CALGARY, AB, Feb. 24, 2021 /CNW/ - Crescent Point Energy
Corp. ("Crescent Point" or the "Company") (TSX: CPG) (NYSE: CPG) is
pleased to announce its operating and financial results for the
year ended December 31, 2020.
Crescent Point recently announced an accretive acquisition of
Kaybob Duvernay assets for $900
million (the "Acquisition") that further enhances the
Company's balance sheet strength and sustainability, including its
expected free cash flow generation. For more information on the
Acquisition, which is expected to close in April 2021, please refer to the news release
dated February 17, 2021.
KEY HIGHLIGHTS
- Achieved annual average production ahead of 2020 guidance with
capital expenditures under budget.
- Reduced net debt by over $615
million in 2020, driven by an accretive disposition and
excess cash flow generation.
- Enhanced sustainability by reducing costs throughout the
organization and lowering the production decline rate.
- Increased proved plus probable net asset value per share,
excluding changes in pricing, by approximately 13 percent.
- Released second annual sustainability report and established an
emissions intensity reduction target of 30 percent by 2025.
- Disciplined 2021 budget expected to generate $375 to $600
million of excess cash flow at US$50/bbl to US$60/bbl WTI.
"Our success over this past year highlights our resiliency,
discipline and flexibility," said Craig
Bryksa, President and CEO of Crescent Point. "As a result of
the volatility in 2020, we acted swiftly, revising our capital
program and operations, to enhance our financial flexibility and
preserve the long-term value of our assets. Through our actions,
over the last two years, we strengthened the Company and positioned
ourselves to continue enhancing value for our stakeholders. Our
recently announced acquisition of Kaybob Duvernay assets
demonstrates this execution. These assets strengthen our expected
free cash flow generation, leverage ratios and depth of
high-quality inventory, within a transaction that is highly
accretive on all financial metrics."
FINANCIAL HIGHLIGHTS
- For the year ended December 31,
2020, the Company's adjusted funds flow totaled $874.4 million, or $1.64 per share diluted. In the fourth quarter,
adjusted funds flow totaled $220.2
million, or $0.41 per share
diluted.
- For the year ended December 31,
2020, Crescent Point's development capital expenditures,
which included drilling and development, facilities and seismic,
totaled $654.8 million, including
$169.4 million spent during fourth
quarter. As a result, the Company's 2020 development capital
expenditures were below its most recent annual guidance of
$665 million.
- As at December 31, 2020, Crescent
Point's net debt was approximately $2.1
billion. Management successfully reduced the Company's net
debt by over $615 million in 2020,
including approximately $40 million
in fourth quarter. Crescent Point's unutilized credit capacity is
expected to total approximately $2.0
billion upon closing of the Acquisition in April 2021. The Company's credit facilities are
not due for renewal until October
2023.
- As part of its risk management program to protect against
commodity price volatility, the Company maintains an active hedging
portfolio. Crescent Point will have approximately 30 percent of its
oil and liquids production, net of royalty interest, hedged through
the remainder of 2021 upon closing of the Acquisition. These hedges
primarily consist of swaps with an average price of over
CDN$60/bbl. Crescent Point plans to
remain disciplined in its approach to layering on additional
protection in the context of commodity prices.
- As previously announced, the Company recorded a non-cash asset
impairment charge of $3.6 billion
($2.7 billion after-tax) in first
quarter 2020, primarily due to a significant decrease in the
independent engineering price forecast. This resulted in Crescent
Point incurring a net loss of $2.5
billion for the year ended December
31, 2020. Neither the Company's adjusted funds flow, nor its
credit capacity were impacted by this charge, which is reversible
in future periods should there be indications of a change in value,
including higher forecast commodity prices. Crescent Point's
adjusted net earnings for the year ended December 31, 2020 were $177.4 million.
- Subsequent to the quarter, the Company declared a quarterly
cash dividend of $0.0025 per share
payable on April 1, 2021.
All financial figures
are approximate and in Canadian dollars unless otherwise noted.
This press release contains forward-looking information and
references to non-GAAP financial measures. Significant related
assumptions and risk factors, and reconciliations are described
under the Non-GAAP 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
- Annual average production in 2020 was 121,642 boe/d, slightly
above Crescent Point's production guidance of 121,000 boe/d.
Average production during fourth quarter was 111,217 boe/d,
reflecting the reduced capital budget announced earlier in the
year.
- Throughout 2020, the Company continued to optimize its
workflows and implement its operational technology ("OT") platform
across its Saskatchewan asset
base. As previously announced, through these initiatives, Crescent
Point removed approximately $60
million in budgeted operating expenses in 2020. The Company
plans to continue the rollout of its OT platform in 2021.
- At year-end 2020, the Company had successfully reduced its
average per well capital costs by over 10 percent, in-line with its
previously announced expectation. This improvement highlights the
benefits of Crescent Point's significant operational experience,
allowing for ongoing knowledge transfer and optimization within its
asset portfolio. The Company's 2021 budget does not include
additional efficiencies that it plans to seek throughout the
year.
- As part of Crescent Point's decline mitigation program, the
Company successfully converted over 130 producing wells to water
injection wells in 2020. A similar level of conversions is planned
for 2021. Crescent Point's base decline rate at the start of 2021
improved by approximately five percent, compared to the prior year,
and is expected to remain unchanged on a pro-forma basis at
approximately 25 percent. The Company's oil production currently
under waterflood accounts for approximately 25 percent of its
current total oil production, with a low decline rate of
approximately five percent. Crescent Point plans to continue
advancement of its waterflood program as only half of its currently
planned injector conversions across its resource plays have been
completed to-date. The Company also plans to pilot other enhanced
oil recovery techniques to further enhance its long-term free cash
flow generation and sustainability.
- As part of its continued commitment to strong environmental,
social and governance ("ESG") practices, the Company has set an
emissions intensity reduction target of 30 percent by 2025,
relative to its 2017 baseline. This target includes a 50 percent
reduction in methane emissions. Crescent Point is currently on
track to meet these targets. The Company also continues to allocate
capital towards reducing its asset retirement obligations ("ARO")
to minimize its environmental footprint. Including funding expected
to be received from government grants, Crescent Point plans to
reduce its standing well count by approximately 10 percent in 2021.
The recent Acquisition is expected to further enhance the Company's
ESG profile, with minimal ARO and a low emissions intensity
associated with the Kaybob Duvernay assets.
RESERVES HIGHLIGHTS
"Our 2020 reserves highlight the continued improvements we have
made to our cost structure, including lower future development
capital and operating expenses, in addition to economic reserves
additions through both our drilling and waterflood programs," said
Bryksa. "As a result of lower commodity prices during first quarter
2020, we prudently revised our budget and allocated our remaining
capital primarily to low-risk, high-return drilling locations.
Given the majority of these wells were previously booked as
undrilled locations, new reserves additions were not as meaningful
as in prior years. Nonetheless, we positively impacted our net
asset value in 2020 through our relentless focus on costs and debt
reduction and through our disciplined disposition strategy. We look
forward to developing the Kaybob Duvernay assets to further enhance
shareholder value, including potential reserves additions given the
significant undeveloped land included in the Acquisition."
- The Company's Proved plus Probable ("2P") net asset value
("NAV") was $8.53 per share at
year-end 2020, based on independent engineering pricing, excluding
land and seismic. This NAV forecast assumes an average WTI price of
approximately US$51/bbl in the first
five years. Excluding the changes in year-over-year pricing, the
Company increased its 2P NAV per share by approximately 13
percent.
- Crescent Point's 2P reserves at year-end 2020 totaled 665.3
million boe ("MMboe"). The Company's Proved ("1P") and Proved
Developed Producing ("PDP") reserves totaled 410.9 MMboe and 262.8
MMboe, respectively. Year-end 2020 reserves decreased in comparison
to the prior year primarily due to economic factors, resulting from
a lower independent engineering pricing forecast, which reduced 2P
reserves by 35.2 MMboe, 1P reserves by 39.4 MMboe and PDP reserves
by 19.3 MMboe.
- Crescent Point's 2P reserve life index ("RLI"), excluding the
recently announced Acquisition, increased to approximately 16.6
years, up from approximately 14.3 years in the prior year.
- The Company's 2P reserves continued to benefit from its
waterflood activities, which contributed approximately 4.9 MMboe of
reserves additions in 2020. Approximately 30 percent, or 193.7
MMboe, of Crescent Point's 2P reserves were under the influence of
secondary waterflood recovery at year-end 2020.
- The Company's 2P future development capital ("FDC") decreased
by approximately $925 million, or 18
percent, primarily driven by a reduction in its per well capital
costs and drilling of previously booked wells.
Additional information on the Company's 2020 reserves is
provided in its Annual Information Form ("AIF") for the year-ended
December 31, 2020. Crescent Point's
2P reserves from the Acquisition are 107.4 MMboe, which included
only 36 booked locations in comparison to approximately 200 net
internally identified locations.
OUTLOOK
Crescent Point's 2020 results demonstrated management's
resiliency, discipline and flexibility. Despite a challenging year
for the industry, the Company successfully and meaningfully
enhanced its balance sheet and sustainability.
Crescent Point expects to further enhance the business
throughout 2021 through the continued rollout of its OT platform,
ongoing drilling and completions optimization, decline mitigation
programs and effective risk mitigation strategies.
In addition to the expected accretion from the Acquisition,
management will also identify opportunities to further enhance
returns by successfully integrating the Kaybob Duvernay assets and
by seeking to deliver additional related cost efficiencies.
Crescent Point has a proven track record of material success in
realizing such efficiencies over the years, including in resource
plays with comparable well costs and development programs, such as
in North Dakota and its previously
owned Uinta Basin asset.
The Company expects to generate significant excess cash flow in
the current price environment, given its high-netback asset base,
which is expected to further improve following the closing of the
Acquisition. The Company is now expected to generate approximately
$375 million to $600 million of excess cash flow in 2021,
assuming an average WTI price of US$50/bbl to US$60/bbl for the year.
Management will remain disciplined in its allocation of excess
cash flow, which will initially be directed to further net debt
reduction, and will evaluate the return of additional capital to
shareholders in the context of its capital allocation framework and
leverage targets.
Summary of Reserves
The Company's reserves were independently evaluated by GLJ
Limited. ("GLJ") and Sproule Associates Limited ("Sproule") as at
December 31, 2020 and were aggregated
by GLJ. 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, 2020 (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
|
120,863
|
111,506
|
59,759
|
54,006
|
21,458
|
17,922
|
37,010
|
33,897
|
Proved Developed
Non-Producing
|
6,209
|
5,290
|
1,453
|
1,346
|
2,058
|
1,816
|
1,649
|
1,376
|
Proved
Undeveloped
|
79,190
|
70,701
|
22,242
|
20,589
|
1,420
|
1,229
|
19,422
|
17,244
|
Total
Proved
|
206,262
|
187,497
|
83,454
|
75,941
|
24,935
|
20,966
|
58,082
|
52,517
|
Total
Probable
|
136,923
|
124,744
|
53,678
|
48,998
|
6,665
|
5,355
|
33,832
|
30,689
|
Total Proved plus
Probable
|
343,185
|
312,241
|
137,131
|
124,939
|
31,600
|
26,321
|
91,914
|
83,206
|
|
|
|
|
|
Shale Gas
(MMcf)
|
Natural
Gas
(MMcf)
|
Total
(Mboe)
|
Reserves
Category
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Proved Developed
Producing
|
101,526
|
92,300
|
40,591
|
38,530
|
262,775
|
239,136
|
Proved Developed
Non-Producing
|
4,339
|
3,659
|
1,227
|
1,014
|
12,297
|
10,607
|
Proved
Undeveloped
|
70,873
|
61,510
|
10,224
|
9,408
|
135,790
|
121,582
|
Total
Proved
|
176,738
|
157,469
|
52,042
|
48,952
|
410,862
|
371,325
|
Total
Probable
|
110,880
|
99,166
|
29,381
|
27,312
|
254,476
|
230,865
|
Total Proved plus
Probable
|
287,618
|
256,635
|
81,423
|
76,264
|
665,338
|
602,190
|
(1)
|
Based on Sproule's
December 31, 2020, 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, 2020 (1)
(2)
|
|
|
|
|
|
|
Before Tax Net
Present Value ($ millions)
|
|
|
|
Discount
Rate
|
Price
Deck
|
Reserves
Category
|
Gross Reserves
(Mboe)
|
0%
|
5%
|
10%
|
15%
|
Sproule
Forecast
|
Proved Developed
Producing
|
262,775
|
4,795
|
4,017
|
3,358
|
2,884
|
Proved and Probable
Developed Producing
|
361,172
|
7,867
|
5,770
|
4,509
|
3,718
|
Total
Proved
|
410,862
|
6,644
|
5,195
|
4,115
|
3,367
|
Total Proved plus
Probable
|
665,338
|
13,464
|
9,189
|
6,731
|
5,223
|
(1)
|
Sproule Forecast
based on Sproule's December 31, 2020, 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
Probable
|
Proved
|
Probable
|
Proved
plus
Probable
|
December 31,
2019
|
235,043
|
150,052
|
385,094
|
100,947
|
58,348
|
159,295
|
27,799
|
6,894
|
34,693
|
Extensions and
Improved Recovery
|
5,722
|
4,054
|
9,776
|
1,693
|
(946)
|
747
|
-
|
-
|
-
|
Technical
Revisions
|
4,936
|
(18,289)
|
(13,354)
|
4,402
|
(4,687)
|
(285)
|
21
|
73
|
94
|
Acquisitions
|
126
|
78
|
204
|
30
|
7
|
37
|
-
|
-
|
-
|
Dispositions
|
(83)
|
(26)
|
(109)
|
(1,848)
|
(1,454)
|
(3,303)
|
-
|
-
|
-
|
Economic
Factors
|
(13,629)
|
1,055
|
(12,574)
|
(14,142)
|
2,410
|
(11,732)
|
(1,283)
|
(301)
|
(1,584)
|
Production
|
(25,853)
|
-
|
(25,853)
|
(7,628)
|
-
|
(7,628)
|
(1,603)
|
-
|
(1,603)
|
December 31,
2020
|
206,262
|
136,923
|
343,185
|
83,454
|
53,678
|
137,131
|
24,935
|
6,665
|
31,600
|
|
|
|
|
|
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,
2019
|
63,062
|
33,315
|
96,377
|
179,325
|
103,163
|
282,488
|
72,086
|
33,640
|
105,726
|
Extensions and
Improved Recovery
|
994
|
253
|
1,247
|
2,969
|
1,827
|
4,796
|
631
|
(106)
|
526
|
Technical
Revisions
|
5,187
|
(413)
|
4,774
|
23,892
|
2,904
|
26,796
|
4,398
|
(1,270)
|
3,128
|
Acquisitions
|
19
|
10
|
29
|
54
|
28
|
82
|
-
|
-
|
-
|
Dispositions
|
(105)
|
(63)
|
(168)
|
(76)
|
(23)
|
(99)
|
(1,972)
|
(2,153)
|
(4,125)
|
Economic
Factors
|
(5,754)
|
730
|
(5,023)
|
(9,785)
|
2,981
|
(6,804)
|
(18,058)
|
(730)
|
(18,788)
|
Production
|
(5,322)
|
-
|
(5,322)
|
(19,642)
|
-
|
(19,642)
|
(5,044)
|
-
|
(5,044)
|
December 31,
2020
|
58,082
|
33,832
|
91,914
|
176,738
|
110,880
|
287,618
|
52,042
|
29,381
|
81,423
|
|
|
|
Total Oil
Equivalent
(Mboe)
|
Factors
|
Proved
|
Probable
|
Proved
plus
Probable
|
December 31,
2019
|
468,753
|
271,409
|
740,161
|
Extensions and
Improved Recovery
|
9,010
|
3,648
|
12,657
|
Technical
Revisions
|
19,261
|
(23,043)
|
(3,782)
|
Acquisitions
|
184
|
100
|
284
|
Dispositions
|
(2,377)
|
(1,906)
|
(4,283)
|
Economic
Factors
|
(39,447)
|
4,269
|
(35,178)
|
Production
|
(44,521)
|
-
|
(44,521)
|
December 31,
2020
|
410,862
|
254,476
|
665,338
|
(1)
|
Based on Sproule's
December 31, 2020, 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 and Development Costs
The Company's F&D costs and recycle ratios for year-end 2020
may not be meaningful or comparable to prior year results due to a
number of factors, including both a significantly lower commodity
price forecast, which impacted economic revisions, and a
significant reduction in FDC relative to total capital
expenditures.
|
|
|
|
|
2020
Totals
|
Change in
FDC
|
Total
|
Capital ($
millions) (1)
|
|
|
|
Total Proved plus
Probable
|
658
|
(908)
|
(250)
|
Total
Proved
|
658
|
(876)
|
(218)
|
Proved Developed
Producing
|
658
|
(3)
|
655
|
|
|
|
|
Reserves Additions
(Mboe) (2)
|
|
|
|
Total Proved plus
Probable
|
(26,303)
|
-
|
(26,303)
|
Total
Proved
|
(11,177)
|
-
|
(11,177)
|
Proved Developed
Producing
|
4,173
|
-
|
4,173
|
(1)
|
The capital
expenditures include the announced purchase price of corporate
acquisitions rather than the amounts allocated to property, plant
and equipment for accounting purposes. The capital expenditures
also exclude capitalized administration costs and transaction
costs.
|
(2)
|
Gross Company
interest reserves are used in this calculation (working interest
reserves, before deduction of any royalties and without including
any royalty interests of the Company).
|
|
|
|
|
Excluding changes
in FDC
|
Including changes
in FDC
|
|
($/boe, except
recycle ratios)
|
($/boe, except
recycle ratios)
|
|
2020
|
2019
|
3 Years Ended
Dec. 31, 2020
(Weighted Avg.)
|
2020
|
2019
|
3 Years Ended
Dec. 31, 2020
(Weighted Avg.)
|
F&D Cost
(1)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
($25.03)
|
($118.27)
|
$67.00
|
$9.49
|
($100.09)
|
$56.09
|
Total
Proved
|
($58.91)
|
$158.85
|
$49.23
|
$19.50
|
$151.57
|
$40.50
|
Proved Developed
Producing
|
$157.78
|
$47.32
|
$34.92
|
$157.06
|
$47.03
|
$34.33
|
|
|
|
|
|
|
|
Recycle Ratio
(2)
|
|
|
|
|
|
|
Total Proved plus
Probable
|
(0.7)
|
(0.3)
|
0.5
|
1.9
|
(0.3)
|
0.5
|
Total
Proved
|
(0.3)
|
0.2
|
0.6
|
0.9
|
0.2
|
0.7
|
Proved Developed
Producing
|
0.1
|
0.7
|
0.9
|
0.1
|
0.7
|
0.9
|
(1)
|
F&D is calculated
by dividing the identified capital expenditures by the applicable
reserves additions. F&D can include or exclude changes to
future development capital costs.
|
(2)
|
Recycle Ratio is
calculated as operating netback before hedging divided by F&D
costs. Based on a 2020 operating netback of $18.24 per boe, a 2019
operating netback of $33.81 per boe and a three-year weighted
average operating netback of $30.36 per boe.
|
Future Development Capital
At year-end 2020, FDC for 2P reserves totaled $4.2 billion, compared to $5.1 billion at year-end 2019. The Company's FDC
decreased by approximately $925
million, primarily driven by lower per well capital costs
and drilling of previously booked wells.
|
Company Annual
Capital Expenditures ($ millions)
|
|
Canada
|
U.S.
|
Total
|
Year
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
Total
Proved
|
Total
Proved
+ Probable
|
2020
|
292
|
350
|
19
|
38
|
311
|
388
|
2021
|
478
|
571
|
71
|
71
|
549
|
643
|
2022
|
431
|
628
|
207
|
208
|
638
|
836
|
2023
|
351
|
663
|
206
|
206
|
557
|
869
|
2024
|
197
|
570
|
266
|
268
|
463
|
838
|
2025
|
18
|
342
|
-
|
141
|
18
|
483
|
2026
|
3
|
89
|
-
|
-
|
3
|
89
|
2027
|
1
|
2
|
-
|
-
|
1
|
2
|
2028
|
2
|
2
|
-
|
-
|
2
|
2
|
2029
|
1
|
1
|
-
|
-
|
1
|
1
|
2030
|
1
|
1
|
-
|
-
|
1
|
1
|
2031
|
2
|
1
|
-
|
-
|
2
|
1
|
Subtotal
(1)
|
1,777
|
3,221
|
770
|
933
|
2,547
|
4,154
|
Remainder
|
12
|
16
|
-
|
-
|
12
|
16
|
Total
(1)
|
1,789
|
3,237
|
770
|
933
|
2,559
|
4,170
|
10%
Discounted
|
1,434
|
2,432
|
564
|
668
|
1,999
|
3,100
|
(1)
|
Numbers may not add
due to rounding.
|
CONFERENCE CALL DETAILS
Crescent Point management will
host a conference call on Wednesday,
February 24, 2021 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 home page.
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.
2021 GUIDANCE
The Company's guidance for 2021 is as follows:
|
|
Total Annual
Average Production (boe/d) (1)
|
132,000 -
136,000
|
|
|
Capital
Expenditures
|
|
Development capital
expenditures ($ million)
|
$575 -
$625
|
Capitalized G&A
($ millions)
|
$35
|
Total ($ million)
(2)
|
$610 -
$660
|
|
|
Other Information
for 2021 Guidance
|
|
Reclamation
activities ($ million) (3)
|
$15
|
Capital lease
payments ($ million)
|
$20
|
Annual operating
expenses
|
$625 - $645
million
($12.75 - $13.25/boe)
|
Royalties
|
11.5% -
12.5%
|
1)
|
Total annual average
production (boe/d) is comprised of 87% Oil & NGLs and 13%
Natural Gas
|
2)
|
Land expenditures and
net property acquisitions and dispositions are not included.
Development capital expenditures spend is allocated as follows: 87%
drilling & development and 13% facilities &
seismic
|
3)
|
Reflects Crescent
Point's portion of its expected total budget
|
The Company's audited financial statements and management's
discussion and analysis for the year ended December 31, 2020, will be available on the
System for Electronic Document Analysis and Retrieval ("SEDAR") at
www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml and on
Crescent Point's website at www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
|
|
|
|
Three months ended
December 31
|
Year ended December
31
|
(Cdn$ millions except
per share and per boe amounts)
|
2020
|
2019
|
2020
|
2019
|
Financial
|
|
|
|
|
Cash flow from
operating activities
|
245.1
|
396.5
|
860.5
|
1,742.9
|
Adjusted funds flow
from operations (1)
|
220.2
|
418.4
|
874.4
|
1,825.4
|
Per share (1)
(2)
|
0.41
|
0.78
|
1.64
|
3.34
|
Net income
(loss)
|
(51.2)
|
(932.1)
|
(2,519.9)
|
(1,033.3)
|
Per share
(2)
|
(0.10)
|
(1.73)
|
(4.76)
|
(1.89)
|
Adjusted net earnings
from operations (1)
|
85.6
|
49.9
|
177.4
|
386.8
|
Per share (1)
(2)
|
0.16
|
0.09
|
0.33
|
0.71
|
Dividends
declared
|
1.4
|
5.4
|
9.4
|
22.0
|
Per share
(2)
|
0.0025
|
0.0100
|
0.0175
|
0.0400
|
Net debt
(1)
|
2,149.2
|
2,765.3
|
2,149.2
|
2,765.3
|
Net debt to adjusted
funds flow from operations (1) (3)
|
2.5
|
1.5
|
2.5
|
1.5
|
Weighted average
shares outstanding
|
|
|
|
|
Basic
|
530.0
|
537.4
|
529.3
|
545.7
|
Diluted
|
534.4
|
538.7
|
531.8
|
546.0
|
Operating
|
|
|
|
|
Average daily
production
|
|
|
|
|
Crude oil
(bbls/d)
|
87,512
|
111,394
|
95,859
|
126,219
|
NGLs
(bbls/d)
|
13,033
|
21,406
|
14,542
|
20,746
|
Natural gas
(mcf/d)
|
64,033
|
74,347
|
67,447
|
91,592
|
Total
(boe/d)
|
111,217
|
145,191
|
121,642
|
162,230
|
Average selling
prices (4)
|
|
|
|
|
Crude oil
($/bbl)
|
49.40
|
65.27
|
43.50
|
67.14
|
NGLs
($/bbl)
|
24.96
|
19.02
|
17.19
|
19.94
|
Natural gas
($/mcf)
|
3.42
|
3.35
|
3.02
|
2.75
|
Total
($/boe)
|
43.76
|
54.60
|
38.01
|
56.34
|
Netback ($/boe)
|
|
|
|
|
Oil and gas
sales
|
43.76
|
54.60
|
38.01
|
56.34
|
Royalties
|
(5.65)
|
(7.79)
|
(4.88)
|
(8.15)
|
Operating
expenses
|
(13.30)
|
(11.24)
|
(12.62)
|
(12.29)
|
Transportation
expenses
|
(2.29)
|
(2.12)
|
(2.27)
|
(2.09)
|
Operating netback
(1)
|
22.52
|
33.45
|
18.24
|
33.81
|
Realized gain (loss)
on derivatives
|
4.03
|
1.71
|
5.52
|
0.73
|
Other
(5)
|
(5.03)
|
(3.84)
|
(4.12)
|
(3.72)
|
Adjusted funds flow
from operations netback (1)
|
21.52
|
31.32
|
19.64
|
30.82
|
Capital
Expenditures
|
|
|
|
|
Capital acquisitions
(dispositions), net (6)
|
1.1
|
(663.8)
|
(506.8)
|
(924.1)
|
Development capital
expenditures
|
|
|
|
|
Drilling and
development
|
152.3
|
312.7
|
586.5
|
1,155.9
|
Facilities and
seismic
|
17.1
|
30.7
|
68.3
|
96.2
|
Total
|
169.4
|
343.4
|
654.8
|
1,252.1
|
Land
expenditures
|
0.8
|
5.2
|
3.6
|
15.5
|
(1)
|
Adjusted funds flow
from operations, adjusted funds flow from operations per share,
adjusted net earnings from operations, adjusted net earnings from
operations per share, net debt, net debt to adjusted funds flow
from operations, operating netback and adjusted funds flow from
operations netback as presented do not have any standardized
meaning prescribed by IFRS and, therefore, may not be comparable
with the calculation of similar measures presented by other
entities.
|
(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.
|
Non-GAAP Financial Measures
Throughout this press release, the Company uses the terms
"adjusted funds flow", "adjusted funds flow from operations",
"funds flow", "adjusted funds flow from operations per share -
diluted", "adjusted net earnings from operations", "adjusted net
earnings from operations per share - diluted", "free cash flow",
"excess cash flow", "net debt", "net debt to adjusted funds flow
from operations", "netback", "operating netback" and "adjusted
funds flow from operations netback". 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.
Adjusted funds flow and funds flow are equivalent to adjusted
funds flow from operations. Adjusted funds flow from operations is
calculated based on cash flow from operating activities before
changes in non-cash working capital, transaction costs and
decommissioning expenditures funded by the Company. Adjusted funds
flow from operations per share - diluted is calculated as adjusted
funds flow from operations divided by the number of weighted
average diluted shares outstanding. Transaction costs are
excluded as they vary based on the Company's acquisition and
disposition activity and to ensure that this metric is more
comparable between periods. Decommissioning expenditures are
discretionary and are excluded as they may vary based on the stage
of Company's assets and operating areas. Management utilizes
adjusted funds flow from operations as a key measure to assess the
ability of the Company to finance dividends, operating activities,
capital expenditures and debt repayments. Adjusted funds flow from
operations as presented is not intended to represent cash flow from
operating activities, net earnings or other measures of financial
performance calculated in accordance with IFRS. Excess cash flow is
defined as adjusted funds flow from operations less capital
expenditures, payments on lease liability, asset retirement
obligations, dividends and other cash items (excluding net
acquisitions and dispositions). Management utilizes excess cash
flow as a key measure to assess the ability of the Company to
finance dividends, potential share repurchases, debt repayments and
returns-based growth.
The following table reconciles cash flow from operating
activities to adjusted funds flow from operations:
|
|
|
|
|
|
Three months ended
December 31
|
Year Ended December
31
|
($
millions)
|
2020
|
2019
|
2020
|
2019
|
Cash flow from
operating activities
|
245.1
|
396.5
|
860.5
|
1,742.9
|
Changes in non-cash
working capital
|
(29.0)
|
6.6
|
(6.2)
|
47.5
|
Transaction
costs
|
—
|
2.1
|
5.4
|
6.3
|
Decommissioning
expenditures (1)
|
4.1
|
13.2
|
14.7
|
28.7
|
Adjusted funds flow
from operations
|
220.2
|
418.4
|
874.4
|
1,825.4
|
(1)
|
Excludes amounts
received from government subsidy programs.
|
Adjusted net earnings from operations is calculated based on net
income before amortization of exploration and evaluation
("E&E") undeveloped land, impairment or impairment recoveries,
unrealized derivative gains or losses, unrealized foreign exchange
gain or loss on translation of hedged US dollar long-term debt,
unrealized gains or losses on long-term investments, gains or
losses on the sale of long-term investments and gains or losses on
capital acquisitions and dispositions. Adjusted net earnings from
operations per share - diluted is calculated as adjusted net
earnings from operations divided by the number of weighted average
diluted shares outstanding. Management utilizes adjusted net
earnings from operations to present a measure of financial
performance that is more comparable between periods. Adjusted net
earnings from operations as presented is not intended to represent
net earnings or other measures of financial performance calculated
in accordance with IFRS.
The following table reconciles net income to adjusted net
earnings from operations:
|
|
|
|
Three months ended
December 31
|
Year ended December
31
|
($
millions)
|
2020
|
2019
|
2020
|
2019
|
Net income
(loss)
|
(51.2)
|
(932.1)
|
(2,519.9)
|
(1,033.3)
|
Amortization of
E&E undeveloped land
|
13.9
|
21.3
|
71.9
|
129.1
|
Impairment
|
—
|
1,216.5
|
3,557.8
|
1,466.4
|
Unrealized derivative
losses
|
185.5
|
153.9
|
112.5
|
269.6
|
Unrealized foreign
exchange gain on translation of hedged US dollar long-term
debt
|
(86.2)
|
(52.5)
|
(62.1)
|
(207.7)
|
Unrealized (gain)
loss on long-term investments
|
(0.9)
|
0.5
|
4.2
|
2.0
|
Net (gain) loss on
capital dispositions
|
(8.5)
|
(0.1)
|
(316.4)
|
199.2
|
Deferred tax relating
to adjustments
|
33.0
|
(357.6)
|
(670.6)
|
(438.5)
|
Adjusted net earnings
from operations
|
85.6
|
49.9
|
177.4
|
386.8
|
Free cash flow is calculated as adjusted funds flow from
operations less capital expenditures, payments on lease liability,
asset retirement obligations and other cash items (excluding net
acquisitions and dispositions). Management utilizes free cash flow
as a key measure to assess the ability of the Company to finance
dividends, potential share repurchases, debt repayments and
returns-based growth.
Net debt is calculated as long-term debt plus accounts payable
and accrued liabilities and long-term compensation liability, less
cash, accounts receivable, prepaids and deposits and long-term
investments, excluding the unrealized foreign exchange on
translation of US dollar long-term debt. Management utilizes net
debt as a key measure to assess the liquidity of the Company.
The following table reconciles long-term debt to net debt:
|
|
|
($
millions)
|
2020
|
2019
|
Long-term debt
(1)
|
2,259.6
|
2,905.1
|
Accounts payable and
accrued liabilities
|
311.6
|
479.4
|
Long-term
compensation liability (2)
|
16.3
|
13.1
|
Cash
|
(8.8)
|
(56.9)
|
Accounts
receivable
|
(200.5)
|
(295.9)
|
Prepaids and
deposits
|
(22.7)
|
(6.9)
|
Long-term
investments
|
(2.5)
|
(6.7)
|
Excludes:
|
|
|
Unrealized foreign
exchange on translation of hedged US dollar long-term
debt
|
(203.8)
|
(265.9)
|
Net debt
|
2,149.2
|
2,765.3
|
(1)
|
Includes current
portion of long-term debt.
|
(2)
|
Includes current
portion of long-term compensation liability and is net of equity
derivative contracts.
|
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. The ratio of net
debt to adjusted funds flow from operations is used by management
to measure the Company's overall debt position and to measure the
strength of the Company's balance sheet. Crescent Point monitors
this ratio and uses this as a key measure in making decisions
regarding financing, capital spending and dividend levels.
Operating netback is calculated on a per boe basis as oil and
gas sales, less royalties, operating and transportation expenses.
Adjusted funds flow netback is equivalent to adjusted funds flow
from operations netback. Adjusted funds flow from operations
netback is calculated on a per boe basis as operating netback less
net purchased products, realized derivative gains and losses,
general and administrative expenses, interest on long-term debt,
foreign exchange, cash-settled share-based compensation and certain
cash items, excluding transaction costs, foreign exchange on US
dollar long-term debt and certain non-cash items. Cash flow netback
is equivalent to adjusted funds flow from operations netback.
Operating netback and adjusted funds flow from operations netback
are common metrics used in the oil and gas industry and are used by
management to measure operating results on a per boe basis to
better analyze performance against prior periods on a comparable
basis. Netback calculations are shown in the Financial and
Operating Highlights section in this press release.
Management believes the presentation of the Non-GAAP 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: the
expected closing of the Kaybob Duvernay acquisition; the
expectation that the Kaybob Duvernay assets have minimal ARO and a
low emissions intensity; the Company's emissions intensity
reduction target of 30 percent by 2025, including a 50 reduction in
methane emissions by 2025; $375 to
$600 million of excess cash flow
generated in 2021 at $US50/bbl to
$US60/bbl WTI; preservation of the
long-term value of our assets; Crescent Point's positioning as
market conditions continue to improve; hedging program plans,
extent and expectations; the Company's positioning to continue
enhancing value for stakeholders; expectations of the acquisition
of the Kaybob Duvernay, including: strengthened free cash flow
generation, leverage ratios and depth of high-quality inventory, a
transaction that is highly accretive on all financial metrics, and
an enhanced Company ESG profile following the acquisition; dividend
payment values and dates; expectations of generating significant
excess cash flow in a rising price environment and the evaluation
of the return of additional capital to shareholders; plans to
continue the rollout of OT platform 2021; waterflood conversion
plans for 2021; further planned waterflood conversions; decline
rates; expected unutilized credit capacity; plans to pilot enhanced
oil recovery techniques, and benefits thereof; additional
environmental targets set in 2021; excepted 2021 standing well
count reduction; Kaybob Duvernay reserves additions; 2P NAV at
year-end 2020, based on independent engineering pricing, excluding
land and seismic, and an average WTI price of approximately
$51/bbl in the first five years;
potential for further cost efficiencies in the Kaybob Duvernay
assets; NPV values before tax; 2P RLI; 2P FDC; expectations of
further enhancing the business throughout 2021, and the components
thereof; opportunities to enhance returns through potential cost
efficiencies in the Kaybob Duvernay assets; that management will
remain disciplined in the allocation of excess cash flow and the
directions thereof; the evaluation of return of additional capital
shareholders; 2021 guidance including total annual average
production, capital expenditures (and proportion allocated to
drilling and development and facilities and seismic), capitalized
G&A, reclamation activities, capital lease payment, annual
operating expenses, annual average transportation costs, 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, 2020. 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, 2020, 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,
2020 under "Risk Factors" and our Management's Discussion
and Analysis for the year ended December 31,
2020, 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, 2020, under the headings
"Capital Expenditures", "Liquidity and Capital Resources",
"Critical Accounting Estimates", "Risk Factors", "Changes in
Accounting Policies" 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 the Acquisition; failure to complete the Acquisition; 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; the impact of the implementation of the
Canada-United States-Mexico
Agreement; uncertainty regarding the benefits and costs of
dispositions; failure to complete acquisitions and dispositions;
uncertainties associated with credit facilities and counterparty
credit risk; 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 2020 and 2019, the
aggregate average production for the fourth quarter of 2020 and
2019, 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
|
|
2020
|
2019
|
2020
|
2019
|
Light & Medium
Crude Oil (bbl/d)
|
21,025
|
25,366
|
20,842
|
30,094
|
Heavy Crude Oil
(bbl/d)
|
4,276
|
4,819
|
4,380
|
4,749
|
Tight Oil
(bbl/d)
|
62,211
|
81,209
|
70,637
|
91,376
|
Total Crude Oil
(bbl/d)
|
87,512
|
111,394
|
95,859
|
126,219
|
|
|
|
|
|
NGLs
(bbl/d)
|
13,033
|
21,406
|
14,542
|
20,746
|
|
|
|
|
|
Shale Gas
(Mcf/d)
|
52,370
|
56,446
|
53,666
|
71,749
|
Conventional Natural
Gas (Mcf/d)
|
11,663
|
17,901
|
13,781
|
19,843
|
Total Natural Gas
(Mcf/d)
|
64,033
|
74,347
|
67,447
|
91,592
|
|
|
|
|
|
Total
(boe/d)
|
111,217
|
145,191
|
121,642
|
162,230
|
DEFINITIONS
Decline rate is the reduction in the rate of
production from one period to the next. This rate is usually
expressed on an annual basis.
Finding and development (F&D) costs are
calculated by dividing the identified capital expenditures by the
applicable reserves additions. F&D costs can include or exclude
changes to future development capital costs.
Future development capital (FDC) reflects the
independent evaluator's 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 Sproule's December 31, 2020 escalated price forecast, the
fair value for the Company's oil and gas hedges based on Sproule's
December 31, 2020 escalated price
forecast, 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. Based on a 2020 netback (before
hedging), of $18.24 per boe, a 2019
netback (before hedging) of $33.81
per boe and a three-year weighted average netback (before hedging)
of $30.36 per boe.
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.
This press release contains metrics commonly used in the oil and
natural gas industry, including "netbacks", "F&D costs", "FDC",
"NAV", "recycle ratio", "reserve life index", and "decline rate".
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 changes in FDC have been presented in
this news release because they provide a useful measure of capital
efficiency. F&D costs, including land, facility and seismic
expenditures and excluding changes 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.
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.
The Company retained McDaniel & Associates Consultants Ltd.
("McDaniel") to evaluate the reserves associated with Kaybob
Duvernay assets and prepare the related independent evaluators
report (the "McDaniel Report"). The statement of reserves data and
other oil and gas information, associated with the Kaybob Duvernay
assets, set forth in this press release is dated February 11, 2021. The effective date of the
reserves information provided for the Kaybob Duvernay assets herein
is December 31, 2020, unless
otherwise indicated, and the preparation date is February 11, 2021. McDaniel prepared the McDaniel
Report in accordance with the standards contained in NI 51-101 and
the COGE Handbook that were in effect at the relevant time. This
press release discloses 36 booked drilling locations, which are
proved plus probable of approximately 200 potential net drilling
locations. Proved plus probable locations consist of proposed
drilling locations identified in the McDaniel Report that have
proved and/or probable reserves, as applicable, attributed to them.
The Company's ability to drill and develop these locations and the
drilling locations on which the Company actually drills wells
depends on a number of uncertainties and factors, including, but
not limited to, the availability of capital, equipment and
personnel, oil and natural gas prices, costs, inclement weather,
seasonal restrictions, drilling results, additional geological,
geophysical and reservoir information that is obtained, production
rate recovery, gathering system and transportation constraints, the
net price received for commodities produced, regulatory approvals
and regulatory changes. As a result of these uncertainties, there
can be no assurance that the potential future drilling locations
that the Company has identified will ever be drilled and, if
drilled, that such locations will result in additional crude oil,
natural gas or NGLs produced. As such, the Company's actual
drilling activities may differ materially from those presently
identified, which could adversely affect the Company's business.
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, 2020, which will be filed on SEDAR
(accessible at www.sedar.com) and EDGAR (accessible at
www.sec.gov/edgar.shtml) on or before February 24, 2021 and further supplemented by
Material Change Reports as applicable.
FOR MORE INFORMATION ON CRESCENT POINT ENERGY, PLEASE
CONTACT:
Brad Borggard, Senior
Vice President, Corporate Planning and Capital Markets, or
Shant Madian, Vice
President, Investor Relations and Corporate Communications
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.