CALGARY,
AB, March 6, 2024 /CNW/ - Paramount Resources
Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to
announce its 2023 annual financial and operating results,
highlighted by record production, and a $47
million non-core asset disposition. The Company is
also providing a production update and revised 2024 guidance.
2023 HIGHLIGHTS
- The Company achieved record annual sales volumes of 96,393
Boe/d (46% liquids) in 2023. Sales volumes in the fourth quarter
were 101,348 Boe/d (46% liquids), of which 72,860 Boe/d (51%
liquids) was produced in the Grande Prairie Region.
(1)
- Cash from operating activities was $938
million ($6.56 per basic
share) in 2023 and $287 million
($1.99 per basic share) in the fourth
quarter. (2)
- Adjusted funds flow was $965
million ($6.75 per basic
share) in 2023 and $284 million
($1.97 per basic share) in the fourth
quarter. (2)
- Capital expenditures totaled $732
million in 2023, which were largely directed to the Grande
Prairie Region Montney development and the Kaybob North and
Willesden Green Duvernay developments.
- Asset retirement obligation settlements totaled $55 million in 2023, which included the
abandonment of 82 wells and reclamation of 113 sites.
- Free cash flow was $168 million
($1.18 per basic share) in 2023 and
$60 million ($0.41 per basic share) in the fourth quarter.
(2)
- Paramount returned $355 million
to shareholders in 2023 comprised of $1.50 per share in regular monthly cash dividends
and a special cash dividend of $1.00
per share.
- The Company realized total cash proceeds of approximately
$45 million in the fourth quarter
from the previously disclosed termination and close out of its 2024
NYMEX WTI swaps.
__________
|
(1)
|
In this press release,
"liquids" refers to NGLs (including condensate) and oil
combined, "natural gas" refers to shale gas and conventional
natural gas combined, "condensate and oil" refers to condensate,
light and medium crude oil, tight oil and heavy crude oil combined
and "Other NGLs" refers to ethane, propane and butane. See the
"Product Type Information" section for a complete breakdown of
sales volumes for applicable periods by the specific product types
of shale gas, conventional natural gas, NGLs, light and medium
crude oil, tight oil and heavy crude oil. See also "Oil and
Gas Measures and Definitions" in the Advisories section.
|
(2)
|
Adjusted funds flow and
free cash flow are capital management measures used by
Paramount. Cash from operating activities per basic share,
adjusted funds flow per basic share and free cash flow per basic
share are supplementary financial measures. Refer to the
"Specified Financial Measures" section for more information on
these measures.
|
- At December 31, 2023, net debt
was $60 million and Paramount's
$1.0 billion revolving credit
facility was undrawn. (1)
- The carrying value of the Company's investments in securities
at December 31, 2023 was $541 million. Paramount received total cash
dividends of $8 million in 2023 from
these investments.
2023 RESERVES
- At December 31, 2023, the
Company's: (2)
- proved developed producing ("PDP") reserves were 165 MMBoe with
an NPV10 of approximately $2.1
billion ($14.57 per basic
share);
- total proved ("TP") reserves were 415 MMBoe with an
NPV10 of approximately $4.5
billion ($31.60 per basic
share); and
- proved plus probable ("P+P") reserves were 761 MMBoe with an
NPV10 of approximately $7.9
billion ($55.04 per basic
share).
- Paramount's reserves replacement ratios in 2023 were 1.4x for
PDP reserves, 1.2x for TP reserves and 2.8x for P+P reserves.
(3)
- The Company's 2023 and three-year average F&D costs and
recycle ratios are as follows: (4)
|
2023
|
Three-Year
Average
|
F&D Costs
($/Boe)
|
Recycle
Ratio
|
F&D Costs
($/Boe)
|
Recycle
Ratio
|
PDP
|
$16.58
|
1.6x
|
$10.89
|
3.0x
|
TP
|
$16.96
|
1.6x
|
$12.39
|
2.6x
|
P+P
|
$12.52
|
2.2x
|
$10.57
|
3.1x
|
- Dispositions in 2023 resulted in reductions to the Company's
PDP reserves of 8.4 MMBoe, TP reserves of 35.6 MMBoe and P+P
reserves of 59.8 MMBoe.
NON-CORE ASSET DISPOSTION
The Company sold certain non-core assets in the Kaybob Region in
February 2024 for cash proceeds of
approximately $47 million and has
retained a 2% no-deduction gross overriding royalty on the
undeveloped Montney acreage forming part of the assets (the
"2024 Kaybob Disposition"). Paramount had previously forecast
these assets to generate approximately 1,000 Boe/d of average
annual sales volumes for 2024.
CORPORATE UPDATE
- In the fourth quarter of 2023, Paramount brought on production
a total of eleven (11.0 net) wells in the Grande Prairie Region,
consisting of a three well pad in Karr and an eight well pad in
Wapiti.
- In December, the Company successfully commissioned the liquids
handling expansion of its Leafland natural gas processing plant at
Willesden Green. The expansion was completed on budget and ahead of
the originally scheduled January 2024
startup. The plant now has raw handling capacity of approximately
6,000 Bbl/d of liquids and 22 MMcf/d of natural gas.
__________
|
(1)
|
Net (cash) debt is a
capital management measure used by Paramount. This capital
management measure has been expressed as net debt in this instance
for simplicity as the amount referenced is a positive number.
Refer to the "Specified Financial Measures" section for more
information on this measure.
|
(2)
|
All reserves are gross
reserves based on an evaluation prepared by McDaniel &
Associates Consultants Ltd. ("McDaniel") dated March 5, 2024 and
effective December 31, 2023 (the "McDaniel Report").
"NPV10" refers to the before tax net present value of
future net revenue of the applicable reserves, discounted at 10
percent, as estimated in the McDaniel Report. Such value does
not represent fair market value. Readers are referred to the
advisories concerning "Reserves Data".
|
(3)
|
See "Oil and Gas
Measures and Definitions" in the Advisories section of this
document for a description of the calculation and use of reserves
replacement ratio.
|
(4)
|
F&D costs and
recycle ratio are non-GAAP ratios. Refer to the "Specified
Financial Measures" section and "Oil and Gas Measures and
Definitions" in the Advisories section for more information on
these measures and on the related non-GAAP financial measure of
F&D capital.
|
- Paramount completed all four (4.0 net) Willesden Green Duvernay
wells from its 2023 development program in early December.
These wells are all now on production and have exhibited
strong results. Three of the wells averaged gross 30-day peak
production per well of 1,873 Boe/d (4.1 MMcf/d of shale gas and
1,195 Bbl/d of NGLs) with an average CGR of 294 Bbl/MMcf. The
fourth well has produced for 27 days and is exhibiting a similar
production profile. (1)
- The Company recently commenced construction of its second
natural gas processing facility at Willesden Green, with
start-up anticipated in the fourth quarter of 2025. This first
phase of the new facility will provide an estimated raw handling
capacity of 10,000 Bbl/d of liquids and 50 MMcf/d of natural
gas.
- All six (6.0 net) Kaybob North Duvernay wells that were
drilled in 2023 were recently brought on production and have
exhibited strong initial production rates.
PRODUCTION UPDATE AND REVISED 2024 GUIDANCE
Paramount is revising its forecast of 2024 sales volumes to a
range of 100,000 Boe/d to 106,000 Boe/d (47% liquids), 9,000 Boe/d
lower at the midpoint than prior guidance of 108,000 Boe/d to
116,000 Boe/d (47% liquids).
The significant factors contributing to the revision are
described below.
- The 2024 Kaybob Disposition completed in February has reduced
forecast 2024 average sales volumes by approximately 1,000
Boe/d.
- Paramount has shut-in dry gas production due to the current
natural gas price environment, reducing forecast 2024 average sales
volumes by approximately 2,250 Boe/d. The Company continues to
closely monitor market conditions and may restore or further reduce
production as conditions warrant.
- Sales volumes were approximately 95,000 Boe/d (46% liquids) in
January and 103,000 Boe/d (48% liquids) in February based on field
estimates, approximately 14,000 Boe/d lower on average across the
two months than expected. Cold weather in January resulted in a
number of significant production upsets, particularly in the Grande
Prairie Region. In addition, production was impacted by
intermittent run time at key facilities, an unplanned pipeline
outage in the Karr field that shut-in approximately 4,000 Boe/d of
production for two weeks and the outage of a water disposal well in
the Grande Prairie Region that will continue until the third
quarter of 2024.
- 2024 production expectations from the five (5.0 net) well Karr
7-33S pad that was brought onstream in the third quarter of 2023
have been downwardly revised by approximately 3,500 Boe/d (55%
liquids). Early production from the wells significantly exceeded
type curve expectations and the prior guidance forecasted
continued outperformance. The wells, which paid out in
approximately three months of being brought onstream, are now
performing in line with type curve expectations and the Company has
reduced forecast sales volumes for the pad accordingly.
- The Company has benefited from strong new well performance in
the Grande Prairie Region in growing its production base and
maximizing netbacks, leading to the optimization of production from
mature wells being deferred. There are currently 31 wells shut-in
and 13 wells that would benefit from intervention in the Grande
Prairie Region. The Company will incur incremental operating
expenditures to pursue an aggressive well optimization program
beginning in 2024 to increase production from these wells, the full
benefit of which has not been incorporated into the revised 2024
sales volume forecast.
___________
|
(1)
|
30-day peak production
is the highest daily average production rate for each well,
measured at the wellhead, over a rolling 30-day period, excluding
days when the well did not produce. Natural gas sales volumes
were lower by approximately 8% and liquids sales volumes were lower
by approximately 20% due to shrinkage. The production rates
and volumes stated are over a short period of time and, therefore,
are not necessarily indicative of average daily production,
long-term performance or of ultimate recovery from the wells. CGR
means condensate to gas ratio and is calculated by dividing raw
wellhead liquids volumes by raw wellhead natural gas volumes.
See "Oil and Gas Measures and Definitions" in the Advisories
section.
|
- In total, Grande Prairie Region sales volumes are forecast to
be approximately 6,000 Boe/d lower in 2024, primarily as a result
of the revised Karr 7-33S pad production, earlier than anticipated
tubing installations on certain wells at Karr due to higher than
expected CGRs and the rescheduling of the 21-day outage at the
third-party Wapiti natural gas processing plant from May to
September.
- The Company has increased forecasted sales volumes by a total
of 1,500 Boe/d in the Kaybob Region and Central Alberta and Other Region, largely due
to better than expected Duvernay
results.
The table below summarizes significant factors contributing to
the revision in Paramount's 2024 sales volumes guidance at the
midpoint:
|
Midpoint Annual
Average Sales
Volumes (Boe/d)
|
Prior 2024
guidance
|
112,000
|
2024
Kaybob Disposition
|
-1,000
|
Dry
gas production shut-ins
|
-2,250
|
January and February sales volumes lower than forecast
|
-1,250
|
Revisions to Grande Prairie Region forecast
|
-6,000
|
Revisions to Kaybob and Central Alberta and Other Region
forecasts
|
+1,500
|
Revised 2024
guidance
|
103,000
|
The Company is updating its forecast of 2024 free cash flow to
approximately $235 million from
$350 million to reflect revised
midpoint 2024 forecast sales volumes of 103,000 Boe/d (47% liquids)
and updated operating cost, royalty and other assumptions.
Free cash flow does not include the $47 million cash proceeds from the
2024 Kaybob Disposition.
|
Prior 2024
Guidance
|
Revised 2024
Guidance
|
WTI
|
US$80.00/Bbl
|
No change
|
NYMEX
|
US$3.50/MMBtu
|
AECO
|
$2.84/GJ
|
Annual average sales
volumes (Boe/d)
|
108,000 to 116,000 (47%
liquids)
|
100,000 to 106,000 (47%
liquids)
|
First half
2024 (Boe/d)
|
101,000 to 111,000 (46%
liquids)
|
96,000 to 100,000 (47%
liquids)
|
Second
half 2024 (Boe/d)
|
115,000 to 121,000 (47%
liquids)
|
104,000 to 112,000 (47%
liquids)
|
Capital
expenditures
|
$830 to $890
million
|
No change
|
Sustaining
and Maintenance
|
$415 to $445
million
|
Growth
|
$415 to $445
million
|
Abandonment and
reclamation expenditures
|
$40 million
|
Free cash flow
(1)
|
$350 million
|
$235 million
|
The Company's midpoint 2024 capital program, abandonment and
reclamation expenditures and regular monthly dividend is fully
funded under the above forecast. The Company's midpoint 2024
sustaining and maintenance capital program, abandonment and
reclamation expenditures and regular monthly dividend would remain
fully funded down to an average WTI price in 2024 of about
US$61/Bbl, assuming no changes to the
other forecast assumptions. See "Advisories – Pricing Sensitivity"
for additional sensitivities of 2024 free cash flow to changes in
commodity price assumptions.
__________
|
(1)
|
Free cash flow is a
capital management measure used by Paramount. Refer to
"Advisories - Specified Financial Measures" for more information on
this measure. The stated free cash flow forecast is based on the
following assumptions for 2024: (i) the midpoint of stated capital
expenditures and sales volumes, (ii) $40 million in abandonment and
reclamation costs, (iii) $10 million in geological and geophysical
expenses, (iv) realized pricing of $56.90/Boe (reflecting changes
to production mix); (v) a $US/$CAD exchange rate of $0.735, (vi)
royalties of $8.35/Boe, (vii) operating costs of $12.90/Boe and
(vii) transportation and NGLs processing costs of $3.85/Boe.
For comparative purposes, the previous 2024 free cash flow forecast
utilized the following differing assumptions as to the following
factors: (i) $7 million in geological and geophysical expenses,
(ii) realized pricing of $56.40/Boe, (iii) royalties of $8.80/Boe,
(iv) operating costs of $12.05/Boe and (v) transportation and NGLs
processing costs of $3.70/Boe.
|
MARCH DIVIDEND
Paramount's Board of Directors has declared a cash dividend of
$0.125 per class A common share that
will be payable on March 28, 2024 to
shareholders of record on March 15,
2024. The dividend will be designated as an "eligible
dividend" for Canadian income tax purposes.
ANNUAL GENERAL MEETING
Paramount will hold its annual general meeting of shareholders
on Thursday, May 2, 2024 at
10:30 am (Calgary time) in the Bankers Hall Auditorium
located at 315 - 8th Avenue S.W., Calgary, Alberta.
COMPLETE ANNUAL RESULTS
Paramount's: (i) complete annual results, including a review of
operations, the Company's audited consolidated financial statements
as at and for the year ended December 31,
2023 (the "Consolidated Financial Statements") and the
accompanying management's discussion and analysis (the "MD&A");
and (ii) 2023 annual information form, which contains additional
important information concerning the Company's reserves, properties
and operations, can be obtained on SEDAR+ at
www.sedarplus.ca or on Paramount's website at
www.paramountres.com/investors/financial-shareholder-reports.
A summary of historical financial and operating results is also
available on Paramount's website at
www.paramountres.com/investors/financial-shareholder-reports.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-rich
natural gas focused Canadian energy company that explores for and
develops both conventional and unconventional petroleum and natural
gas, including longer-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are
located in Alberta and British
Columbia. Paramount's Common Shares are listed on the Toronto
Stock Exchange under the symbol "POU".
FINANCIAL AND
OPERATING RESULTS (1)
|
|
|
|
|
|
|
|
|
|
|
($ millions, except
as noted)
|
Three months ended
December 31
|
Year ended December
31
|
|
2023
|
|
2022
|
2023
|
2022
|
Net
income
|
111.9
|
|
259.9
|
|
470.2
|
680.6
|
per
share – basic ($/share)
|
0.78
|
|
1.83
|
|
3.29
|
4.83
|
per
share – diluted ($/share)
|
0.75
|
|
1.76
|
|
3.17
|
4.63
|
Cash from operating
activities
|
287.0
|
|
306.9
|
|
938.2
|
1,049.6
|
per
share – basic ($/share)
|
1.99
|
|
2.17
|
|
6.56
|
7.45
|
per
share – diluted ($/share)
|
1.93
|
|
2.08
|
|
6.32
|
7.14
|
Adjusted funds
flow
|
284.1
|
|
340.7
|
|
965.3
|
1,171.0
|
per
share – basic ($/share)
|
1.97
|
|
2.40
|
|
6.75
|
8.32
|
per
share – diluted ($/share)
|
1.91
|
|
2.31
|
|
6.51
|
7.97
|
Free cash
flow
|
59.7
|
|
162.0
|
|
168.4
|
471.1
|
per
share – basic ($/share)
|
0.41
|
|
1.14
|
|
1.18
|
3.35
|
per
share – diluted ($/share)
|
0.40
|
|
1.10
|
|
1.13
|
3.20
|
Total
assets
|
|
|
|
|
4,388.7
|
4,337.3
|
Investments in
securities
|
|
|
|
|
540.9
|
557.1
|
Long-term
debt
|
|
|
|
|
–
|
159.4
|
Net (cash)
debt
|
|
|
|
|
59.6
|
161.2
|
Common shares
outstanding (millions) (2)
|
|
|
|
|
144.2
|
142.0
|
Sales volumes
(3)
|
|
|
|
|
|
Natural
gas (MMcf/d)
|
326.2
|
|
321.9
|
315.1
|
294.7
|
Condensate
and oil (Bbl/d)
|
40,290
|
|
37,580
|
37,657
|
33,908
|
Other NGLs
(Bbl/d)
|
6,698
|
|
6,143
|
6,226
|
5,650
|
Total (Boe/d)
|
101,348
|
|
97,370
|
96,393
|
88,672
|
% liquids
|
46 %
|
|
45 %
|
46 %
|
45 %
|
Grande
Prairie Region (Boe/d)
|
72,860
|
|
64,434
|
70,943
|
58,519
|
Kaybob
Region (Boe/d)
|
20,324
|
|
24,477
|
17,449
|
22,730
|
Central
Alberta & Other Region (Boe/d)
|
8,164
|
|
8,459
|
8,001
|
7,423
|
Total
(Boe/d)
|
101,348
|
|
97,370
|
96,393
|
88,672
|
Netback
|
|
$/Boe (4)
|
|
$/Boe
(4)
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
Natural
gas revenue
|
83.7
|
2.79
|
194.2
|
6.56
|
|
349.1
|
3.04
|
671.1
|
6.24
|
Condensate
and oil revenue
|
363.7
|
98.12
|
375.1
|
108.50
|
|
1,364.2
|
99.25
|
1,448.9
|
117.07
|
Other NGLs
revenue
|
22.2
|
36.00
|
27.3
|
48.25
|
|
81.9
|
36.06
|
114.2
|
55.37
|
Royalty
income and other revenue
|
0.9
|
–
|
1.1
|
–
|
|
3.3
|
–
|
18.2
|
–
|
Petroleum and
natural gas sales
|
470.5
|
50.46
|
597.7
|
66.72
|
|
1,798.5
|
51.12
|
2,252.4
|
69.60
|
Royalties
|
(68.9)
|
(7.39)
|
(84.4)
|
(9.43)
|
|
(254.3)
|
(7.23)
|
(335.3)
|
(10.36)
|
Operating
expense
|
(126.4)
|
(13.56)
|
(119.2)
|
(13.31)
|
|
(453.8)
|
(12.90)
|
(407.1)
|
(12.58)
|
Transportation and NGLs processing
|
(33.2)
|
(3.56)
|
(27.2)
|
(3.03)
|
|
(134.4)
|
(3.82)
|
(123.7)
|
(3.82)
|
Sales of
commodities purchased (5)
|
50.2
|
5.38
|
102.7
|
11.47
|
|
255.1
|
7.25
|
272.0
|
8.41
|
Commodities purchased (5)
|
(47.4)
|
(5.08)
|
(100.4)
|
(11.21)
|
|
(250.2)
|
(7.11)
|
(267.0)
|
(8.25)
|
Netback
|
244.8
|
26.25
|
369.2
|
41.21
|
|
960.9
|
27.31
|
1,391.3
|
43.00
|
Risk management contract settlements
|
43.0
|
4.61
|
(23.0)
|
(2.57)
|
|
46.7
|
1.33
|
(179.0)
|
(5.53)
|
Netback including
risk management contract settlements
|
287.8
|
30.86
|
346.2
|
38.64
|
|
1,007.6
|
28.64
|
1,212.3
|
37.47
|
Capital
expenditures
|
|
|
|
|
|
Grande
Prairie Region
|
75.8
|
|
135.8
|
380.3
|
453.3
|
Kaybob
Region
|
64.5
|
|
11.4
|
190.4
|
131.2
|
Central
Alberta and Other Region
|
61.7
|
|
1.0
|
120.0
|
2.1
|
Fox
Drilling and Cavalier Energy
|
3.9
|
|
12.1
|
29.2
|
27.7
|
Corporate
|
3.0
|
|
9.3
|
12.2
|
40.7
|
Total
|
208.9
|
|
169.6
|
732.1
|
655.0
|
Asset retirement
obligations settled
|
12.8
|
|
7.0
|
54.6
|
36.1
|
(1)
|
Adjusted funds flow,
free cash flow and net (cash) debt are capital management measures
used by Paramount. Netback and netback including risk
management contract settlements are non-GAAP financial measures.
Netback and Netback including risk management contract settlements
presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each
measure, other than net income, that is presented on a per share,
$/Mcf or $/Boe basis is a supplementary financial measure.
Refer to "Specified Financial Measures".
|
(2)
|
Common shares are
presented net of shares held in trust under the Company's
restricted share unit plan: 2023: 0.4 million, 2022: 0.8
million.
|
(3)
|
Refer to the Product
Type Information section of this document for a complete breakdown
of sales volumes for applicable periods by specific product
type.
|
(4)
|
Natural gas revenue
presented as $/Mcf.
|
(5)
|
Sales of commodities
purchased and commodities purchased are treated as corporate items
and not allocated to individual regions or properties.
|
PRODUCT TYPE INFORMATION
This press release includes references to sales volumes of
"natural gas", "condensate and oil", "NGLs", "Other NGLs" and
"liquids". "Natural gas" refers to shale gas and conventional
natural gas combined. "Condensate and oil" refers to
condensate, light and medium crude oil, tight oil and heavy crude
oil combined. "NGLs" refers to condensate and Other NGLs
combined. "Other NGLs" refers to ethane, propane and
butane. "Liquids" refers to condensate and oil and
Other NGLs combined. Below is a complete breakdown of sales
volumes for applicable periods by the specific product types of
shale gas, conventional natural gas, NGLs, light and medium crude
oil, tight oil and heavy crude oil. Numbers may not add due
to rounding.
|
Annual
|
|
Total
|
Grande
Prairie
Region
|
Kaybob
Region
|
Central Alberta
and
Other Region
|
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
Shale gas
(MMcf/d)
|
265.2
|
232.9
|
209.3
|
166.9
|
28.2
|
38.5
|
27.7
|
27.5
|
Conventional natural
gas (MMcf/d)
|
49.9
|
61.8
|
0.4
|
1.3
|
44.6
|
55.0
|
4.9
|
5.5
|
Natural gas
(MMcf/d)
|
315.1
|
294.7
|
209.7
|
168.2
|
72.8
|
93.5
|
32.6
|
33.0
|
Condensate
(Bbl/d)
|
35,148
|
31,228
|
31,433
|
27,095
|
2,655
|
3,192
|
1,060
|
941
|
Other NGLs
(Bbl/d)
|
6,226
|
5,650
|
4,414
|
3,394
|
1,070
|
1,620
|
742
|
636
|
NGLs
(Bbl/d)
|
41,374
|
36,878
|
35,847
|
30,489
|
3,725
|
4,812
|
1,802
|
1,577
|
Light and medium crude
oil (Bbl/d)
|
1,469
|
2,200
|
–
|
4
|
1,440
|
2,066
|
29
|
130
|
Tight oil
(Bbl/d)
|
616
|
480
|
152
|
–
|
158
|
261
|
306
|
219
|
Heavy crude oil
(Bbl/d)
|
424
|
–
|
–
|
–
|
–
|
–
|
424
|
–
|
Crude oil
(Bbl/d)
|
2,509
|
2,680
|
152
|
4
|
1,598
|
2,327
|
759
|
349
|
Total
(Boe/d)
|
96,393
|
88,672
|
70,943
|
58,519
|
17,449
|
22,730
|
8,001
|
7,423
|
|
Q4
|
|
Total
|
Grande
Prairie
Region
|
Kaybob
Region
|
Central Alberta
and
Other Region
|
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
2023
|
2022
|
Shale gas
(MMcf/d)
|
271.8
|
260.0
|
214.1
|
188.4
|
30.2
|
41.9
|
27.5
|
29.7
|
Conventional natural
gas (MMcf/d)
|
54.4
|
61.9
|
0.3
|
1.5
|
49.6
|
55.0
|
4.5
|
5.4
|
Natural gas
(MMcf/d)
|
326.2
|
321.9
|
214.4
|
189.9
|
79.8
|
96.9
|
32.0
|
35.1
|
Condensate
(Bbl/d)
|
37,522
|
34,616
|
32,155
|
29,146
|
4,003
|
4,354
|
1,364
|
1,116
|
Other NGLs
(Bbl/d)
|
6,698
|
6,143
|
4,742
|
3,631
|
1,209
|
1,671
|
747
|
841
|
NGLs
(Bbl/d)
|
44,220
|
40,759
|
36,897
|
32,777
|
5,212
|
6,025
|
2,111
|
1,957
|
Light and medium crude
oil (Bbl/d)
|
1,636
|
2,335
|
–
|
–
|
1,602
|
2,045
|
34
|
290
|
Tight oil
(Bbl/d)
|
699
|
629
|
227
|
–
|
205
|
262
|
267
|
367
|
Heavy crude oil
(Bbl/d)
|
433
|
–
|
–
|
–
|
–
|
–
|
433
|
–
|
Crude oil
(Bbl/d)
|
2,768
|
2,964
|
227
|
–
|
1,807
|
2,307
|
734
|
657
|
Total
(Boe/d)
|
101,348
|
97,370
|
72,860
|
64,434
|
20,324
|
24,477
|
8,164
|
8,459
|
The Company forecasts that 2024 annual sales volumes will
average between 100,000 Boe/d and 106,000 Boe/d (53% shale gas and
conventional natural gas combined, 41% condensate, light and medium
crude oil, tight oil and heavy crude oil combined and 6% Other
NGLs). First half 2024 sales volumes are expected to average
between 96,000 Boe/d and 100,000 Boe/d (53% shale gas and
conventional natural gas combined, 41% condensate, light and medium
crude oil, tight oil and heavy crude oil combined and 6% Other
NGLs). Second half 2024 sales volumes are expected to average
between 104,000 Boe/d and 112,000 Boe/d (53% shale gas and
conventional natural gas combined, 41% condensate, light and medium
crude oil, tight oil and heavy crude oil combined and 6% Other
NGLs).
SPECIFIED FINANCIAL MEASURES
Non-GAAP Financial Measures
Netback and netback including risk management contract
settlements are non-GAAP financial measures. These measures
are not standardized measures under IFRS and might not be
comparable to similar financial measures presented by other
issuers. These measures should not be considered in isolation
or construed as alternatives to their most directly comparable
measure disclosed in the Company's primary financial statements or
other measures of financial performance calculated in accordance
with IFRS.
Netback equals petroleum and natural gas sales (the most
directly comparable measure disclosed in the Company's primary
financial statements) plus sales of commodities purchased less
royalties, operating expense, transportation and NGLs processing
expense and commodities purchased. Sales of commodities
purchased and commodities purchased are treated as corporate items
and are not allocated to individual regions or properties.
Netback is used by investors and management to compare the
performance of the Company's producing assets between periods.
Netback including risk management contract settlements equals
netback after including (or deducting) risk management contract
settlements received (paid). Netback including risk management
contract settlements is used by investors and management to assess
the performance of the producing assets after incorporating
management's risk management strategies.
Refer to the table under the heading "Financial and Operating
Results" in this press release for the calculation of netback and
netback including risk management contract settlements for the
three months and years ended December 31,
2023 and 2022.
F&D capital is a measure used in determining F&D costs
and is comprised of capital expenditures (the most directly
comparable measure disclosed in the Company's primary financial
statements) for the applicable year, excluding certain expenditures
described herein, plus the change from the prior year in estimated
future development capital included in the applicable reserves
evaluation prepared by McDaniel. Capital expenditures related to
Fox Drilling and corporate capital expenditures are excluded in all
periods where F&D capital has been calculated. Capital
expenditures related to Cavalier Energy are excluded in all periods
were F&D capital has been calculated prior to 2023 as no
reserves were attributed to the properties of Cavalier Energy prior
to 2023. F&D capital is used by management and investors,
in calculating F&D costs, to represent the amount of capital
invested in oil and gas exploration and development projects to
generate reserves additions.
Set out below is the calculation of F&D capital for the
years ended December 31, 2023, 2022
and 2021. Columns may not add due to rounding.
($
millions)
|
Total
Company
|
Proved Developed
Producing
|
2023
|
2022
|
2021
|
3-year Total
|
Capital
expenditures
|
732
|
655
|
275
|
1,662
|
Fox Drilling, Cavalier
Energy (2022 and 2021) and corporate
|
(34)
|
(69)
|
(6)
|
(109)
|
Change in estimated
future development capital
|
94
|
(10)
|
(11)
|
73
|
F&D Capital –
PDP
|
792
|
577
|
257
|
1,626
|
|
|
|
|
|
Total
Proved
|
2023
|
2022
|
2021
|
3-year Total
|
Capital
expenditures
|
732
|
655
|
275
|
1,662
|
Fox Drilling, Cavalier
Energy (2022 and 2021) and corporate
|
(34)
|
(69)
|
(6)
|
(109)
|
Change in estimated
future development capital
|
1
|
1,249
|
221
|
1,471
|
F&D Capital –
TP
|
700
|
1,835
|
490
|
3,025
|
|
|
|
|
|
Proved Plus
Probable
|
2023
|
2022
|
2021
|
3-year Total
|
Capital
expenditures
|
732
|
655
|
275
|
1,662
|
Fox Drilling, Cavalier
Energy (2022 and 2021) and corporate
|
(34)
|
(69)
|
(6)
|
(109)
|
Change in estimated
future development capital
|
516
|
1,176
|
(93)
|
1,599
|
F&D Capital –
P+P
|
1,214
|
1,762
|
176
|
3,152
|
Non-GAAP Ratios
F&D costs, recycle ratio, netback and netback including risk
management contract settlements presented on a $/Boe basis are
non-GAAP ratios as they each have a non-GAAP financial measure as a
component. These measures are not standardized measures under
IFRS and might not be comparable to similar financial measures
presented by other issuers. These measures should not be
considered in isolation or construed as alternatives to their most
directly comparable measure disclosed in the Company's primary
financial statements or other measures of financial performance
calculated in accordance with IFRS.
F&D costs are calculated by dividing: (i) F&D capital (a
non-GAAP financial measure) for the applicable reserves category
and period; by (ii) the net changes to reserves in such reserves
category from the prior period from extensions/improved recovery,
technical revisions and economic factors, expressed in Boe.
F&D costs are a measure commonly used by management and
investors to assess the relationship between capital invested in
oil and gas exploration and development projects and reserve
additions. Readers should refer to the information under the
heading "Reserves and Other Oil and Gas Information – Reserves
Information – Reserves Reconciliation" in the Company's annual
information forms for the years ended December 31, 2023, 2022 and 2021, which are
available on SEDAR+ at www.sedarplus.ca or on the Company's website
at www.paramountres.com, for a description of the net changes to
reserves from the prior year. See "Advisories – Oil and Gas
Definitions and Measures" below for more information about this
measure.
Recycle ratio is calculated by dividing the netback (a non-GAAP
financial measure) per Boe for the period by the F&D costs for
the period. Recycle ratio is used by investors and management
to compare the cost of adding reserves to the netback realized from
production. See "Advisories – Oil and Gas Definitions and
Measures" for more information about this measure.
Set out below are the applicable F&D costs and recycle
ratios for 2023, 2022 and 2021.
|
F&D
($/Boe)
|
Recycle Ratio
*
|
|
2023
|
2022
|
2021
|
2023
|
2022
|
2021
|
Proved Developed
Producing
|
$16.58
|
$9.58
|
$6.22
|
1.6x
|
4.5x
|
4.3x
|
Total
Proved
|
$16.96
|
$14.11
|
$6.72
|
1.6x
|
3.0x
|
4.0x
|
Proved plus
Probable
|
$12.52
|
$14.87
|
$2.12
|
2.2x
|
2.9x
|
12.6x
|
Netback on a $/Boe basis is calculated by dividing netback (a
non-GAAP financial measure) for the applicable period by the total
sales volumes during the period in Boe. Netback including
risk management contract settlements on a $/Boe basis is calculated
by dividing netback including risk management contract settlements
(a non-GAAP financial measure) for the applicable period by the
total sales volumes during the period in Boe. These measures
are used by investors and management to assess netback and netback
including risk management contract settlements on a unit of sales
volumes basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net (cash) debt are
capital management measures that Paramount utilizes in managing its
capital structure. These measures are not standardized measures and
therefore may not be comparable with the calculation of similar
measures by other entities. Refer to Note 18 – Capital
Structure in the Consolidated Financial Statements of Paramount
for: (i) a description of the composition and use of these
measures, (ii) reconciliations of adjusted funds flow and free cash
flow to cash from operating activities, the most directly
comparable measure disclosed in the Company's primary financial
statements, for the years ended December 31,
2023 and 2022 and (iii) a calculation of net (cash) debt as
at December 31, 2023 and 2022.
The following is a reconciliation of adjusted funds flow to cash
from operating activities, the most directly comparable measure
disclosed in the Company's primary financial statements, for the
three months ended December 31, 2023
and 2022:
Three months ended
December 31 ($millions)
|
2023
|
2022
|
Cash from operating
activities
|
287.0
|
306.9
|
Change in non-cash
working capital
|
(18.4)
|
48.7
|
Geological and
geophysical expense
|
2.7
|
2.1
|
Asset retirement
obligations settled
|
12.8
|
7.0
|
Closure
costs
|
–
|
–
|
Provisions
|
–
|
(24.0)
|
Settlements
|
–
|
–
|
Transaction and
reorganization costs
|
–
|
–
|
Adjusted funds
flow
|
284.1
|
340.7
|
The following is a reconciliation of free cash flow to cash from
operating activities, the most directly comparable measure
disclosed in the Company's primary financial statements, for the
three months ended December 31, 2023
and 2022:
Three months ended
December 31 ($ millions)
|
2023
|
2022
|
Cash from operating
activities
|
287.0
|
306.9
|
Change in non-cash
working capital
|
(18.4)
|
48.7
|
Geological and
geophysical expense
|
2.7
|
2.1
|
Asset retirement
obligations settled
|
12.8
|
7.0
|
Closure
costs
|
–
|
–
|
Provisions
|
–
|
(24.0)
|
Settlements
|
–
|
–
|
Transaction and
reorganization costs
|
–
|
–
|
Adjusted funds
flow
|
284.1
|
340.7
|
Capital
expenditures
|
(208.9)
|
(169.6)
|
Geological and
geophysical expense
|
(2.7)
|
(2.1)
|
Asset retirement
obligation settled
|
(12.8)
|
(7.0)
|
Free cash
flow
|
59.7
|
162.0
|
Supplementary Financial Measures
This press release contains supplementary financial measures
expressed as: (i) cash from operating activities, adjusted funds
flow and free cash flow on a per share – basic and per share –
diluted basis and (ii) petroleum and natural gas sales, revenue,
royalties, operating expenses, transportation and NGLs processing
expenses, sales of commodities purchased and commodities purchased
on a $/Boe or $/Mcf basis.
Cash from operating activities, adjusted funds flow and free
cash flow on a per share – basic basis are calculated by dividing
cash from operating activities, adjusted funds flow or free cash
flow, as applicable, over the referenced period by the weighted
average basic shares outstanding during the period determined
under IFRS. Cash from operating activities, adjusted
funds flow and free cash flow on a per share – diluted basis are
calculated by dividing cash from operating activities, adjusted
funds flow or free cash flow, as applicable, over the referenced
period by the weighted average diluted shares outstanding during
the period determined under IFRS.
Petroleum and natural gas sales, revenue, royalties, operating
expenses, transportation and NGLs processing expenses, sales of
commodities purchased and commodities purchased on a $/Boe or $/Mcf
basis are calculated by dividing petroleum and natural gas sales,
revenue, royalties, operating expenses, transportation and NGLs
processing expenses, sales of commodities purchased and commodities
purchased, as applicable, over the referenced period by the
aggregate units (Boe or Mcf) of sales volumes during such
period.
ADVISORIES
Forward-looking Information
Certain statements in this press release constitute
forward-looking information under applicable securities
legislation. Forward-looking information typically contains
statements with words such as "anticipate", "believe", "estimate",
"will", "expect", "plan", "schedule", "intend", "propose", or
similar words suggesting future outcomes or an outlook.
Forward-looking information in this press release includes, but is
not limited to:
- forecast sales volumes for 2024 and certain periods
therein;
- planned capital expenditures in 2024 and the allocation thereof
between sustaining and maintenance capital and growth capital;
- planned abandonment and reclamation expenditures in 2024;
- forecast free cash flow in 2024;
- the expected construction of a new natural gas processing
facility at Willesden Green and the anticipated timing of start-up
and estimated capacity upon completion; and
- the potential payment of future dividends.
Statements relating to reserves are also deemed to be forward
looking information, 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.
Such forward-looking information is based on a number of
assumptions which may prove to be incorrect. Assumptions have been
made with respect to the following matters, in addition to any
other assumptions identified in this press release:
- future commodity prices;
- the impact of international conflicts, including in
Ukraine and the Middle East;
- royalty rates, taxes and capital, operating, general &
administrative and other costs;
- foreign currency exchange rates, interest rates and the rate
and impacts of inflation;
- general business, economic and market conditions;
- the performance of wells and facilities;
- the availability to Paramount of the funds required for
exploration, development and other operations and the meeting of
commitments and financial obligations;
- the ability of Paramount to obtain equipment, materials,
services and personnel in a timely manner and at expected and
acceptable costs to carry out its activities;
- the ability of Paramount to secure adequate processing,
transportation, fractionation, disposal and storage capacity on
acceptable terms and the capacity and reliability of
facilities;
- the ability of Paramount to obtain the volumes of water
required for completion activities;
- the ability of Paramount to market its production
successfully;
- the ability of Paramount and its industry partners to obtain
drilling success (including in respect of anticipated sales
volumes, reserves additions, product yields and product recoveries)
and operational improvements, efficiencies and results consistent
with expectations;
- the timely receipt of required governmental and regulatory
approvals;
- the application of regulatory requirements respecting
abandonment and reclamation; and
- anticipated timelines and budgets being met in respect of: (i)
drilling programs and other operations, including well completions
and tie-ins, (ii) the construction, commissioning and start-up of
new and expanded third-party and Company facilities, including the
new natural gas processing facility at Willesden Green, and (iii)
facility turnarounds and maintenance.
Although Paramount believes that the expectations reflected in
such forward-looking information are reasonable based on the
information available at the time of this press release, undue
reliance should not be placed on the forward-looking information as
Paramount can give no assurance that such expectations will prove
to be correct. Forward-looking information is based on
expectations, estimates and projections that involve a number of
risks and uncertainties which could cause actual results to differ
materially from those anticipated by Paramount and described in the
forward-looking information. The material risks and
uncertainties include, but are not limited to:
- fluctuations in commodity prices;
- changes in capital spending plans and planned exploration and
development activities;
- changes in foreign currency exchange rates, interest rates and
the rate of inflation;
- the uncertainty of estimates and projections relating to future
production, product yields (including condensate to natural gas
ratios), revenue, free cash flow, reserves additions, product
recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate processing, transportation,
fractionation, disposal and storage capacity on acceptable
terms;
- operational risks in exploring for, developing, producing and
transporting natural gas and liquids, including the risk of spills,
leaks or blowouts;
- the ability to obtain equipment, materials, services and
personnel in a timely manner and at expected and acceptable costs,
including the potential effects of inflation and supply chain
disruptions;
- potential disruptions, delays or unexpected technical or other
difficulties in designing, developing, expanding or operating new,
expanded or existing facilities, including third-party facilities
and the new natural gas processing facility at Willesden
Green;
- processing, transportation, fractionation, disposal and storage
outages, disruptions and constraints;
- potential limitations on access to the volumes of water
required for completion activities due to drought, conditions of
low river flow, government restrictions or other factors;
- risks and uncertainties involving the geology of oil and gas
deposits;
- the uncertainty of reserves estimates;
- general business, economic and market conditions;
- the ability to generate sufficient cash from operating
activities to fund, or to otherwise finance, planned exploration,
development and operational activities and meet current and future
commitments and obligations (including asset retirement
obligations, processing, transportation, fractionation and similar
commitments and obligations);
- changes in, or in the interpretation of, laws, regulations or
policies (including environmental laws);
- the ability to obtain required governmental or regulatory
approvals in a timely manner, and to obtain and maintain leases and
licenses, including those required for the new natural gas
processing facility at Willesden Green;
- the effects of weather and other factors including wildlife and
environmental restrictions which affect field operations and
access;
- uncertainties as to the timing and cost of future abandonment
and reclamation obligations and potential liabilities for
environmental damage and contamination;
- uncertainties regarding Indigenous claims and in maintaining
relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, regulatory
actions, audits and assessments; and
- other risks and uncertainties described elsewhere in this
document and in Paramount's other filings with Canadian securities
authorities.
There are risks that may result in the Company changing,
suspending or discontinuing its monthly dividend program, including
changes to its free cash flow, operating results, capital
requirements, financial position, market conditions or corporate
strategy and the need to comply with requirements under debt
agreements and applicable laws respecting the declaration and
payment of dividends. There are no assurances as to the
continuing declaration and payment of future dividends or the
amount or timing of any such dividends.
The foregoing list of risks is not exhaustive. For more
information relating to risks, see the section titled "Risk
Factors" in Paramount's annual information form for the year
ended December 31, 2023, which is
available on SEDAR+ at www.sedarplus.ca or on the Company's website
at www.paramountres.com. The forward-looking information
contained in this press release is made as of the date hereof and,
except as required by applicable securities law, Paramount
undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of
new information, future events or otherwise.
Certain forward-looking information in this press release,
including forecast free cash flow in 2024, may also constitute a
"financial outlook" within the meaning of applicable securities
laws. A financial outlook involves statements about Paramount's
prospective financial performance or position and is based on and
subject to the assumptions and risk factors described above in
respect of forward-looking information generally as well as any
other specific assumptions and risk factors in relation to such
financial outlook noted in this press release. Such assumptions are
based on management's assessment of the relevant information
currently available and any financial outlook included in this
press release is provided for the purpose of helping readers
understand Paramount's current expectations and plans for the
future. Readers are cautioned that reliance on any financial
outlook may not be appropriate for other purposes or in other
circumstances and that the risk factors described above or other
factors may cause actual results to differ materially from any
financial outlook.
Reserves Data
Reserves data set forth in this press release is based upon an
evaluation of the Company's reserves prepared by McDaniel &
Associates Consultants Ltd. ("McDaniel") dated March 5, 2024 and effective December 31, 2023 (the "McDaniel Report").
The reserves referenced in this press release are gross reserves.
The price forecast used in the McDaniel Report is an average of the
January 1, 2024 price forecasts for
McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2023 price forecast of Sproule
Associates Ltd. The estimates of reserves contained in the
McDaniel Report and referenced in this press release are estimates
only and there is no guarantee that the estimated reserves will be
recovered. Actual reserves may be greater than or less than
the estimates contained in the McDaniel Report and referenced in
this press release. There is no assurance that the forecast
prices and costs assumptions used in the McDaniel Report will be
attained, and variances could be material. Estimated future
net revenue does not represent fair market value. The
estimates of reserves for individual properties may not reflect the
same confidence level as estimates of reserves for all properties
due to the effects of aggregation. Readers should refer to
the Company's annual information form for the year ended
December 31, 2023, which is available
on SEDAR+ at www.sedarplus.ca or on Paramount's website at
www.paramountres.com, for a complete description of the McDaniel
Report (including reserves by the specific product types of shale
gas, conventional natural gas, NGLs, light and medium crude oil,
tight oil and heavy crude oil) and the material assumptions,
limitations and risk factors pertaining thereto.
Oil and Gas Measures and Definitions
Liquids
|
|
Natural
Gas
|
Bbl
|
Barrels
|
|
GJ
|
Gigajoules
|
Bbl/d
|
Barrels per
day
|
|
GJ/d
|
Gigajoules per
day
|
MBbl
|
Thousands of
barrels
|
|
MMBtu
|
Millions of British
Thermal Units
|
NGLs
|
Natural gas
liquids
|
|
MMBtu/d
|
Millions of British
Thermal Units per day
|
Condensate
|
Pentane and heavier
hydrocarbons
|
Mcf
|
Thousands of cubic
feet
|
WTI
|
West Texas
Intermediate
|
|
MMcf
|
Millions of cubic
feet
|
|
|
|
MMcf/d
|
Millions of cubic feet
per day
|
Oil
Equivalent
|
|
AECO
|
AECO-C reference
price
|
Boe
|
Barrels of oil
equivalent
|
|
|
|
MBoe
|
Thousands of barrels of
oil equivalent
|
|
|
|
MMBoe
|
Millions of barrels of
oil equivalent
|
|
Boe/d
|
Barrels of oil
equivalent per day
|
|
|
|
|
|
|
|
|
|
This press release contains disclosures expressed as "Boe",
"$/Boe" and "Boe/d". Natural gas equivalency volumes have
been derived using the ratio of six thousand cubic feet of natural
gas to one barrel of oil when converting natural gas to Boe.
Equivalency measures may be misleading, particularly if used in
isolation. A conversion ratio of six thousand cubic feet of natural
gas to one barrel of oil is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the well head. For the year
ended December 31, 2023, the value
ratio between crude oil and natural gas was approximately 36:1.
This value ratio is significantly different from the energy
equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as
an indication of value.
This press release contains metrics commonly used in the oil and
natural gas industry. These metrics are "CGR", F&D costs,
recycle ratio and reserves replacement ratio. Each of these
metrics is determined by the Company as set out below or elsewhere
in this press release. These metrics do not have standardized
meanings and may not be comparable to similar measures presented by
other companies. As such, they should not be used to make
comparisons. Management uses these oil and gas metrics for its own
performance measurements and to provide shareholders with measures
to compare the Company's performance over time; however, such
measures are not reliable indicators of the Company's future
performance and future performance may not compare to the
performance in previous periods and therefore should not be unduly
relied upon.
"CGR" means condensate to gas ratio and is
calculated by dividing wellhead raw liquids volumes by
wellhead raw natural gas volumes.
Refer to the "Specified Financial Measures" section of this
press release for a description of the calculation and use of
F&D costs and recycle ratio.
Reserves replacement ratio is calculated by dividing: (i) the
net changes in reserves from the prior year in the applicable
category from technical revisions, economic factors and
extensions/improved recovery, by (ii) the aggregate production
during the year. Reserves replacement ratio is a measure
commonly used by management and investors to assess the rate at
which reserves depleted by production are being replaced.
Additional information respecting the Company's oil and gas
properties and operations is provided in the Company's annual
information form for the year ended December
31, 2023 which is available on SEDAR+ at www.sedarplus.ca or
on Paramount's website at www.paramountres.com.
Pricing Sensitivity
The below table reflects forecast 2024 free cash flow under the
revised 2024 guidance and, for illustrative comparison, two
alternative pricing scenarios:
|
Revised 2024
Guidance
|
Alternative Scenario
1
|
Alternative Scenario
2
|
WTI
|
US$80.00/Bbl
|
US$77.50/Bbl
|
US$75.00/Bbl
|
NYMEX
|
US$3.50/MMBtu
|
US$3.00/MMBtu
|
US$2.40/MMBtu
|
AECO
|
$2.84/GJ
|
$2.37/GJ
|
$1.90/GJ
|
2024 Free Cash
Flow
|
$235 million
|
$135 million
|
$25 million
|
Forecast 2024 free cash flow is forward-looking
information. See
"Forward-looking Information" in these Advisories.
SOURCE Paramount Resources Ltd.