,255
|
6,091
|
47,742
|
40,108
|
Total Proved plus
Probable
|
289,413
|
264,905
|
101,696
|
92,651
|
31,514
|
26,525
|
177,772
|
155,579
|
|
Shale
Gas
(MMcf)
|
Natural
Gas
(MMcf)
|
Total
(Mboe)
|
Reserves
Category
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Proved Developed
Producing
|
259,805
|
241,945
|
39,979
|
36,719
|
306,412
|
278,273
|
Proved Developed
Non-Producing
|
1,504
|
1,239
|
165
|
148
|
5,423
|
4,751
|
Proved
Undeveloped
|
183,576
|
169,285
|
3,468
|
3,223
|
166,536
|
150,900
|
Total
Proved
|
444,884
|
412,469
|
43,612
|
40,090
|
478,371
|
433,924
|
Total
Probable
|
158,493
|
144,084
|
25,077
|
23,108
|
234,035
|
209,029
|
Total Proved plus
Probable
|
603,377
|
556,553
|
68,690
|
63,198
|
712,406
|
642,952
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2021, 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, 2021
(1) (2)
|
|
|
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
|
306,412
|
8,628
|
7,119
|
5,995
|
5,207
|
Total
Proved
|
478,371
|
12,600
|
9,948
|
8,078
|
6,781
|
Total Proved plus
Probable
|
712,406
|
20,714
|
14,723
|
11,230
|
9,037
|
(1)
|
Price deck based on
three evaluator's average (McDaniel, GLJ Ltd. and Sproule
Associates Ltd.) December 31, 2021, escalated price
forecast.
|
(2)
|
Numbers may not add
due to rounding.
|
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 P
robable
|
Proved
|
Probable
|
Proved
plus
Probable
|
December 31,
2020
|
206,262
|
136,923
|
343,185
|
83,454
|
53,678
|
137,131
|
24,935
|
6,665
|
31,600
|
Extensions and
Improved Recovery
|
12,139
|
216
|
12,355
|
6,786
|
1,753
|
8,539
|
1,810
|
1,362
|
3,173
|
Technical
Revisions
|
(17,677)
|
(27,407)
|
(45,085)
|
(3,267)
|
(2,184)
|
(5,451)
|
(1,863)
|
(939)
|
(2,802)
|
Acquisitions
|
-
|
-
|
-
|
24
|
6
|
30
|
-
|
-
|
-
|
Dispositions
|
(1,943)
|
(3,393)
|
(5,336)
|
(23,463)
|
(14,422)
|
(37,885)
|
-
|
-
|
-
|
Economic
Factors
|
5,575
|
1,530
|
7,104
|
4,107
|
1,744
|
5,851
|
911
|
167
|
1,078
|
Production
|
(22,810)
|
-
|
(22,810)
|
(6,519)
|
-
|
(6,519)
|
(1,534)
|
-
|
(1,534)
|
December 31,
2021
|
181,545
|
107,868
|
289,413
|
61,122
|
40,574
|
101,696
|
24,259
|
7,255
|
31,514
|
|
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,
2020
|
58,082
|
33,832
|
91,914
|
176,738
|
110,880
|
287,618
|
52,042
|
29,381
|
81,423
|
Extensions and
Improved Recovery
|
31,404
|
6,241
|
37,645
|
113,922
|
20,659
|
134,581
|
1,581
|
820
|
2,402
|
Technical
Revisions
|
(4,385)
|
(4,344)
|
(8,729)
|
(14,641)
|
(17,625)
|
(32,266)
|
(1,970)
|
(1,940)
|
(3,910)
|
Acquisitions
|
54,314
|
12,327
|
66,641
|
203,901
|
48,064
|
251,966
|
-
|
-
|
-
|
Dispositions
|
(1,396)
|
(1,159)
|
(2,554)
|
(3,188)
|
(5,272)
|
(8,460)
|
(7,728)
|
(4,712)
|
(12,440)
|
Economic
Factors
|
2,615
|
845
|
3,460
|
5,793
|
1,786
|
7,579
|
3,822
|
1,527
|
5,350
|
Production
|
(10,605)
|
-
|
(10,605)
|
(37,640)
|
-
|
(37,640)
|
(4,135)
|
-
|
(4,135)
|
December 31,
2021
|
130,029
|
47,742
|
177,772
|
444,884
|
158,493
|
603,377
|
43,612
|
25,077
|
68,690
|
|
Total Oil
Equivalent
(Mboe)
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
December 31,
2020
|
410,862
|
254,476
|
665,338
|
Extensions and
Improved Recovery
|
71,389
|
13,151
|
84,541
|
Technical
Revisions
|
(29,961)
|
(38,135)
|
(68,096)
|
Acquisitions
|
88,322
|
20,343
|
108,665
|
Dispositions
|
(28,621)
|
(20,638)
|
(49,259)
|
Economic
Factors
|
14,810
|
4,838
|
19,648
|
Production
|
(48,429)
|
-
|
(48,429)
|
December 31,
2021
|
478,371
|
234,035
|
712,406
|
(1)
|
Based on three
evaluator's average (McDaniel, GLJ Ltd. and Sproule Associates
Ltd.) December 31, 2021, 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 2021
The Company's F&D costs, FD&A costs and recycle ratios
may not be meaningful or comparable year-over-year given
significant portfolio changes executed over the last three
years.
|
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
|
629
|
319
|
948
|
1,472
|
407
|
1,879
|
Total
Proved
|
629
|
190
|
819
|
1,472
|
458
|
1,931
|
Proved Developed
Producing
|
629
|
(38)
|
591
|
1,472
|
(6)
|
1,467
|
|
|
|
|
|
|
|
Reserves Additions
(Mboe)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
36,092
|
-
|
36,092
|
95,498
|
-
|
95,498
|
Total
Proved
|
56,238
|
-
|
56,238
|
115,939
|
-
|
115,939
|
Proved Developed
Producing
|
48,338
|
-
|
48,338
|
92,066
|
-
|
92,066
|
|
|
|
|
|
|
|
Costs ($/boe)
(1)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
$17.43
|
-
|
$26.27
|
$15.42
|
-
|
$19.68
|
Total
Proved
|
$11.19
|
-
|
$14.56
|
$12.70
|
-
|
$16.65
|
Proved Developed
Producing
|
$13.01
|
-
|
$12.22
|
$15.99
|
-
|
$15.93
|
|
|
|
|
|
|
|
Recycle Ratio
(2)
|
|
|
|
|
|
|
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
|
(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 2021 operating netback of $42.43 per
boe.
|
Future Development Capital
At year-end 2021, FDC for 2P reserves totaled $4.6 billion, compared to $4.2 billion at year-end 2020. The Company's FDC
increased by approximately $400
million, primarily driven by location additions from its
Kaybob Duvernay play.
Company Annual
Capital Expenditures ($ millions)
|
|
Canada
|
U.S.
|
Total
|
Year
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
2022
|
608
|
612
|
130
|
130
|
738
|
742
|
2023
|
551
|
607
|
51
|
128
|
602
|
736
|
2024
|
606
|
742
|
121
|
141
|
727
|
883
|
2025
|
550
|
727
|
81
|
137
|
631
|
864
|
2026
|
284
|
505
|
6
|
138
|
290
|
643
|
2027
|
6
|
399
|
-
|
24
|
6
|
424
|
2028
|
4
|
265
|
-
|
-
|
4
|
265
|
2029
|
3
|
3
|
-
|
-
|
3
|
3
|
2030
|
3
|
3
|
-
|
-
|
3
|
3
|
2031
|
5
|
3
|
-
|
-
|
5
|
3
|
2032
|
3
|
2
|
-
|
-
|
3
|
2
|
2033
|
1
|
1
|
-
|
-
|
1
|
1
|
Subtotal
(1)
|
2,624
|
3,870
|
390
|
699
|
3,014
|
4,568
|
Remainder
|
3
|
9
|
-
|
-
|
3
|
9
|
Total
(1)
|
2,627
|
3,878
|
390
|
699
|
3,017
|
4,577
|
10%
Discounted
|
2,134
|
2,941
|
331
|
558
|
2,465
|
3,499
|
(1)
|
Numbers may not add
due to rounding.
|
CONFERENCE CALL DETAILS
Crescent Point management will host a conference call on
Thursday, March 3, 2022 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.
2022 GUIDANCE
The Company's guidance for 2022 is as follows:
Total Annual
Average Production (boe/d) (1)
|
133,000 -
137,000
|
Capital
Expenditures
|
|
Development capital
expenditures ($ millions)
|
$825 -
$900
|
Capitalized G&A
($ millions)
|
$40
|
Total ($ million)
(2)
|
$865 -
$940
|
Other Information
for 2022 Guidance
|
|
Reclamation
activities ($ millions) (3)
|
$20
|
Capital lease
payments ($ millions)
|
$20
|
Annual operating
expenses ($/boe)
|
$13.25 -
$13.75
|
Royalties
|
12.5% -
13.5%
|
1)
|
Total annual average
production (boe/d) is comprised of approximately 80% Oil & NGLs
and 20% Natural Gas
|
2)
|
Land expenditures and
net property acquisitions and dispositions are not included.
Development capital expenditures spend is allocated on an
approximate basis as follows: 85% drilling & development and
15% facilities & seismic
|
3)
|
Reflects Crescent
Point's portion of its expected total budget
|
The Company's audited financial statements and management's
discussion and analysis for the year ended December 31, 2021, will be available on the
System for Electronic Document Analysis and Retrieval ("SEDAR") at
www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml and on Crescent
Point's website at www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
|
Three months ended
December 31
|
Year ended December
31
|
(Cdn$ millions except
per share and per boe amounts)
|
2021
|
2020
|
2021
|
2020
|
Financial
|
|
|
|
|
Cash flow from
operating activities
|
492.4
|
245.1
|
1,495.8
|
860.5
|
Adjusted funds flow
from operations
|
432.5
|
220.2
|
1,476.9
|
874.4
|
Per share
(2)
|
0.74
|
0.41
|
2.57
|
1.64
|
Net income
(loss)
|
121.6
|
(51.2)
|
2,364.1
|
(2,519.9)
|
Per share
(2)
|
0.21
|
(0.10)
|
4.11
|
(4.76)
|
Adjusted net earnings
from operations (1)
|
160.0
|
85.6
|
515.3
|
177.4
|
Per share (1)
(2)
|
0.27
|
0.16
|
0.90
|
0.33
|
Dividends
declared
|
26.0
|
1.4
|
47.8
|
9.4
|
Per share
(2)
|
0.0450
|
0.0025
|
0.0825
|
0.0175
|
Net debt
|
2,005.0
|
2,149.2
|
2,005.0
|
2,149.2
|
Net debt to adjusted
funds flow from operations (3)
|
1.4
|
2.5
|
1.4
|
2.5
|
Weighted average
shares outstanding
|
|
|
|
|
Basic
|
582.1
|
530.0
|
569.2
|
529.3
|
Diluted
|
587.7
|
534.4
|
575.1
|
531.8
|
Operating
|
|
|
|
|
Average daily
production
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
88,544
|
87,512
|
95,839
|
95,859
|
NGLs
(bbls/d)
|
20,884
|
13,033
|
17,769
|
14,542
|
Natural gas
(mcf/d)
|
125,871
|
64,033
|
114,452
|
67,447
|
Total
(boe/d)
|
130,407
|
111,217
|
132,683
|
121,642
|
Average selling
prices (4)
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
91.27
|
49.40
|
78.43
|
43.50
|
NGLs
($/bbl)
|
47.59
|
24.96
|
42.33
|
17.19
|
Natural gas
($/mcf)
|
5.66
|
3.42
|
4.51
|
3.02
|
Total
($/boe)
|
75.05
|
43.76
|
66.21
|
38.01
|
Netback ($/boe)
|
|
|
|
|
Oil and gas
sales
|
75.05
|
43.76
|
66.21
|
38.01
|
Royalties
|
(9.57)
|
(5.65)
|
(8.44)
|
(4.88)
|
Operating
expenses
|
(12.85)
|
(13.30)
|
(12.91)
|
(12.62)
|
Transportation
expenses
|
(2.48)
|
(2.29)
|
(2.43)
|
(2.27)
|
Operating
netback
|
50.15
|
22.52
|
42.43
|
18.24
|
Realized gain (loss)
on commodity derivatives
|
(9.60)
|
4.03
|
(7.45)
|
5.52
|
Other
(5)
|
(4.50)
|
(5.03)
|
(4.48)
|
(4.12)
|
Adjusted funds flow
from operations netback (1)
|
36.05
|
21.52
|
30.50
|
19.64
|
Capital
Expenditures
|
|
|
|
|
Capital acquisitions
(6)
|
5.2
|
—
|
942.4
|
1.4
|
Capital dispositions
(6)
|
(0.1)
|
1.1
|
(99.0)
|
(508.2)
|
Development capital
expenditures
|
|
|
|
|
Drilling and
development
|
198.9
|
152.3
|
523.7
|
586.5
|
Facilities and
seismic
|
30.6
|
17.1
|
100.5
|
68.3
|
Total
|
229.5
|
169.4
|
624.2
|
654.8
|
Land
expenditures
|
0.8
|
0.8
|
4.9
|
3.6
|
(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", "excess cash flow",
"net debt", "net debt to adjusted funds flow" (equivalent to "net
debt to adjusted funds flow from operations"), "recycle ratio",
"total operating netback", "total netback", "operating netback",
"netback", "adjusted funds flow from operations netback" and
"adjusted working capital 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, 2021, 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)
|
2021
|
|
2020
|
|
% Change
|
|
2021
|
|
2020
|
|
% Change
|
|
Oil and gas
sales
|
900.4
|
|
447.8
|
|
101
|
|
3,206.5
|
|
1,692.2
|
|
89
|
|
Royalties
|
(114.8)
|
|
(57.8)
|
|
99
|
|
(408.8)
|
|
(217.1)
|
|
88
|
|
Operating
expenses
|
(154.2)
|
|
(136.1)
|
|
13
|
|
(625.3)
|
|
(561.8)
|
|
11
|
|
Transportation
expenses
|
(29.8)
|
|
(23.4)
|
|
27
|
|
(117.7)
|
|
(101.1)
|
|
16
|
|
Total operating
netback
|
601.6
|
|
230.5
|
|
161
|
|
2,054.7
|
|
812.2
|
|
153
|
|
Realized gain (loss)
on commodity derivatives
|
(115.2)
|
|
41.2
|
|
(380)
|
|
(360.8)
|
|
245.7
|
|
(247)
|
|
Total
netback
|
486.4
|
|
271.7
|
|
79
|
|
1,693.9
|
|
1,057.9
|
|
60
|
|
Other
(1)
|
(53.9)
|
|
(51.5)
|
|
5
|
|
(217.0)
|
|
(183.5)
|
|
18
|
|
Total adjusted funds
flow from operations netback
|
432.5
|
|
220.2
|
|
96
|
|
1,476.9
|
|
874.4
|
|
69
|
|
|
|
(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 and excess cash
flow:
|
Three months ended
December 31
|
|
Year ended December
31
|
|
($
millions)
|
2021
|
|
2020
(1)
|
|
% Change
|
|
2021
|
|
2020
(1)
|
|
% Change
|
|
Cash flow from
operating activities
|
492.4
|
|
245.1
|
|
101
|
|
1,495.8
|
|
860.5
|
|
74
|
|
Changes in non-cash
working capital
|
(69.1)
|
|
(29.0)
|
|
138
|
|
(51.6)
|
|
(6.2)
|
|
732
|
|
Transaction
costs
|
0.3
|
|
—
|
|
100
|
|
12.5
|
|
5.4
|
|
131
|
|
Decommissioning
expenditures (2)
|
8.9
|
|
4.1
|
|
117
|
|
20.2
|
|
14.7
|
|
37
|
|
Adjusted funds flow
from operations
|
432.5
|
|
220.2
|
|
96
|
|
1,476.9
|
|
874.4
|
|
69
|
|
Capital
expenditures
|
(242.9)
|
|
(181.6)
|
|
34
|
|
(676.1)
|
|
(698.8)
|
|
(3)
|
|
Payments on lease
liability
|
(5.6)
|
|
(5.2)
|
|
8
|
|
(21.2)
|
|
(30.0)
|
|
(29)
|
|
Decommissioning
expenditures
|
(8.9)
|
|
(4.1)
|
|
117
|
|
(20.2)
|
|
(14.7)
|
|
37
|
|
Other items
(3)
|
7.3
|
|
13.1
|
|
(44)
|
|
29.0
|
|
0.5
|
|
5,700
|
|
Excess cash
flow
|
182.4
|
|
42.4
|
|
330
|
|
788.4
|
|
131.4
|
|
500
|
|
(1)
|
Comparative period
revised to reflect current year presentation.
|
(2)
|
Excludes amounts
received from government subsidy programs.
|
(3)
|
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. It is used as a key measure to assess
the ability of the Company to finance dividends, operating
activities, capital expenditures and debt repayments.
The following table reconciles adjusted working capital
deficiency:
($
millions)
|
2021
|
|
2020
|
|
% Change
|
|
Accounts payable and
accrued liabilities
|
450.7
|
|
310.3
|
|
45
|
|
Dividends
payable
|
43.5
|
|
1.3
|
|
3,246
|
|
Long-term
compensation liability (1)
|
42.6
|
|
16.3
|
|
161
|
|
Cash
|
(13.5)
|
|
(8.8)
|
|
53
|
|
Accounts
receivable
|
(314.3)
|
|
(200.5)
|
|
57
|
|
Prepaids and
deposits
|
(7.4)
|
|
(22.7)
|
|
(67)
|
|
Long-term
investments
|
—
|
|
(2.5)
|
|
(100)
|
|
Adjusted working
capital deficiency
|
201.6
|
|
93.4
|
|
116
|
|
(1)
|
Includes current
portion of long-term compensation liability and is net of equity
derivative contracts.
|
The following table reconciles long-term debt to net debt:
($
millions)
|
2021
|
|
2020
|
|
% Change
|
|
Long-term debt
(1)
|
1,970.2
|
|
2,259.6
|
|
(13)
|
|
Adjusted working
capital deficiency
|
201.6
|
|
93.4
|
|
116
|
|
Unrealized foreign
exchange on translation of US dollar long-term debt
|
(166.8)
|
|
(203.8)
|
|
(18)
|
|
Net debt
|
2,005.0
|
|
2,149.2
|
|
(7)
|
|
(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)
|
2021
|
|
2020
|
|
% Change
|
|
2021
|
|
2020
|
|
% Change
|
|
Net income
(loss)
|
121.6
|
|
(51.2)
|
|
(338)
|
|
2,364.1
|
|
(2,519.9)
|
|
(194)
|
|
Amortization of
E&E undeveloped land
|
9.6
|
|
13.9
|
|
(31)
|
|
51.0
|
|
71.9
|
|
(29)
|
|
Impairment
(impairment reversal)
|
—
|
|
—
|
|
100
|
|
(2,514.4)
|
|
3,557.8
|
|
(171)
|
|
Unrealized derivative
(gains) losses
|
(87.1)
|
|
185.5
|
|
(147)
|
|
141.4
|
|
112.5
|
|
26
|
|
Unrealized foreign
exchange gain on translation of
hedged US dollar long-term debt
|
(13.1)
|
|
(86.2)
|
|
(85)
|
|
(37.0)
|
|
(62.1)
|
|
(40)
|
|
Unrealized (gain)
loss on long-term investments
|
—
|
|
(0.9)
|
|
(100)
|
|
(3.1)
|
|
4.2
|
|
(174)
|
|
Gain on sale of
long-term investments
|
—
|
|
—
|
|
(100)
|
|
(7.0)
|
|
—
|
|
(100)
|
|
Net gain on capital
dispositions
|
—
|
|
(8.5)
|
|
(100)
|
|
(58.4)
|
|
(316.4)
|
|
(82)
|
|
Deferred tax
adjustments
|
129.0
|
|
33.0
|
|
291
|
|
578.7
|
|
(670.6)
|
|
(186)
|
|
Adjusted net earnings
from operations
|
160.0
|
|
85.6
|
|
87
|
|
515.3
|
|
177.4
|
|
190
|
|
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.
Excess cash flow forecasted for 2022 is a forward-looking
non-GAAP measure and is calculated consistently with the measure
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, 2021.
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: excess
cash flow generation in 2022; timing and amount of share
repurchases and renewal of NCIB program; retention of significant
liquidity; the risk management program protects cash flow
generation; the Company remaining disciplined in its hedging
program; the Company's strengthening financial position; well cost
savings providing additional insulation to the Company's capital
budget in the current inflationary environment; the Company seeking
to further enhance returns in the Kaybob-Duvernay play, through
ongoing drilling and completions optimization; sustainable cost
efficiencies; Kaybob Duvernay wells generating full-cycle rates of
return of over 120 percent and payout in less than a year, at
current commodity priced and budged cost inflation
assumptions; the Company's 2022 waterflood program; continued
progression of decline mitigation programs; target for emissions
intensity reduction to 50 percent of 2017 levels by 2025, including
a 70 percent reduction in methane emissions (compared to 2017
levels); Crescent Point on track to meet or exceed its existing
emissions targets before 2025 and plans to revisit its current
emissions reduction goals in second quarter 2022; plans to retire
approximately 350 wells in 2022; prospects for the Kaybob Duvernay
assets; the opportunity to enhance shareholder value through
potential cost efficiencies, productivity improvements, new
locations and reserves; 2P reserves life index; the Company is on
track to meet its 2022 average production guidance of 133,000 to
137,000 boe/d within its development capital expenditures budget of
$825 to $900
million; management remains disciplined and focused on
generating significant excess cash flow to create shareholder
value; Crescent Point's 5 year plan and related FDC spending;
assuming US$80/bbl WTI, Crescent
Point's budget is expected to generate approximately $1.1 billion of excess cash flow in 2022;
prioritized balance sheet; moving toward the Company's near-term
leverage target of approximately 1.0 times net debt to adjusted
funds flow at US$55/bbl WTI, or
approximately $1.3 to $1.4 billion of absolute net debt; at current
commodity prices, the Company expects to achieve its near-term debt
target over the next six months; Crescent Point's plans to provide
increased returns to shareholders alongside a more defined return
of capital framework as the balance sheet strengthens; the
Company's commitment to a model that returns capital to
shareholders while also generating additional returns through
debt-adjusted per share growth; Crescent Point's 2022 production
and development capital expenditures guidance; and other
information for Crescent Point's 2022 guidance, including
capitalized G&A, reclamation activities, capital lease
payments, operating expenses and royalties.
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, 2021. 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, 2021, 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,
2021 under "Risk Factors" and our Management's Discussion
and Analysis for the year ended December 31,
2021, 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, 2021, 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 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.
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 2021 and 2020, the
aggregate average production for fourth quarter of 2021 and 2020,
and the references to "natural gas" and "crude oil", 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
|
|
2021
|
2020
|
2021
|
2020
|
Light & Medium
Crude Oil (bbl/d)
|
15,517
|
21,025
|
17,859
|
20,842
|
Heavy Crude Oil
(bbl/d)
|
4,226
|
4,276
|
4,203
|
4,380
|
Tight Oil
(bbl/d)
|
55,965
|
62,211
|
62,492
|
70,637
|
Total Crude Oil
(bbl/d)
|
75,708
|
87,512
|
84,554
|
95,859
|
|
|
|
|
|
NGLs
(bbl/d)
|
33,720
|
13,033
|
29,054
|
14,542
|
|
|
|
|
|
Shale Gas
(mcf/d)
|
115,482
|
52,370
|
103,124
|
53,666
|
Conventional Natural
Gas (mcf/d)
|
10,389
|
11,663
|
11,328
|
13,781
|
Total Natural Gas
(mcf/d)
|
125,871
|
64,033
|
114,452
|
67,447
|
|
|
|
|
|
Total
(boe/d)
|
130,407
|
111,217
|
132,683
|
121,642
|
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.
Full cycle rate of return is the internal
rate of return of a well including the drilling, completion,
equipping, tie-in and facility costs of the project.
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, 2021 escalated price forecast, the fair value for the
Company's oil and gas hedges based on such December 31, 2021 escalated price forecast, and
less outstanding net debt. The NAV per share is calculated on a
fully diluted basis.
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.
Reserves 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, 2021.
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" 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.
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. All of the required information will be contained in the
Company's Annual Information Form for the year ended December 31, 2021, which will be filed on SEDAR
(accessible at www.sedar.com) and EDGAR (accessible at
www.sec.gov/edgar.shtml) on or before March 3, 2022 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.
View original
content:https://www.prnewswire.com/news-releases/crescent-point-announces-2021-results--reserves-and-increases-share-repurchases-301494672.html
SOURCE Crescent Point Energy Corp.