CALGARY,
AB, May 4, 2022 /CNW/ - Paramount
Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased
to announce strong first quarter 2022 financial and operating
results, the acceleration of development activities at Karr
supporting increased production in 2023 and beyond and a
highly complementary $40 million
Duvernay acquisition in its
Willesden Green core area. Paramount is also pleased to
announce that it is increasing its regular monthly dividend from
$0.08 per class A common share
("Common Share") to $0.10 per Common
Share beginning May 2022.
HIGHLIGHTS
- First quarter 2022 sales volumes averaged 82,137 Boe/d (45%
liquids), in-line with expectations.(1)
-
- Sales volumes at Karr averaged 38,611 Boe/d (51% liquids).
- Sales volumes at Wapiti averaged 16,126 Boe/d (59%
liquids).
- Cash from operating activities was $175
million ($1.25 per basic
share) in the first quarter. Adjusted funds flow was $238 million ($1.70
per basic share). Free cash flow was $103
million ($0.74 per basic
share).(2)
- First quarter capital expenditures totaled $117 million and were predominantly focused on
drilling and completion activities at Karr and Wapiti as well as in
the Kaybob region.
- Paramount realized cash proceeds of approximately $51 million from the sale of a portion of its
investments in securities in the first quarter.
- Net debt was reduced by approximately $96 million quarter-over-quarter to $361 million at March 31,
2022, including drawings under the Company's credit facility
of $305 million. Net debt does not
account for the $479 million carrying
value of the Company's investments in securities as at March 31, 2022. (3)
- Paramount now expects to achieve its net debt target of about
$300 million by mid-year, earlier
than previously forecast, even after accounting for the
$40 million Willesden Green
acquisition.
- Abandonment and reclamation expenditures in the first quarter
totaled $15 million, net of
$5 million in funding under the
Alberta Site Rehabilitation Program ("ASRP"). A total of 63 wells
were abandoned in the quarter, including 36 under the Company's
ongoing area-based closure program at Zama.
- In late April, the Company acquired Duvernay lands and production directly
offsetting its existing 61,000 net acre position in the Willesden
Green area of Alberta for
approximately $40 million in cash
prior to adjustments. The acquisition is accretive on all key
metrics and more than doubles Paramount's land position and
internally estimated drilling locations in the area, setting the
stage for more efficient future development and potential
infrastructure synergies. Current production from the acquisition
is approximately 1,300 Boe/d (49% liquids).
- In May, Paramount increased the capacity of its bank credit
facility to $1.0 billion and extended
the maturity date to May 3, 2026. The
capacity of the credit facility can be further increased by up to
$250 million pursuant to an accordion
feature, subject to incremental lender commitments.
_______________________________________________
|
(1)
|
In this press release,
"liquids" refers to NGLs (including condensate) and oil combined,
"natural gas" refers to conventional natural gas and shale gas
combined, "condensate and oil" refers to condensate, light and
medium crude oil and tight 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 and tight 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. 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.
|
(3)
|
Net debt is a capital
management measure used by Paramount. Refer to the "Specified
Financial Measures" section for more information on this
measure.
|
INCREASED DIVIDEND
Paramount's Board of Directors has approved a 25% increase in
the Company's regular monthly dividend from $0.08 to $0.10 per
Common Share. The first increased dividend will be payable on
May 31, 2022 to shareholders of
record on May 16, 2022. The
dividend will be designated as an "eligible dividend" for Canadian
income tax purposes.
UPDATED 2022 GUIDANCE AND PRELIMINARY 2023 BUDGET
The Company's planned 2022 capital expenditures have been
upwardly revised by $20 million to a
range of between $520 million and
$560 million. The additional
capital expenditures will be used to accelerate the drilling of a
five-well pad at Karr from 2023 into late 2022 to facilitate
further production growth in 2023. Paramount remains
committed to prudently managing its capital resources and has the
flexibility to adjust its capital expenditure plans depending on
commodity prices and other factors. The Company continues to
budget $33 million of abandonment and
reclamation expenditures in 2022, net of approximately $8 million in funding under the ASRP.
Paramount is reaffirming its 2022 annual average sales volume
guidance of between 91,000 Boe/d and 95,000 Boe/d (46%
liquids).
- First half 2022 sales volumes are expected to average between
81,000 Boe/d and 85,000 Boe/d (44% liquids).
- Second half 2022 sales volumes are expected to average between
101,000 Boe/d and 105,000 Boe/d (47% liquids).
The Company is increasing its forecast of 2022 free cash flow
from approximately $590 million to
approximately $710 million to reflect
higher commodity price assumptions and its updated capital
expenditure plan.(1)
________________________
|
(1)
|
The stated free cash
flow forecast is based on the following assumptions for 2022: (i)
the midpoint of forecast capital spending and production, (ii) $33
million in net abandonment and reclamation costs, (iii) $7 million
in geological and geophysical expenses, (iv) realized pricing of
$72.55/Boe (US$97.07/Bbl WTI, US$6.34/MMBtu NYMEX, $5.34/GJ AECO),
(v) a $US/$CDN exchange rate of $0.793, (vi) royalties of
$12.40/Boe, (vii) operating costs of $11.30/Boe and (viii)
transportation and processing costs of $4.10/Boe.
|
|
|
The Company's 2022 capital program, targeted net debt reduction
and regular monthly dividend would remain fully funded down to an
average WTI price of about US$50.00/Bbl over the last three quarters of
2022. (1)
Paramount's anticipated 2023 capital expenditure budget, based
on preliminary planning and current market conditions, has been
upwardly revised by $60 million at
the midpoint to a range of between $540
million and $580
million. The additional capital expenditures will
largely be focused on accelerating development activities at Karr
to grow production by approximately 4,000 Boe/d in 2023 to a range
of 45,000 Boe/d to 49,000 Boe/d and set the stage for a new
production plateau range of 50,000 Boe/d to 54,000 Boe/d in
2024.
The Company expects that a capital program in this range will
result in 2023 average sales volumes of 105,000 Boe/d to 110,000
Boe/d (47% liquids), 6,500 Boe/d higher than previous estimates and
a 15% increase at midpoint from forecast average 2022 sales
volumes.
Paramount is updating its estimate of 2023 free cash flow that
would be expected from such a capital program from approximately
$580 million to approximately
$820 million to reflect higher
production and commodity price assumptions.(2)
UPDATED FIVE-YEAR OUTLOOK
The Company is updating its previously provided five-year
outlook to reflect revised capital and production expectations and
recent commodity prices. Paramount now anticipates cumulative
free cash flow through to the end of 2026 of approximately
$4.1 billion, up from $3.3 billion. The Company now anticipates
annual capital expenditures of approximately $550 million (up from $500
million) and a compound annual production growth rate of
approximately 7% (up from 5%) through the period.(3)
DELIVERING ON FREE CASH FLOW PRIORITIES
Paramount's free cash flow priorities are: (i) the achievement
of its net debt target of about $300
million and the maintenance of conservative leverage levels
thereafter, (ii) shareholder returns and (iii) incremental
growth. Paramount has and will continue to deliver on these
priorities.
- The Company expects to achieve its net debt target of about
$300 million by mid-year 2022. At
this level, year-end 2022 net debt to adjusted funds flow would be
less than 0.3x.(4)
- Paramount has increased shareholder returns by implementing a
regular monthly dividend in July 2021
of $0.02 per share and increasing it
three times to $0.10 per share
beginning in May 2022. The Company
retains the flexibility to make repurchases of shares under its
normal course issuer bid.
- The Company has allocated incremental capital to its highest
risk-adjusted rate of return organic growth opportunities and to
accretive acquisitions, adding to the significant free cash flow
and production growth described in the five-year outlook.
_________________________
|
(1)
|
Assuming no changes to
the other free cash flow forecast assumptions for
2022.
|
(2)
|
The revised free cash
flow estimate is based on the following assumptions for 2023: (i)
the midpoint of stated capital spending and production, (ii) $40
million in abandonment and reclamation costs, (iii) $7 million in
geological and geophysical expenses, (iv) realized pricing of
$63.80/Boe (US$87.88/Bbl WTI, US$5.04/MMBtu NYMEX, $4.48/GJ AECO),
(v) a $US/$CDN exchange rate of $0.794, (vi) royalties of
$12.05/Boe, (vii) operating costs of $10.60/Boe and (vii)
transportation and processing costs of $3.80/Boe.
|
(3)
|
The five-year outlook
is based on preliminary planning and current market conditions and
is subject to change. The stated anticipated cumulative free
cash flow is based on the following assumptions: (i) the stated
annual capital expenditures and compound annual production growth;
(ii) approximately $40 million in average annual abandonment and
reclamation costs, (iii) approximately $7 million in annual
geological and geophysical expenses, (iv) strip commodity prices
and foreign exchange rates as at April 21, 2022, and (v) internal
management estimates of future royalties, operating costs,
transportation and processing costs and, in 2026, cash
taxes.
|
(4)
|
Assuming 2022 adjusted
funds flow in excess of $1 billion.
|
|
|
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Grande Prairie Region sales volumes and netbacks are summarized
below:
|
Q1
2022
|
Q4 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas (MMcf/d)
|
152.5
|
158.9
|
(4)
|
Condensate and oil
(Bbl/d)
|
26,048
|
26,278
|
(1)
|
Other NGLs (Bbl/d)
|
3,267
|
3,276
|
-
|
Total (Boe/d)
|
54,737
|
56,035
|
(2)
|
% liquids
|
54%
|
53%
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
Change in $
millions (%)
|
Natural gas revenue
(2)
|
72.1
|
5.25
|
71.5
|
4.89
|
1
|
Condensate and oil
revenue
|
277.1
|
118.21
|
230.5
|
95.37
|
20
|
Other NGLs revenue
|
18.1
|
61.47
|
16.6
|
54.97
|
9
|
Royalty and other revenue
(3)
|
10.7
|
-
|
-
|
-
|
NM
|
Petroleum and natural gas sales
|
378.0
|
76.74
|
318.6
|
61.81
|
19
|
Royalties
|
(61.4)
|
(12.46)
|
(39.8)
|
(7.74)
|
54
|
Operating expense
|
(53.7)
|
(10.89)
|
(54.9)
|
(10.64)
|
(2)
|
Transportation and NGLs processing
|
(23.2)
|
(4.73)
|
(19.0)
|
(3.68)
|
22
|
|
239.7
|
48.66
|
204.9
|
39.75
|
17
|
(1)
|
"Netback" is a Non-GAAP
financial measure. When presented on a $/Boe or $/Mcf basis, each
of the components of Netback is a supplementary financial measure
and Netback is a non-GAAP ratio. Refer to the "Specified
Financial Measures" section for more information on these
measures.
|
(2)
|
Natural gas revenue
presented as $/Mcf.
|
(3)
|
In the first quarter of
2022, royalty and other revenue includes $10.6 million in respect
of a contingent business interruption insurance claim. Refer to
Note 12 in the unaudited Interim Condensed Consolidated Financial
Statements as at and for the three months ended March 31,
2022.
|
NM means not
meaningful.
|
|
KARR AREA
Karr sales volumes and netbacks are summarized below:
|
Q1
2022
|
Q4 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas (MMcf/d)
|
113.3
|
124.0
|
(9)
|
Condensate and oil
(Bbl/d)
|
17,246
|
18,521
|
(7)
|
Other NGLs (Bbl/d)
|
2,475
|
2,449
|
1
|
Total (Boe/d)
|
38,611
|
41,629
|
(7)
|
% liquids
|
51%
|
50%
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($ millions)
|
($/Boe)
|
Change in $
millions (%)
|
Natural gas revenue
(2)
|
53.1
|
5.21
|
55.2
|
4.84
|
(4)
|
Condensate and oil
revenue
|
182.4
|
117.56
|
161.3
|
94.67
|
13
|
Other NGLs revenue
|
14.4
|
64.60
|
13.1
|
58.20
|
10
|
Royalty and other
revenue
|
0.1
|
-
|
-
|
-
|
NM
|
Petroleum and natural gas sales
|
250.0
|
71.95
|
229.6
|
59.96
|
9
|
Royalties
|
(54.0)
|
(15.52)
|
(35.7)
|
(9.32)
|
51
|
Operating expense
|
(35.2)
|
(10.14)
|
(36.0)
|
(9.38)
|
(2)
|
Transportation and NGLs processing
|
(16.1)
|
(4.65)
|
(14.0)
|
(3.68)
|
15
|
|
144.7
|
41.64
|
143.9
|
37.58
|
1
|
(1)
|
"Netback" is a Non-GAAP
financial measure. When presented on a $/Boe or $/Mcf basis, each
of the components of Netback is a supplementary financial measure
and Netback is a non-GAAP ratio. Refer to the "Specified
Financial Measures" section for more information on these
measures.
|
(2)
|
Natural gas revenue
presented as $/Mcf.
|
NM means not
meaningful.
|
|
First quarter 2022 sales volumes at Karr averaged 38,611 Boe/d
(51% liquids) compared to 41,629 Boe/d (50% liquids) in the fourth
quarter of 2021. Sales volumes were lower primarily due to
natural declines. Several short, unplanned curtailments at
third-party operated facilities in the first quarter, all of which
have now been resolved, also contributed to the
reduction.
The first seven wells at the 16-17 pad came on production ahead
of schedule and under budget with preliminary drilling, completion,
equipping and tie-in ("DCET") costs averaging $6.9 million per well. Average gross peak
30-day production per well was 1,395 Boe/d (3.6 MMcf/d of shale gas
and 802 Bbl/d of NGLs) with an average CGR of 225
Bbl/MMcf.(1) The Company continues to strive for
improved efficiencies in its development activities to mitigate
inflationary pressures on DCET costs without compromising
completion effectiveness or health, safety and environmental
performance. The 16-17 pad, as well as the Wapiti 9-22 pad,
are the Company's first two pads to have been equipped with
instrument air to operate all pneumatically driven
controllers. Paramount plans to equip new pads with
instrument air where possible to minimize methane emissions from
its operations.
Second quarter activities at Karr include completing the
drilling of the remaining five wells at the 16-17 pad. These
wells are expected to be brought onstream in the third
quarter. Second quarter sales volumes are expected to be
impacted by a 16-day full field outage for scheduled turnaround
activities at third-party midstream facilities.
In the second half of 2022, the Company plans to drill,
complete, tie-in and bring on production the four-well 1-2 North
pad and commence drilling the five-well 4-2 South pad. In
addition, the Company is accelerating the drilling of the five-well
4-2 North pad into the fourth quarter. Paramount plans to
bring onstream additional gas lift compression in the year to
support liquids production and continue to build out infrastructure
to debottleneck future production.
_________________________
|
(1)
|
Production measured at
the wellhead. Natural gas sales volumes are lower by approximately
6% and liquids sales volumes are lower by approximately 6% due to
shrinkage. Excludes days when the wells did not produce. 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.
|
|
|
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
|
Q1
2022
|
Q4 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas (MMcf/d)
|
39.2
|
34.9
|
12
|
Condensate and oil
(Bbl/d)
|
8,802
|
7,757
|
13
|
Other NGLs (Bbl/d)
|
792
|
827
|
(4)
|
Total (Boe/d)
|
16,126
|
14,406
|
12
|
% liquids
|
59%
|
60%
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($ millions)
|
($/Boe)
|
Change in $
millions (%)
|
Natural gas revenue
(2)
|
19.0
|
5.39
|
16.3
|
5.07
|
17
|
Condensate and oil
revenue
|
94.7
|
119.49
|
69.2
|
97.03
|
37
|
Other NGLs revenue
|
3.7
|
51.67
|
3.5
|
45.43
|
6
|
Royalty and other revenue
(3)
|
10.6
|
-
|
-
|
-
|
NM
|
Petroleum and natural gas sales
|
128.0
|
88.20
|
89.0
|
67.15
|
44
|
Royalties
|
(7.4)
|
(5.13)
|
(4.1)
|
(3.18)
|
80
|
Operating expense
|
(18.5)
|
(12.69)
|
(18.9)
|
(14.26)
|
(2)
|
Transportation and NGLs processing
|
(7.1)
|
(4.92)
|
(5.0)
|
(3.69)
|
42
|
|
95.0
|
65.46
|
61.0
|
46.02
|
56
|
(1)
|
"Netback" is a Non-GAAP
financial measure. When presented on a $/Boe or $/Mcf basis, each
of the components of Netback is a supplementary financial measure
and Netback is a non-GAAP ratio. Refer to the "Specified
Financial Measures" section for more information on these
measures.
|
(2)
|
Natural gas revenue
presented as $/Mcf.
|
(3)
|
In the first quarter of
2022, royalty and other revenue includes $10.6 million in respect
of a contingent business interruption insurance claim. Refer to
Note 12 in the unaudited Interim Condensed Consolidated Financial
Statements as at and for the three months ended March 31,
2022.
|
NM means not
meaningful.
|
|
First quarter 2022 sales volumes at Wapiti averaged 16,126 Boe/d
(59% liquids) compared to 14,406 Boe/d (60% liquids) in the fourth
quarter of 2021 as a result of new production from the seven-well
9-22 pad that came onstream between late in the fourth quarter of
2021 and the first quarter of 2022. The increase in sales
volumes was achieved despite three unplanned outages at the Wapiti
Plant that resulted in approximately three weeks of downtime and
approximately 5,100 Boe/d of lost production in the
quarter.
Royalty and other revenue for the three months ended
March 31, 2022 includes $10.6 million in respect of the Company's
business interruption claim arising from outages at the Wapiti
Plant in 2020 and 2021.
Despite operational challenges associated with outages at the
Wapiti Plant, initial results from the seven-well 9-22 pad have
been encouraging, averaging gross peak 30-day production per well
of 1,503 Boe/d (4.0 MMcf/d of shale gas and
840 Bbl/d of NGLs) with an average CGR of
211 Bbl/MMcf.(1)
Drilling operations at the eight-well 8-22 pad that commenced in
late 2021 are now complete. The pad is the Company's first
where all wells have been configured as monobores. This
delivers a cost advantage compared to conventional multiple casing
wells due to lower steel requirements and higher pumping
efficiencies.
_________________________
|
(1)
|
Production measured at
the wellhead. Natural gas sales volumes are lower by approximately
12% and liquids sales volumes are lower by approximately 2% due to
shrinkage. Excludes days when the wells did not produce. 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.
|
|
|
Second quarter sales volumes are anticipated to increase as all
eight wells on the 8-22 pad are brought onstream. Additional
second quarter activities include the drilling of eight wells at
the 6-32 pad, which is forecast to be brought on production in the
third quarter, and the commencement of drilling operations at the
eight well 16-15 pad, which is forecast to be brought on production
in early 2023. The Company also plans to commence the
drilling of the eight well 8-15 pad later in the year.
KAYBOB REGION
Kaybob Region sales volumes averaged 20,726 Boe/d (28% liquids)
in the first quarter compared to 21,725 Boe/d (29% liquids) in the
fourth quarter of 2021. The decrease in production is
primarily attributable to natural declines.
Development commenced at the Company's two Duvernay assets at Kaybob Smoky and Kaybob
North. Drilling operations at the four well 10-35 pad at
Kaybob Smoky were recently completed on time with preliminary
drilling cost estimates coming in approximately 7% under
budget. The Company plans to commence completion operations
in the second quarter and expects all four wells to be onstream in
the third quarter. The Company also plans to expand its 100%
owned and operated 6-16 facility in 2022. Drilling of the two
remaining wells at the three well Kaybob North 12-21 pad have
recently commenced. The Company plans to bring all three
wells onstream in the fourth quarter.
In addition to the activities at Kaybob Smoky and Kaybob North,
Paramount is advancing a number of other high return opportunities
in the Kaybob Region. The first (1.0 net) of four (2.5 net)
Montney gas wells in the Kaybob
Presley area planned for 2022 was drilled, completed and brought
onstream in the first quarter and a second (0.5 net) well was
drilled in the quarter and is forecast to come onstream in the
second quarter. The remaining two (1.0 net) wells at Kaybob
Presley are expected to be drilled, completed and brought onstream
by the fourth quarter. The two (2.0 net) Kaybob Gething oil wells
planned for 2022 have completed drilling operations and are
forecast to come onstream in the third quarter. In addition,
one (1.0 net) Kaybob Montney Oil well is planned to be drilled,
completed and brought onstream over the second and third
quarters.
CENTRAL ALBERTA AND OTHER
REGION
Central Alberta and Other
Region sales volumes averaged 6,674 Boe/d (22% liquids) in the
first quarter compared to 7,505 Boe/d (26% liquids) in the fourth
quarter of 2021. The decrease in production is primarily
attributable to natural declines.
The recently completed acquisition at Willesden Green adds over
90,000 net acres (after deducting near-term expiries) to
Paramount's land position and approximately 200 internally
estimated Duvernay drilling
locations.(1) Prior to the acquisition, the
Company's preliminary development plans for Willesden Green
targeted a full field production plateau of approximately 20,000
Boe/d, which could be sustained for over 15 years based on
approximately 180 internally estimated Duvernay drilling locations. Paramount's
five-year outlook includes capital to advance development of the
asset with production expected to begin ramping up in 2025/26.
The incremental drilling inventory provided by the
acquisition allows for the potential to expand development plans to
increase the ultimate targeted plateau production level. The
Company had already initiated an engineering design study for the
expansion of its majority owned Leafland gas plant in the area as
part of its 2022 capital program and will now incorporate the
acquisition into the study to optimize full field development plans
for Willesden Green. Paramount continues to review its plans
for Willesden Green, including the targeted plateau production
level, capital allocation and pace of development.
_________________________
|
(1)
|
See also "Oil and Gas
Measures and Definitions" in the Advisories section for additional
information respecting internally estimated drilling
locations.
|
HEDGING
Paramount has hedged approximately 31% of its remaining 2022
forecast production to provide greater free cash flow
certainty. The Company's current hedging position is
summarized below:
|
Type
(1)
|
|
Q2
2022
|
Q3
2022
|
Q4
2022
|
Q1
2023
|
Average Price
(2)
|
Oil – WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
3,500
|
3,500
|
3,500
|
–
|
US$75.79/Bbl
|
Oil – WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
3,500
|
3,500
|
3,500
|
–
|
CDN$91.38/Bbl
|
Oil – WTI Collars
(Bbl/d)
|
Financial
|
|
7,000
|
7,000
|
7,000
|
–
|
CDN$82.50/Bbl
(Floor)
|
|
|
|
|
|
|
|
CDN$100.47/Bbl
(Ceiling)
|
Sweet Crude Oil – Basis
(Sale) (Bbl/d)
|
Physical
|
|
5,186
|
–
|
–
|
–
|
WTI -
US$2.15/Bbl
|
|
|
|
|
|
|
|
|
Gas – NYMEX Swaps (Sale)
(MMBtu/d)
|
Financial
|
|
30,000
|
–
|
–
|
–
|
US$4.62/MMBtu
|
Gas – NYMEX Swaps (Sale)
(MMBtu/d)
|
Financial
|
|
–
|
30,000
|
–
|
–
|
US$4.67/MMBtu
|
Gas – NYMEX Swaps (Sale)
(MMBtu/d)
|
Financial
|
|
–
|
–
|
3,370
|
–
|
US$4.91/MMBtu
|
Gas – AECO fixed price
(GJ/d)
|
Physical
|
|
80,000
|
80,000
|
26,957
|
–
|
CDN$3.78/GJ
|
Gas – Dawn fixed price
(MMBtu/d)
|
Physical
|
|
20,000
|
20,000
|
6,739
|
–
|
US$4.03/MMBtu
|
|
|
|
|
|
|
|
|
Fx – CDN/USD Forwards
(US$MM/Month)
|
Forwards
|
|
$15
|
$20
|
$20
|
$10
|
1.2804 C$ /
US$
|
Fx – CDN/USD Collars
(US$MM/Month)
|
Financial
|
|
$5
|
$5
|
$3.3
|
–
|
1.25 C$ / US$
(Floor)
|
|
|
|
|
|
|
|
1.30 C$ / US$
(Ceiling)
|
Fx – CDN/USD Swaps
(US$MM/Month)
|
Financial
|
|
$6.7
|
$10
|
$10
|
$10
|
1.2888 C$ /
US$
|
(1)
|
Financial, refers to
financial commodity and foreign currency exchange contracts.
Physical, refers to fixed-priced and basis physical
contracts. Forwards, refers to foreign currency exchange
forwards contracts.
|
(2)
|
Average price is
calculated using a weighted average of notional volumes and
prices.
|
|
|
ANNUAL GENERAL MEETING
Paramount will hold its annual general meeting of shareholders
in a virtual-only format accessible
at https://meetnow.global/MD9YA2M on Wednesday, May 4, 2022 at 10:30 a.m. (Calgary time).
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-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 Class A common shares are listed on the
Toronto Stock Exchange under the symbol "POU".
Paramount's first quarter 2022 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements, can be obtained on SEDAR at www.sedar.com or on
Paramount's website at
https://www.paramountres.com/investors/financial-shareholder-reports.
A summary of historical financial and operating results is also
available on Paramount's website at
https://www.paramountres.com/investors/financial-shareholder-reports.
FINANCIAL AND OPERATING RESULTS
(1)
|
($ millions, except as
noted)
|
Q1 2022
|
Q4 2021
|
Q1
2021
|
Net income (loss)
|
16.6
|
101.0
|
(82.5)
|
per share – basic
($/share)
|
0.12
|
0.75
|
(0.62)
|
per share – diluted
($/share)
|
0.11
|
0.70
|
(0.62)
|
Cash from operating activities
|
174.9
|
191.8
|
81.3
|
per share – basic
($/share)
|
1.25
|
1.42
|
0.61
|
per share – diluted
($/share)
|
1.20
|
1.33
|
0.61
|
Adjusted funds flow
|
237.8
|
174.6
|
90.9
|
per share – basic
($/share)
|
1.70
|
1.29
|
0.69
|
per share – diluted
($/share)
|
1.63
|
1.21
|
0.69
|
Free cash flow
|
103.4
|
99.0
|
21.6
|
per share – basic
($/share)
|
0.74
|
0.73
|
0.16
|
per share – diluted
($/share)
|
0.71
|
0.69
|
0.16
|
Total assets
|
4,095.5
|
3,885.1
|
3,583.1
|
Long-term debt
|
302.6
|
386.3
|
712.7
|
Net debt
|
361.2
|
456.7
|
761.7
|
Common shares outstanding (millions) (2)
|
140.0
|
139.2
|
132.8
|
|
|
|
|
Sales volumes (3)
|
|
|
|
Natural gas (MMcf/d)
|
272.9
|
284.8
|
273.1
|
Condensate and oil (Bbl/d)
|
31,375
|
32,342
|
29,854
|
Other NGLs (Bbl/d)
|
5,276
|
5,462
|
5,170
|
Total (Boe/d)
|
82,137
|
85,265
|
80,540
|
%
liquids
|
45%
|
44%
|
43%
|
Grande Prairie Region (Boe/d)
|
54,737
|
56,035
|
47,385
|
Kaybob Region (Boe/d)
|
20,726
|
21,725
|
24,938
|
Central Alberta & Other Region (Boe/d)
|
6,674
|
7,505
|
8,217
|
Total (Boe/d)
|
82,137
|
85,265
|
80,540
|
|
|
|
|
|
|
|
|
Netback
|
|
$/Boe
(4)
|
|
$/Boe (4)
|
|
$/Boe (4)
|
|
Natural gas revenue
|
127.1
|
5.18
|
124.7
|
4.76
|
77.3
|
3.14
|
|
Condensate and oil revenue
|
331.9
|
117.53
|
281.1
|
94.46
|
185.9
|
69.20
|
|
Other NGLs revenue
|
29.3
|
61.64
|
27.4
|
54.61
|
15.0
|
32.29
|
|
Royalty and other revenue
|
11.3
|
─
|
1.3
|
─
|
1.9
|
─
|
|
Petroleum and natural gas sales
|
499.6
|
67.59
|
434.5
|
55.40
|
280.1
|
38.64
|
|
Royalties
|
(76.2)
|
(10.31)
|
(52.5)
|
(6.69)
|
(18.6)
|
(2.57)
|
|
Operating expense
|
(89.2)
|
(12.07)
|
(91.0)
|
(11.61)
|
(84.3)
|
(11.63)
|
|
Transportation and NGLs processing
|
(31.3)
|
(4.24)
|
(26.1)
|
(3.33)
|
(27.9)
|
(3.84)
|
|
Sales of commodities purchased (5)
|
48.8
|
6.59
|
22.1
|
2.82
|
8.6
|
1.18
|
|
Commodities purchased (5)
|
(49.1)
|
(6.64)
|
(22.3)
|
(2.85)
|
(8.8)
|
(1.21)
|
|
Netback
|
302.6
|
40.92
|
264.7
|
33.74
|
149.1
|
20.57
|
|
Risk management contract settlements
|
(49.7)
|
(6.72)
|
(72.4)
|
(9.23)
|
(32.7)
|
(4.51)
|
|
Netback including risk management contract
settlements
|
252.9
|
34.20
|
192.3
|
24.51
|
116.4
|
16.06
|
|
|
|
|
|
Capital expenditures
|
|
|
|
Grande Prairie Region
|
76.8
|
57.7
|
51.3
|
Kaybob Region
|
31.1
|
3.8
|
5.0
|
Central Alberta & Other Region
|
0.1
|
2.6
|
1.2
|
Corporate
|
9.0
|
1.6
|
1.8
|
Total
|
117.0
|
65.7
|
59.3
|
|
|
|
|
Asset retirement obligations
settlements
|
14.8
|
7.0
|
8.4
|
(1)
|
Adjusted funds flow,
free cash flow and net 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
the "Specified Financial Measures" section for more
information on these measures. Prior period free cash flow has been
reclassified to conform with the current year's
presentation.
|
(2)
|
Common shares are
presented net of shares held in trust under the Company's
restricted share unit plan: Q1 2022: 1.5 million; Q4 2021: 1.5
million; Q1 2021: 1.9 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 refers to sales volumes of "liquids",
"natural gas", "condensate and oil" and "other NGLs".
"Liquids" means NGLs (including condensate)
and oil combined, "natural gas" refers to conventional natural gas
and shale gas combined, "condensate and oil" refers to condensate,
light and medium crude oil and tight oil combined and
"other NGLs" refers to ethane, propane and butane. Below
is a complete breakdown of sales volumes for applicable periods by
the specific product types of shale gas, conventional natural
gas, NGLs, tight oil and light and medium crude oil.
Numbers may not add due to rounding.
|
Total
|
Grande Prairie
Region
|
Kaybob
Region
|
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Shale gas (MMcf/d)
|
213.1
|
220.4
|
197.8
|
151.4
|
156.5
|
120.6
|
35.7
|
35.6
|
42.1
|
Conventional natural gas (MMcf/d)
|
59.8
|
64.4
|
75.3
|
1.1
|
2.4
|
2.0
|
53.6
|
56.8
|
65.8
|
Natural gas
(MMcf/d)
|
272.9
|
284.8
|
273.1
|
152.5
|
158.9
|
122.6
|
89.3
|
92.4
|
107.9
|
Condensate (Bbl/d)
|
29,098
|
29,797
|
27,017
|
26,042
|
26,272
|
23,974
|
2,130
|
2,184
|
2,611
|
Other NGLs (Bbl/d)
|
5,276
|
5,462
|
5,170
|
3,267
|
3,276
|
2,984
|
1,558
|
1,788
|
1,677
|
NGLs
(Bbl/d)
|
34,374
|
35,259
|
32,187
|
29,309
|
29,548
|
26,958
|
3,688
|
3,972
|
4,288
|
Tight oil (Bbl/d)
|
403
|
497
|
479
|
-
|
-
|
-
|
322
|
355
|
342
|
Light and medium crude oil (Bbl/d)
|
1,874
|
2,048
|
2,358
|
6
|
6
|
-
|
1,832
|
2,000
|
2,321
|
Crude oil
(Bbl/d)
|
2,277
|
2,545
|
2,837
|
6
|
6
|
-
|
2,154
|
2,355
|
2,663
|
Total
(Boe/d)
|
82,137
|
85,265
|
80,540
|
54,737
|
56,035
|
47,385
|
20,726
|
21,725
|
24,938
|
|
|
Central and Other
Region
|
Karr
|
Wapiti
|
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Q1
2022
|
Q4
2021
|
Q1
2021
|
Shale gas (MMcf/d)
|
26.0
|
28.2
|
35.1
|
112.8
|
122.5
|
89.1
|
38.6
|
34.0
|
31.5
|
Conventional natural gas (MMcf/d)
|
5.1
|
5.3
|
7.5
|
0.5
|
1.5
|
1.1
|
0.6
|
0.9
|
0.9
|
Natural gas
(MMcf/d)
|
31.1
|
33.5
|
42.6
|
113.3
|
124.0
|
90.2
|
39.2
|
34.9
|
32.4
|
Condensate (Bbl/d)
|
926
|
1,341
|
433
|
17,246
|
18,521
|
16,095
|
8,796
|
7,751
|
7,879
|
Other NGLs (Bbl/d)
|
451
|
398
|
509
|
2,475
|
2,449
|
2,108
|
792
|
827
|
876
|
NGLs
(Bbl/d)
|
1,377
|
1,739
|
942
|
19,721
|
20,970
|
18,203
|
9,588
|
8,578
|
8,755
|
Tight oil (Bbl/d)
|
81
|
142
|
136
|
-
|
-
|
-
|
-
|
-
|
-
|
Light and medium crude oil (Bbl/d)
|
36
|
42
|
37
|
-
|
-
|
-
|
6
|
6
|
-
|
Crude oil
(Bbl/d)
|
117
|
184
|
173
|
-
|
-
|
-
|
6
|
6
|
-
|
Total
(Boe/d)
|
6,674
|
7,505
|
8,217
|
38,611
|
41,629
|
33,230
|
16,126
|
14,406
|
14,155
|
The Company forecasts that 2022 sales volumes will average between
91,000 Boe/d and 95,000 Boe/d (54% shale gas and conventional
natural gas combined, 40% light and medium crude oil, tight oil and
condensate combined and 6% other NGLs). First half 2022 sales
volumes are expected to average between 81,000 Boe/d and 85,000
Boe/d (56% shale gas and conventional natural gas combined, 38%
light and medium crude oil, tight oil and condensate combined and
6% other NGLs). Second half 2022 sales volumes are expected to
average between 101,000 Boe/d and 105,000 Boe/d (53% shale gas and
conventional natural gas combined, 41% light and medium crude oil,
tight oil and condensate 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. 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 ended March 31, 2022 and
2021.
Non-GAAP Ratios
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 (netback and netback
including risk management contract settlements, respectively) 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.
Netback on a $/Boe basis is calculated by dividing netback for
the applicable period by the total production 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 for the applicable period by the
total production 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
production basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net 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 15 – Capital
Structure in the unaudited Interim Condensed Consolidated Financial
Statements of Paramount as at and for the three months ended
March 31, 2022 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 three months ended
March 31, 2022 and 2021 and
(iii) a calculation of net debt as at March 31, 2022 and December 31, 2021.
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) revenue, petroleum and natural gas sales,
royalties, operating expenses, transportation and NGLs processing
expenses, sales of commodities purchased and commodities purchased
on a $/Bbl, $/Mcf or $/Boe 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.
Revenue, petroleum and natural gas sales, royalties, operating
expenses, transportation and NGLs processing expense, sales of
commodities purchased and commodities purchased on a $/Bbl, $/Mcf
or $/Boe basis are calculated by dividing the revenue, petroleum
and natural gas sales, royalties, operating expenses,
transportation and NGLs processing expense, sales of commodities
purchased or commodities purchased, as applicable, over the
referenced period by the aggregate applicable units of production
(Bbl, Mcf or Boe) 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:
- the expectation that the Company will achieve its net debt
target of about $300 million mid-year
2022 and potential net debt to adjusted funds flow at
year-end;
- planned abandonment and reclamation expenditures and activities
in 2022 and 2023;
- planned capital expenditures in 2022;
- forecast sales volumes for 2022 and certain periods
therein;
- forecast free cash flow in 2022;
- preliminary anticipated capital expenditures in 2023 and the
resulting expected 2023 average sales volumes and free cash
flow;
- expected production growth at Karr in 2023 and the potential
range of plateau production at Karr in 2024;
- the Company's five-year outlook for capital spending, annual
production growth rate and cumulative free cash flow;
- planned exploration, development and production activities,
including the expected timing of drilling, completing and bringing
new wells on production;
- the expectation that second quarter sales volumes at Karr will
be impacted by a 16-day full field outage for scheduled turnaround
activities at third-party midstream facilities;
- expected increases in sales volumes at Wapiti in the second
quarter of 2022;
- internally estimated drilling locations and potential plateau
production volumes at Willesden Green and the time period over
which plateau production volumes may be maintained; and
- the payment of future dividends under the Company's monthly
dividend program.
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 the COVID-19 pandemic on the Company;
- the ability to realize expected cost savings;
- royalty rates, taxes and capital, operating, general &
administrative and other costs;
- foreign currency exchange rates, interest rates and the rate of
inflation;
- general business, economic and market conditions;
- the performance of wells and facilities;
- the ability of Paramount to obtain the required capital to
finance its exploration, development and other operations and meet
its commitments and financial obligations;
- the ability of Paramount to obtain equipment, materials,
services and personnel in a timely manner and at an acceptable cost
to carry out its activities;
- the ability of Paramount to secure adequate product processing,
transportation, fractionation and storage capacity on acceptable
terms and the capacity and reliability of facilities;
- the ability of Paramount to market its natural gas and liquids
successfully to current and new customers;
- the ability of Paramount and its industry partners to obtain
drilling success (including in respect of anticipated production
volumes, reserves additions, liquids yields and resource
recoveries) and operational improvements, efficiencies and results
consistent with expectations;
- the timely receipt of required governmental and regulatory
approvals;
- the receipt of benefits under government programs;
- the application of regulatory requirements respecting
abandonment and reclamation; and
- anticipated timelines and budgets being met in respect of
drilling programs and other operations (including well completions
and tie-ins, the construction, commissioning and start-up of new
and expanded facilities, including third-party facilities, and
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;
- the potential for changes to preliminary anticipated 2023
capital expenditures prior to finalization and changes to the
resulting expected 2023 average sales volumes and free cash
flow;
- the potential for changes to the Company's five-year outlook
for capital spending, annual production growth rate and cumulative
free cash flow;
- changes in foreign currency exchange rates, interest rates and
the rate of inflation;
- the uncertainty of estimates and projections relating to future
revenue, free cash flow, production, reserve additions, product
yields (including condensate to natural gas ratios), resource
recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate product processing,
transportation, fractionation, 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 an acceptable cost, 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);
- processing, pipeline, and fractionation infrastructure outages,
disruptions and constraints;
- 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 and obtain financing to fund planned exploration,
development and operational activities and meet current and future
commitments and obligations (including product 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;
- 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 aboriginal claims and in maintaining
relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, insurance
claims, 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 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 under the Company's
monthly dividend program 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 sections titled "Risk
Factors" in Paramount's annual information form for the year
ended December 31, 2021, which is
available on SEDAR at www.sedar.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 2022 and future periods, 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.
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
|
|
|
|
MMcf
|
Millions of cubic
feet
|
Oil
Equivalent
|
|
MMcf/d
|
Millions of cubic feet
per day
|
Boe
|
Barrels of oil
equivalent
|
|
AECO
|
AECO-C reference
price
|
MBoe
|
Thousands of barrels of
oil equivalent
|
|
WTI
|
West Texas
Intermediate
|
MMBoe
|
Millions of barrels of
oil equivalent
|
|
Boe/d
|
Barrels of oil
equivalent per day
|
|
|
|
|
|
|
|
|
|
This press release contains disclosures expressed as "Boe",
"$/Boe", "MBoe", "MMBoe" 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 three months ended March 31,
2022, the value ratio between crude oil and natural gas was
approximately 27:1. 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 refers to "CGR", a metric commonly used in
the oil and natural gas industry. "CGR" means condensate to
gas ratio and is calculated by dividing wellhead raw liquids
volumes by wellhead raw natural gas volumes. This
metric does not have a standardized meaning and may not be
comparable to similar measures presented by other companies. As
such, it should not be used to make comparisons. Management uses
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.
This press release contains information respecting Paramount's
internal estimate of Duvernay
drilling locations at Willesden Green. The referenced drilling
locations represent future potential undeveloped gross locations as
estimated effective December 31, 2021
by internal qualified reserves evaluators from Paramount. The
referenced drilling locations were determined by Paramount's
internal evaluators based on, among other matters, their assessment
of available reservoir, geological and technical information, the
economic thresholds necessary for development and potential future
development plans. There is no certainty that the Company
will drill any of the identified future potential undeveloped
locations and there is no certainty that such locations will result
in any reserves or production. The locations on which the
Company will actually drill wells, including the number and timing
thereof, will be dependent upon the availability of funding,
regulatory approvals, seasonal restrictions, oil, NGLs and natural
gas prices, costs, actual drilling results, additional reservoir,
geological and technical information that is obtained and other
factors. While certain of the estimated undeveloped locations have
been de-risked by drilling existing wells in relative close
proximity to such locations, many of the locations are further away
from existing wells where management has less information about the
characteristics of the reservoir and therefore there is more
uncertainty as to whether wells will be drilled in such locations,
and if wells are drilled in such locations there is more
uncertainty that such wells will result in any reserves or
production. There is no guarantee that any internally
estimated future potential development locations will be included
and assigned reserves in any future reserves report prepared for
the Company.
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, 2021 which is available on SEDAR at www.sedar.com.
SOURCE Paramount Resources Ltd.