CALGARY, AB, March 2, 2022 /CNW/ - Paramount Resources Ltd.
("Paramount" or the "Company") (TSX: POU) is pleased to report 2021
annual results that include record adjusted funds flow, continuing
capital discipline, increased reserves with strong finding and
development costs and recycle ratios and a 47% year-over-year
reduction in net debt. Paramount is also pleased to announce
that it is increasing its regular monthly dividend from
$0.06 per share to $0.08 per share beginning March 2022 and forecasting higher 2022 production
and free cash flow.
HIGHLIGHTS
- Annual sales volumes averaged 82,001 Boe/d (44% liquids) in
2021, in line with guidance. Fourth quarter 2021 sales volumes
averaged 85,265 Boe/d (44% liquids).(1)
-
- Fourth quarter sales volumes at Karr averaged 41,629 Boe/d (50%
liquids) compared to 39,878 Boe/d (52% liquids) in the third
quarter.
- Fourth quarter sales volumes at Wapiti averaged 14,350 Boe/d
(60% liquids) compared to 14,651 Boe/d (62% liquids) in the third
quarter.
- Cash from operating activities was $482.1 million in 2021 and $191.8 million in the fourth quarter. Adjusted
funds flow in 2021 was $499.8 million
($3.74 per basic share) and
$174.6 million ($1.29 per basic share) in the fourth quarter,
representing annual and quarterly records for the
Company.(2)
- 2021 capital expenditures totaled $274.6
million and were predominantly focused on drilling and
completion activities at Karr, Wapiti and the Willesden Green
Duvernay. Capital expenditures were $15.4
million less than the midpoint of previous guidance,
reflecting strong execution and a continued focus on cost
control.
- In 2021, the Company achieved proved plus probable ("P+P")
reserves additions of 82.8 MMBoe, P+P finding and development
("F&D") costs of $2.12/Boe and a
P+P recycle ratio of 12.6x. Total proved ("TP") reserves additions
in 2021 were 72.9 MMBoe, with TP F&D costs of $6.72/Boe and TP recycle ratio of
4.0x.(3)
__________
|
(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 is
a capital management measure used by Paramount. Adjusted
funds flow per share is a supplementary financial measure.
Refer to the "Specified Financial Measures" section for more
information on these measures.
|
(3)
|
Readers are referred to
the advisories concerning "Reserves Data". Reserves evaluated
by McDaniel & Associates Consultants Ltd. ("McDaniel") as of
December 31, 2021 in accordance with National Instrument 51-101
definitions, standards and procedures. Reserves are gross reserves
representing working interest before royalties. 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.
|
- Operating costs averaged $11.37/Boe in 2021, 4% lower than 2020. Karr
operating costs averaged $9.57/Boe in
2021.(1)
- Abandonment and reclamation expenditures totaled $25.4 million in 2021, net of $9.7 million funded under the Alberta Site
Rehabilitation Program ("ASRP").
- Free cash flow was $191.8 million
($1.44 per basic share) in 2021 and
$99.0 million ($0.73 per basic share) in the fourth
quarter.(2)
- The Company reduced net debt by $397.4
million year-over-year to $456.7
million at December 31,
2021.(3)
-
- Drawings under Paramount's $900
million credit facility were $389.1
million at December 31,
2021.
- Non-core property dispositions generated aggregate proceeds of
$165.5 million in 2021 and a further
$67 million was received in the year
in settlement of the previously disclosed dissent proceedings
respecting an investment in securities.
- In the fourth quarter, all $35
million of the Company's 7.5% convertible debentures were
converted by holders into 5.2 million class A common shares
("Common Shares") of the Company.
- Net debt to adjusted funds flow at year-end was approximately
0.9x.
- Net debt does not account for the $372.1
million carrying value of the Company's investments in
securities as at December 31,
2021.
- The Company implemented a regular monthly dividend of
$0.02 per Common Share in
July 2021 and tripled it to
$0.06 per Common Share in
November 2021. The Company is
increasing its monthly dividend to $0.08 per Common Share beginning in March 2022.
- In the first quarter of 2022, the Company completed a highly
complementary asset acquisition in the Grande Prairie Region for
$24.4 million (the "Grande Prairie
Acquisition"), which is expected to contribute approximately 1,000
Boe/d to annual 2022 sales volumes.
RESERVES
- Paramount's P+P reserves increased 5% to 662 MMBoe in 2021
compared to 632 MMBoe in 2020. TP and proved developed producing
("PDP") reserves increased 9% and 4%, respectively.
-
- In the Grande Prairie Region, where the majority of 2021
development activity occurred and the Company achieved further
reductions in its cost structure, P+P reserves were up 8%, TP
reserves were up 2% and PDP reserves were up 20%.
- The Company's reserves replacement ratio was 1.4x for PDP
reserves.(4)
__________
|
(1)
|
Operating costs on a
$/Boe basis is a supplementary financial measure. Refer to
the "Specified Financial Measures" section for more information on
this measure.
|
(2)
|
Free cash flow is a
capital management measure used by Paramount. Free cash flow
per share is a supplementary financial measure. Refer to the
"Specified Financial Measures" section for more information on
these measures.
|
(3)
|
Net debt and net debt
to adjusted funds flow are capital management measures used by
Paramount. Refer to the "Specified Financial Measures"
section for more information on these measures.
|
(4)
|
See "Oil and Gas
Measures and Definitions" in the Advisories section of this
document for a description of the calculation and use
of reserves replacement ratio.
|
- Paramount achieved strong F&D costs and recycle ratios in
2021 due to lower drilling, completion, equipping and tie-in costs
across its major resource plays and higher
netbacks.(1)
|
F&D
($/Boe)
|
Recycle Ratio
*
|
|
Total
|
Grande
Prairie
|
Total
|
Grande
Prairie
|
Proved Developed
Producing
|
6.22
|
6.53
|
4.3
|
5.1
|
Total Proved
|
6.72
|
1.99
|
4.0
|
16.8
|
Proved plus
Probable
|
2.12
|
0.59
|
12.6
|
56.2
|
- Estimated future net revenue at December
31, 2021, discounted at 10% before tax, totaled $1.4 billion for PDP reserves, $3.6 billion for TP reserves and $6.2 billion for P+P
reserves.(2)
2022 GUIDANCE
The Company's planned 2022 capital expenditures remain unchanged
at a range of between $500 million
and $540 million, with anticipated
efficiency gains offsetting certain inflationary pressures.
The 2022 capital budget is focused on development and
debottlenecking operations at Karr to grow production to 43,000 to
47,000 Boe/d in the second half of 2022, development activities at
Wapiti to achieve targeted plateau production of 30,000 Boe/d in
2023 and development activities at Kaybob to advance the
Duvernay plays at Kaybob Smoky and
Kaybob North. 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 is increasing its 2022 annual production guidance to
average between 91,000 Boe/d and 95,000 Boe/d (46% liquids) to
reflect the impact of the Grande Prairie Acquisition.
Although production in early 2022 at Wapiti was affected by two
unplanned outages totaling 18 days at the third-party operated
Wapiti natural gas processing facility, well outperformance is
anticipated to offset this unplanned downtime.
- First half 2022 sales volumes are still expected to average
between 81,000 Boe/d and 85,000 Boe/d (44% liquids), taking into
account a planned 16-day full field outage at Karr during the
second quarter for turnaround activities at third-party midstream
facilities.
- Second half 2022 sales volumes are now expected to average
between 101,000 Boe/d and 105,000 Boe/d (47% liquids) as numerous
new wells from the Company's capital program are brought
onstream.
Paramount is increasing its forecast of 2022 free cash flow from
approximately $455 million to
approximately $590 million to reflect
higher commodity price assumptions and higher forecast
production.(3)
__________
|
(1)
|
Netback is a non-GAAP
financial measure. Refer to the "Specified Financial
Measures" section for more information on this measure.
|
(2)
|
Net present values of
future net revenue were determined using forecast prices and costs
and do not represent fair market value.
|
(3)
|
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 expense, (iv) realized pricing of
$61.95/Boe (US$86.30/Bbl WTI, US$4.74/MMBtu NYMEX, $4.25/GJ AECO),
(v) royalties of $9.45/Boe, (vi) operating costs of $11.15/Boe,
(vii) transportation and processing costs of $3.75/Boe and (viii) a
$US/$Cdn exchange rate of $0.788.
|
As previously disclosed, the Company's free cash flow priorities
are (i) the achievement of targeted leverage levels, (ii)
shareholder returns and (iii) incremental growth.
- The Company expects to achieve its net debt target of about
$300 million in the third quarter of
2022 based on its 2022 free cash flow forecast.
- Remaining 2022 free cash flow will be available to:
-
- further augment shareholder returns through additional
increases in the regular monthly dividend, special dividends or
opportunistic repurchases of Common Shares under the Company's
normal course issuer bid; and
- reinvest in incremental organic growth or strategic
acquisitions.
The Company continues to budget approximately $41 million for abandonment and reclamation
activities in 2022. Approximately $8
million is to be funded directly through the ASRP, resulting
in approximately $33 million net to
Paramount. The majority of these funds will be directed to
the Zama area.
PRELIMINARY 2023 BUDGET
Paramount's anticipated 2023 capital expenditure budget, based
on preliminary planning and current market conditions, remains
unchanged at a range of between $475
million and $525
million.
Paramount expects that a capital program in this range will
result in 2023 average sales volumes of between 98,500 Boe/d and
103,500 Boe/d (48% liquids), 1,000 Boe/d higher than previously
estimated.
Paramount is updating its estimate of 2023 free cash flow that
would be expected from such a capital program from approximately
$450 million to approximately
$580 million to reflect higher
commodity price assumptions and higher estimated
production.(1)
FIVE-YEAR OUTLOOK
Paramount is updating its previously provided five-year outlook
to reflect recent commodity prices. The Company now
anticipates cumulative free cash flow through to the end of 2026 of
over $3.3 billion, up from
$2.7 billion. The Company
continues to anticipate annual capital expenditures of
approximately $500 million and a
compound annual production growth rate of approximately 5 percent
through the period. (2)
INCREASED DIVIDEND
Paramount's Board of Directors has approved an increase in the
Company's regular monthly dividend from $0.06 to $0.08 per
Common Share. The first increased dividend will be payable on
March 31, 2022 to shareholders of
record on March 15, 2022. The
dividend will be designated as an "eligible dividend" for
Canadian income tax purposes.
__________
|
(1)
|
The stated 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 net abandonment and reclamation costs, (iii) $7 million
in geological and geophysical expenses, (iv) realized pricing of
$54.60/Boe (US$76.96/Bbl WTI, US$3.84/MMBtu NYMEX, $3.39/GJ AECO),
(v) royalties of $8.55/Boe, (vi) operating costs of $10.65/Boe,
(vii) transportation and processing costs of $3.65/Boe and (viii) a
$US/$Cdn exchange rate of $0.787.
|
(2)
|
The five-year outlook
is based on preliminary planning and current market conditions and
is subject to change as conditions evolve. 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 February 16, 2022, and (v) internal management estimates of
future royalties, operating costs and transportation and processing
costs.
|
HEDGING
Paramount has hedged approximately 33% of its 2022 forecast
production to provide greater free cash flow certainty. The
Company's current 2022 hedging position is summarized below:
|
Type
(1)
|
|
Q1
2022
|
Q2
2022
|
Q3
2022
|
Q4
2022
|
Average Price (2)
|
Oil – WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
3,500
|
3,500
|
3,500
|
3,500
|
US$75.79/Bbl
|
Oil – WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
9,500
|
–
|
–
|
–
|
CDN$87.90/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
|
7,000
|
CDN$82.50/Bbl
(Floor)
|
|
|
|
|
|
|
|
CDN$100.47/Bbl
(Ceiling)
|
Condensate – Basis
(Sale) (Bbl/d)
|
Physical
|
|
2,098
|
–
|
–
|
–
|
WTI +
US$3.13/Bbl
|
Sweet Crude Oil – Basis
(Sale) (Bbl/d)
|
Physical
|
|
–
|
5,186
|
–
|
–
|
WTI -
US$2.15/Bbl
|
Gas – NYMEX Swaps
(Sale) (MMBtu/d)
|
Financial
|
|
40,000
|
–
|
–
|
–
|
US$4.15/MMBtu
|
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
|
|
40,000
|
–
|
–
|
–
|
CDN$4.06/GJ
|
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$4.03/MMBtu
|
Fx – CDN/USD Swaps
(US$MM/Month)
|
Financial
|
|
$5
|
$5
|
$5
|
$5
|
1.27 C$ /
US$
|
Fx – CDN/USD Collars
(US$MM/Month)
|
Financial
|
|
$5
|
$5
|
$5
|
$3.3
|
1.25 C$ / US$
(Floor)
|
|
|
|
|
|
|
|
1.30 C$ / US$
(Ceiling)
|
|
(1) Financial, refers
to financial commodity contracts. Physical, refers to fixed-priced
and basis physical contracts. (2) Average price is calculated using a weighted
average of notional volumes and prIces.
|
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,
2021 (the "Consolidated Financial Statements") and the
accompanying management's discussion and analysis (the "MD&A")
and (ii) 2021 annual information form, which contains additional
important information concerning the Company's reserves, properties
and operations, can be obtained on SEDAR at www.sedar.com 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.
ANNUAL GENERAL MEETING
Paramount will hold its annual general meeting of shareholders
in a virtual-only format on Wednesday, May
4, 2022 at 10:30 a.m.
(Calgary time).
FINANCIAL AND
OPERATING RESULTS (1)
|
|
|
|
($ millions, except
as noted)
|
Three months ended
December 31
|
Year ended December
31
|
|
2021
|
|
2020
|
2021
|
2020
|
Net income
(loss)
|
101.0
|
|
311.5
|
|
236.9
|
(22.7)
|
per share – basic
($/share)
|
0.75
|
|
2.35
|
|
1.77
|
(0.17)
|
per share – diluted
($/share)
|
0.70
|
|
2.35
|
|
1.67
|
(0.17)
|
Cash from operating
activities
|
191.8
|
|
53.2
|
|
482.1
|
80.9
|
per share – basic
($/share)
|
1.42
|
|
0.40
|
|
3.61
|
0.61
|
per share – diluted
($/share)
|
1.33
|
|
0.40
|
|
3.39
|
0.61
|
Adjusted funds
flow
|
174.6
|
|
67.9
|
|
499.8
|
150.0
|
per share – basic
($/share)
|
1.29
|
|
0.51
|
|
3.74
|
1.12
|
per share – diluted
($/share)
|
1.21
|
|
0.51
|
|
3.51
|
1.12
|
Free cash
flow
|
99.0
|
|
0.6
|
|
191.8
|
(113.7)
|
per share – basic
($/share)
|
0.73
|
|
0.01
|
|
1.44
|
(0.85)
|
per share – diluted
($/share)
|
0.69
|
|
0.01
|
|
1.36
|
(0.85)
|
Total
assets
|
|
|
|
|
3,885.1
|
3,497.0
|
Long-term
debt
|
|
|
|
|
386.3
|
813.5
|
Net
debt
|
|
|
|
|
456.7
|
854.1
|
Common shares
outstanding (millions) (2)
|
|
|
|
|
139.2
|
132.3
|
|
|
|
|
|
|
|
Sales volumes
(3)
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
284.8
|
|
256.3
|
275.2
|
248.7
|
Condensate and oil
(Bbl/d)
|
32,342
|
|
25,752
|
30,989
|
22,565
|
Other NGLs
(Bbl/d)
|
5,462
|
|
4,987
|
5,147
|
4,325
|
Total
(Boe/d)
|
85,265
|
|
73,460
|
82,001
|
68,340
|
%
liquids
|
44%
|
|
42%
|
44%
|
39%
|
Grande Prairie Region
(Boe/d)
|
56,035
|
|
37,782
|
51,869
|
31,076
|
Kaybob Region
(Boe/d)
|
21,725
|
|
27,056
|
22,588
|
28,685
|
Central Alberta &
Other Region (Boe/d)
|
7,505
|
|
8,622
|
7,544
|
8,579
|
Total
(Boe/d)
|
85,265
|
|
73,460
|
82,001
|
68,340
|
|
|
|
|
|
|
|
|
|
|
Netback
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
Natural gas
revenue
|
124.7
|
4.76
|
66.7
|
2.83
|
|
373.3
|
3.72
|
204.9
|
2.25
|
Condensate and
oil revenue
|
281.1
|
94.46
|
123.3
|
52.03
|
|
926.5
|
81.91
|
383.8
|
46.47
|
Other NGLs
revenue
|
27.4
|
54.61
|
9.5
|
20.61
|
|
78.6
|
41.84
|
24.7
|
15.63
|
Royalty and
other revenue
|
1.1
|
─
|
2.5
|
─
|
|
4.6
|
─
|
12.6
|
─
|
Petroleum and
natural gas sales
|
434.3
|
55.37
|
202.0
|
29.89
|
|
1,383.0
|
46.21
|
626.0
|
25.03
|
Royalties
|
(52.5)
|
(6.69)
|
(11.7)
|
(1.73)
|
|
(127.0)
|
(4.24)
|
(31.3)
|
(1.25)
|
Operating
expense
|
(91.0)
|
(11.61)
|
(79.8)
|
(11.80)
|
|
(340.4)
|
(11.37)
|
(297.1)
|
(11.88)
|
Transportation
and NGLs processing
|
(26.1)
|
(3.33)
|
(24.6)
|
(3.63)
|
|
(114.5)
|
(3.83)
|
(101.3)
|
(4.05)
|
Netback
|
264.7
|
33.74
|
85.9
|
12.73
|
|
801.1
|
26.77
|
196.3
|
7.85
|
Risk management
contract settlements
|
(72.4)
|
(9.23)
|
7.9
|
1.18
|
|
(218.3)
|
(7.29)
|
37.6
|
1.50
|
Netback including
risk management contract settlements
|
192.3
|
24.51
|
93.8
|
13.91
|
|
582.8
|
19.48
|
233.9
|
9.35
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
|
|
|
Grande Prairie
Region
|
57.7
|
|
64.3
|
228.6
|
196.9
|
Kaybob
Region
|
3.8
|
|
1.8
|
14.5
|
16.4
|
Central Alberta &
Other Region
|
2.6
|
|
0.8
|
25.3
|
4.6
|
Corporate
|
1.6
|
|
(1.8)
|
6.2
|
2.3
|
Total
|
65.7
|
|
65.1
|
274.6
|
220.2
|
|
|
|
|
|
|
Asset retirement
obligations settlements
|
7.0
|
|
0.1
|
25.4
|
35.0
|
(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 results
have been reclassified to conform with the current years'
presentation.
|
(2)
|
Common shares are
presented net of shares held in trust under the Company's
restricted share unit plan: 2021: 1.5 million; 2020: 1.9 million;
2019: 0.9 million.
|
(3)
|
Other NGLs means
ethane, propane and butane. Readers are referred 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.
|
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".
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.
|
Annual
|
|
Total
|
Grande Prairie
Region
|
Kabob
Region
|
Central Alberta
and
Other Region
|
|
2021
|
2020
|
2021
|
2020
|
2021
|
2020
|
2021
|
2020
|
Shale gas
(MMcf/d)
|
207.9
|
156.7
|
138.8
|
77.2
|
38.6
|
43.8
|
30.5
|
35.7
|
Conventional natural
gas (MMcf/d)
|
67.3
|
92.0
|
2.2
|
1.4
|
58.6
|
82.1
|
6.5
|
8.5
|
Natural gas
(MMcf/d)
|
275.2
|
248.7
|
141.0
|
78.6
|
97.2
|
125.9
|
37.0
|
44.2
|
Condensate
(Bbl/d)
|
28,328
|
19,334
|
25,253
|
15,991
|
2,295
|
2,885
|
781
|
458
|
Other NGLs
(Bbl/d)
|
5,147
|
4,325
|
3,103
|
1,964
|
1,612
|
1,812
|
432
|
549
|
NGLs
(Bbl/d)
|
33,475
|
23,659
|
28,356
|
17,955
|
3,907
|
4,697
|
1,213
|
1,007
|
Tight oil
(Bbl/d)
|
487
|
462
|
–
|
–
|
355
|
301
|
131
|
161
|
Light and Medium crude
oil (Bbl/d)
|
2,174
|
2,768
|
5
|
14
|
2,129
|
2,709
|
40
|
46
|
Crude oil
(Bbl/d)
|
2,661
|
3,230
|
5
|
14
|
2,484
|
3,010
|
171
|
207
|
Total
(Boe/d)
|
82,001
|
68,340
|
51,869
|
31,076
|
22,588
|
28,685
|
7,544
|
8,579
|
|
Annual
|
|
Karr
|
Wapiti
|
|
2021
|
2020
|
2021
|
2020
|
Shale gas
(MMcf/d)
|
107.9
|
55.6
|
31.0
|
21.5
|
Conventional natural
gas (MMcf/d)
|
1.3
|
0.7
|
0.6
|
0.4
|
Natural gas
(MMcf/d)
|
109.2
|
56.3
|
31.6
|
21.9
|
NGLs
(Bbl/d)
|
20,188
|
11,389
|
8,159
|
6,550
|
Total
(Boe/d)
|
38,381
|
20,777
|
13,432
|
10,207
|
|
Q4
|
|
Total
|
Grande Prairie
Region
|
Kabob Region
|
Central Alberta
and
Other Region
|
|
2021
|
2020
|
2021
|
2020
|
2021
|
2020
|
2021
|
2020
|
Shale gas
(MMcf/d)
|
220.4
|
170.7
|
156.5
|
92.7
|
35.6
|
41.9
|
28.2
|
36.1
|
Conventional natural
gas (MMcf/d)
|
64.4
|
85.6
|
2.4
|
1.6
|
56.8
|
76.3
|
5.3
|
7.7
|
Natural gas
(MMcf/d)
|
284.8
|
256.3
|
158.9
|
94.3
|
92.4
|
118.2
|
33.5
|
43.8
|
Condensate
(Bbl/d)
|
29,797
|
22,782
|
26,272
|
19,635
|
2,184
|
2,631
|
1,341
|
515
|
Other NGLs
(Bbl/d)
|
5,462
|
4,987
|
3,276
|
2,429
|
1,788
|
1,953
|
398
|
605
|
NGLs
(Bbl/d)
|
35,259
|
27,769
|
29,548
|
22,064
|
3,972
|
4,584
|
1,739
|
1,120
|
Tight oil
(Bbl/d)
|
497
|
437
|
–
|
–
|
355
|
299
|
142
|
138
|
Light and Medium crude
oil (Bbl/d)
|
2,048
|
2,533
|
6
|
–
|
2,000
|
2,480
|
42
|
54
|
Crude oil
(Bbl/d)
|
2,545
|
2,970
|
6
|
–
|
2,355
|
2,779
|
184
|
192
|
Total
(Boe/d)
|
85,265
|
73,460
|
56,035
|
37,782
|
21,725
|
27,056
|
7,505
|
8,622
|
|
Q4
|
|
Karr
|
Wapiti
|
|
2021
|
2020
|
2021
|
2020
|
Shale gas
(MMcf/d)
|
122.5
|
69.6
|
34.1
|
22.8
|
Conventional natural
gas (MMcf/d)
|
1.5
|
0.9
|
0.6
|
0.5
|
Natural gas
(MMcf/d)
|
124.0
|
70.5
|
34.7
|
23.3
|
NGLs
(Bbl/d)
|
20,970
|
15,165
|
8,568
|
6,875
|
Total
(Boe/d)
|
41,629
|
26,914
|
14,350
|
10,764
|
Fourth quarter 2021 sales volumes at Karr averaged 41,629 Boe/d
(122.5 MMcf/d of shale gas, 1.5 MMcf/d of conventional natural gas
and 20,970 Bbl/d of NGLs), compared to 39,878 Boe/d (113.0 MMcf/d
of shale gas, 1.4 MMcf/d of conventional natural gas and 20,805
Bbl/d of NGLs) in the third quarter of 2021. Fourth quarter
2021 sales volumes at Wapiti averaged 14,350 Boe/d (34.1 MMcf/d of
shale gas, 0.6 MMcf/d of conventional natural gas and 8,568 Bbl/d
of NGLs), compared to 14,651 Boe/d (32.7 MMcf/d of shale gas, 0.6
MMcf/d of conventional natural gas and 9,100 Bbl/d of NGLs) in the
third quarter of 2021.
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, netback including risk management contract settlements
and F&D capital 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) less royalties, operating expense and
transportation and NGLs processing expense. 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 Company's 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
years ended December 31, 2021 and
2020 and for the three months ended December
31, 2021 and 2020.
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 year excluding corporate expenditures plus the
change from the prior year in estimated future development capital
included in the reserves evaluation prepared by McDaniel.
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, 2021 and
2020. Prior period results have been restated to conform with
the current years' presentation to reflect the inclusion of changes
in estimated future development capital in the calculation of
F&D capital.
($
millions)
|
Grande Prairie
Region (1)
|
Total Company
(1)
|
Proved Developed
Producing
|
2021
|
2020
|
2021
|
2020
|
Capital
expenditures
|
229
|
197
|
275
|
221
|
Corporate
expenditures
|
–
|
–
|
(6)
|
(2)
|
Change in estimated
future development capital
|
(22)
|
(4)
|
(11)
|
54
|
F&D
Capital
|
207
|
193
|
257
|
273
|
|
|
|
|
|
Total
Proved
|
2021
|
2020
|
2021
|
2020
|
Capital
expenditures
|
229
|
197
|
275
|
221
|
Corporate
expenditures
|
–
|
–
|
(6)
|
(2)
|
Change in estimated
future development capital
|
(182)
|
(736)
|
221
|
(962)
|
F&D
Capital
|
47
|
(539)
|
490
|
(743)
|
|
|
|
|
|
Proved Plus
Probable
|
2021
|
2020
|
2021
|
2020
|
Capital
expenditures
|
229
|
197
|
275
|
221
|
Corporate
expenditures
|
–
|
–
|
(6)
|
(2)
|
Change in estimated
future development capital
|
(197)
|
(1,106)
|
(93)
|
(1,196)
|
F&D
Capital
|
31
|
(909)
|
176
|
(977)
|
|
|
|
|
|
(1) Columns may
not add due to rounding.
|
Non-GAAP Ratios
F&D costs, recycle ratio, netback and netback including risk
management contract settlements presented on a $/Boe of $/Mcf 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;
by (ii) the net changes to reserves in such reserves category from
the prior year from extensions/improved recovery, technical
revisions and economic factors. 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 Reconciliation" in the
Company's annual information form for the year ended December 31, 2021, which is available on
www.sedar.com or at www.paramountres.com, for a description of the
net changes to reserves in each reserves category from the prior
year. See "Advisories – Oil and Gas Definitions and Measures"
for more information about this measure.
Recycle ratio is calculated by dividing the netback (a non-GAAP
financial measure) per Boe for the year by the F&D costs for
the year. 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, for comparative purposes to the 2021 information
included in this press release, are the applicable F&D costs
and recycle ratios for 2020. Prior period results have been
restated to conform with the current years' presentation to reflect
the inclusion of changes in estimated future development capital in
the calculation of F&D capital.
|
F&D
($/Boe)
|
Recycle Ratio
*
|
|
Total
|
Grande
Prairie
|
Total
|
Grande
Prairie
|
Proved Developed
Producing
|
$7.90
|
$8.79
|
1.0x
|
1.3x
|
Total Proved
|
na
|
na
|
na
|
na
|
Proved plus
Probable
|
na
|
na
|
na
|
na
|
Netback on a $/Boe of $/Mcf basis is calculated by dividing
netback (a non-GAAP financial measure) for the applicable period by
the total production during the period in Boe or Mcf. Netback
including risk management contract settlements on a $/Boe of $/Mcf
basis is calculated by dividing netback including risk management
contract settlements for the applicable period by the total
production during the period in Boe or Mcf. 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, net debt and net debt to
adjusted funds flow 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 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, 2021 and 2020 and
(iii) a calculation of net debt as at December 31, 2021 and 2020.
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, 2021
and 2020:
Three months ended
December 31
|
2021
|
2020
|
Cash from operating
activities
|
191.8
|
53.2
|
Change in non-cash
working capital
|
(20.1)
|
12.5
|
Geological and
geophysical expense
|
2.9
|
2.1
|
Asset retirement
obligations settled
|
7.0
|
0.1
|
Closure
costs
|
–
|
–
|
Provisions
|
–
|
–
|
Settlements
|
(7.0)
|
–
|
Transaction and
reorganization costs
|
–
|
–
|
Adjusted funds
flow
|
174.6
|
67.9
|
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, 2021
and 2020:
Three months ended
December 31
|
2021
|
2020
|
Cash from operating
activities
|
191.8
|
53.2
|
Change in non-cash
working capital
|
(20.1)
|
12.5
|
Geological and
geophysical expense
|
2.9
|
2.1
|
Asset retirement
obligations settled
|
7.0
|
0.1
|
Closure
costs
|
–
|
–
|
Provisions
|
–
|
–
|
Settlements
|
(7.0)
|
–
|
Transaction and
reorganization costs
|
–
|
–
|
Adjusted funds
flow
|
174.6
|
67.9
|
Capital
expenditures
|
(65.7)
|
(65.1)
|
Geological and
geophysical expense
|
(2.9)
|
(2.1)
|
Asset retirement
obligation settled
|
(7.0)
|
(0.1)
|
Free cash
flow
|
99.0
|
0.6
|
For comparative purposes to the 2021 information included in
this press release, net debt to adjusted funds flow as at
December 31, 2020 was 5.7x.
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 and transportation and NGLs
processing expenses 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 and transportation and NGLs processing expenses on a
$/Bbl, $/Mcf or $/Boe basis are calculated by dividing the revenue,
petroleum and natural gas sales, royalties, operating expenses or
transportation and NGLs processing expenses, 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:
- planned capital expenditures in 2022;
- forecast sales volumes for 2022 and certain periods
therein;
- the expectation that well outperformance in 2022 will offset
the impact of the unplanned outages at the third-party operated
Wapiti natural gas processing facility;
- forecast free cash flow in 2022;
- the Company's priorities and expectations respecting the
allocation of free cash flow;
- the expectation that the Company will achieve its net debt
target of about $300 million in the
third quarter of 2022;
- the expectation that plateau production will be reached at
Wapiti in 2023;
- planned abandonment and reclamation expenditures and activities
in 2022;
- preliminary anticipated capital expenditures in 2023 and the
resulting expected 2023 average sales volumes and free cash
flow;
- 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; and
- the payment of future dividends under the Company's monthly
dividend program.
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 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;
- 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.
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 1, 2022 and effective December 31, 2021 (the "McDaniel Report").
The price forecast used in the McDaniel Report is an average of the
January 1, 2022 price forecasts for
McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2021 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, 2021, which is available on SEDAR at
www.sedar.com, for a complete description of the McDaniel Report
(including reserves by the specific product types of shale gas,
conventional natural gas, NGLs, tight oil and light and medium
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
|
|
|
|
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 year ended December 31,
2021, the value ratio between crude oil and natural gas was
approximately 24:1. 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. Each of these metrics is determined by the
Company as set out below or elsewhere in this press release. The
metrics are F&D costs, recycle ratio and reserves replacement
ratio. 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.
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 from extensions/improved recovery, technical revisions
and economic factors, 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 by reserves added through
exploration and development.
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.