CALGARY,
AB, Nov. 3, 2022 /CNW/ - Paramount Resources
Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to
announce third quarter 2022 financial and operating results
highlighted by record production, funds flow and free cash flow and
a 2023 capital expenditure budget that is forecast to generate
approximately $650 million in free cash flow on production of
between 105,000 Boe/d and 110,000 Boe/d (46%
liquids).(1)(2) Paramount is also pleased to
announce that it is increasing its regular monthly dividend by 25%
from $0.10 per class A common share
("Common Share") to $0.125 per Common
Share beginning November 2022.
HIGHLIGHTS
- The Company achieved record quarterly sales volumes of 97,601
Boe/d (46% liquids) in the third quarter, including record monthly
sales volumes of 104,506 Boe/d (46% liquids) in September.
-
- Karr sales volumes averaged 38,088 Boe/d (50% liquids) in the
quarter, with September production averaging 40,485 Boe/d (49%
liquids).
- Wapiti sales volumes averaged 27,893 Boe/d (54% liquids) in the
quarter. September production averaged 30,589 Boe/d (54% liquids),
exceeding targeted plateau production one quarter ahead of
schedule.
- Four new Duvernay wells at
Smoky and three new Duvernay wells
at Kaybob North were brought onstream in the third quarter,
increasing Kaybob Region average sales volumes to 24,021 Boe/d (35%
liquids) in the quarter.
- Cash from operating activities was $248.9 million ($1.76 per basic share) in the third quarter.
Adjusted funds flow was $334.3
million ($2.37 per basic
share). Free cash flow was $137.5
million ($0.97 per basic
share).(3)
- Capital expenditures in the quarter totaled $184.3 million and were focused on development
activities at Karr, Wapiti, Kaybob North and Smoky.
- As previously announced, Paramount closed its Willesden Green
Duvernay acquisition in the third quarter. Net of adjustments, the
purchase price was $60.4 million in
cash.
________________________________________
|
(1)
|
Free cash flow is a
capital management measure used by Paramount. Refer to the
"Specified Financial Measures" section for more information on this
measure.
|
(2)
|
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.
|
(3)
|
Adjusted funds flow is
a capital management measure used by Paramount. Cash from
operating activities per basic share, adjusted funds flow per basic
share and free cash flow per basic share are supplementary
financial measures. Refer to the "Specified Financial
Measures" section for more information on these measures.
|
- In early October, the Company also closed its previously
announced disposition of certain non-core infrastructure assets,
comprised of approximately 60 kilometers of operated resource roads
in the Bigstone area of the Kaybob Region (the "Roads
Disposition"), for cash proceeds of $64.2
million net of adjustments. Paramount continues to own
approximately 1,600 gross kilometers of resource roads, largely in
the Kaybob Region.
- Abandonment and reclamation expenditures in the third quarter
totaled $10.2 million, net of
$4.3 million in funding under the
Alberta Site Rehabilitation Program ("ASRP").
- Net debt at September 30, 2022
was $347.0 million. Pro forma the
$64.2 million Roads Disposition, the
Company has achieved its $300 million
net debt target. Net debt does not account for the $451.3 million carrying value of the Company's
investments in securities at September 30,
2022.(1)
INCREASED DIVIDEND
Paramount's Board of Directors has approved a 25% increase in
the regular monthly dividend from $0.10 to $0.125 per
Common Share. The first increased dividend will be payable on
November 30, 2022 to shareholders of
record on November 15, 2022.
The dividend will be designated as an "eligible dividend" for
Canadian income tax purposes.
DELIVERING ON FREE CASH FLOW PRIORITIES
Following the achievement of its net debt target, Paramount's
free cash flow priorities continue to be the maintenance of
conservative leverage levels and the delivery of superior
shareholder returns through a combination of dividends, investments
in growth opportunities and opportunistic share buybacks.
Paramount has and will continue to deliver on these priorities.
- The Company implemented a regular monthly dividend of
$0.02 per share in July 2021, which has now been increased six-fold
to $0.125 per share through four
increases over the past year. Paramount maintains the flexibility
to provide incremental returns through special dividends.
- The Company has allocated incremental capital to its highest
risk-adjusted return organic growth opportunities and to accretive
acquisitions, contributing to the significant growth in free cash
flow and production described in the five-year outlook below.
Paramount continues to actively evaluate additional opportunities
for accretive acquisitions and divestitures and organic growth,
while remaining focused on capital discipline and maintaining a
strong balance sheet.
- The Company has the ability to make opportunistic repurchases
of up to 7.6 million Common Shares under its normal course issuer
bid.
Paramount plans to direct the majority of its near-term free
cash flows to further reduce credit facility drawings in order to
provide additional financial flexibility. Over the last two years,
the Company has reduced net debt by over $500 million while increasing production 50% to
approximately 105,000 Boe/d.
_________________________
|
(1) Net
debt is a capital management measure used by Paramount. Refer
to the "Specified Financial Measures" section for more information
on this measure.
|
UPDATED 2022 GUIDANCE
Fourth quarter 2022 sales volumes are expected to average
between 103,000 Boe/d and 107,000 Boe/d (45% liquids). This
results in expected full year 2022 average sales volumes of between
90,000 Boe/d and 91,000 Boe/d (45% liquids) versus previous
guidance of between 91,000 Boe/d and 93,000 Boe/d (45%
liquids).
The Company's planned 2022 capital expenditures remain unchanged
at a range of between $600 million
and $640
million.(1) Planned 2022
abandonment and reclamation spending totals $35 million, net of $10.5
million in funding under the ASRP.
Paramount is updating its forecast of 2022 free cash flow to
approximately $500 million from
$600 million to reflect updated
commodity prices, production and other
assumptions.(2)
2023 BUDGET AND GUIDANCE
With its achievement of the net debt target, strong free cash
flow profile and deep inventory of high return opportunities,
Paramount is budgeting 2023 capital expenditures in a range of
between $720 million and $760 million, $65
million higher at the midpoint than previous preliminary
guidance. This increase is largely related to infrastructure
and drilling capital to accelerate Duvernay development in the recently expanded
Willesden Green core area that will benefit production in 2024 and
beyond. 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 2023 capital budget at midpoint is broken down as
follows:
- $350 million of sustaining
capital and maintenance activities;
- $80 million of growth capital
associated with production benefits in 2023; and
- $310 million of growth capital
associated with production benefits in 2024 and beyond.
The breakdown by region at midpoint is as follows:
- Grande Prairie Region − $375
million;
- Kaybob Region − $215
million;
- Central Alberta and Other
Region − $125 million; and
- Corporate and Other − $25
million.
The Company has budgeted approximately $45 million for abandonment and reclamation
activities in 2023.
Average sales volumes in 2023 are expected to be between 105,000
Boe/d and 110,000 Boe/d (46% liquids), unchanged from previous
preliminary guidance.
- First half 2023 sales volumes are expected to average between
101,000 Boe/d and 106,000 Boe/d (45% liquids).
- Second half 2023 sales volumes are expected to average between
109,000 Boe/d and 114,000 Boe/d (46% liquids).
_____________________________
|
(1)
|
Capital expenditures
exclude land and property acquisitions and abandonment and
reclamation expenditures.
|
(2)
|
The stated free cash
flow forecast is based on the following assumptions for 2022: (i)
the midpoint of forecast capital spending and production, (ii) $35
million in net abandonment and reclamation costs, (iii) $9 million
in geological and geophysical expenses, (iv) realized pricing of
$69.70/Boe (US$93.99/Bbl WTI, US$6.57/MMBtu NYMEX, $5.22/GJ AECO),
(v) a $US/$CAD exchange rate of $0.766, (vi) royalties of
$10.80/Boe, (vii) operating costs of $12.00/Boe and (viii)
transportation and processing costs of $4.00/Boe.
|
Paramount is forecasting approximately $650 million of free cash flow in 2023,
approximately $75 million lower than
previous preliminary estimates largely as a result of changes in
budgeted capital spending.(1)
The Company's 2023 capital program and increased regular monthly
dividend would remain fully funded down to an average WTI price of
about US$56/Bbl in
2023.(2)
PRELIMINARY 2024 GUIDANCE
Based on preliminary planning and current market conditions,
Paramount anticipates 2024 capital expenditures to range between
$750 million and $850 million, broken down as follows at
midpoint:
- $390 million of sustaining
capital and maintenance activities; and
- $410 million of growth
capital.
The breakdown by region at midpoint is as follows:
- Grande Prairie Region – $385
million;
- Kaybob Region – $200
million;
- Central Alberta and Other
Region – $205 million; and
- Corporate and Other − $10
million.
A capital program in this range would be expected to result in
2024 average sales volumes of between 115,000 Boe/d and 125,000
Boe/d (48% liquids) and free cash flow of approximately
$650
million.(3)
The Company's 2024 capital program and increased regular monthly
dividend would remain fully funded down to an average WTI price of
about US$54/Bbl in
2024.(4)
FIVE-YEAR OUTLOOK
Paramount is providing its five-year outlook for the period from
2023 through to the end of 2027. The Company anticipates
midpoint cumulative free cash flow of approximately $4.2 billion (approximately $30 per basic share(5))
over the period. Paramount anticipates annual capital
expenditures to range between $750
million and $850 million
through the period 2024 to 2027, with sales volumes increasing to
between 140,000 Boe/d and 150,000 Boe/d in 2027, representing
a compound annual production growth rate of approximately 11%
between 2022 and 2027.(6) With
estimated tax pools in excess of $4
billion at September 30, 2022,
the majority of which are immediately deductible, Paramount does
not forecast cash tax in its five-year outlook until 2026.
(1)
|
The stated free cash
flow forecast is based on the following assumptions for 2023: (i)
the midpoint of stated capital spending and production, (ii) $45
million in abandonment and reclamation costs, (iii) $7 million in
geological and geophysical expenses, (iv) realized pricing of
$63.00/Boe (US$80.00/Bbl WTI, US$5.00/MMBtu NYMEX, $4.74/GJ AECO),
(v) a $US/$CAD exchange rate of $0.730, (vi) royalties of
$10.30/Boe, (vii) operating costs of $11.15/Boe and (vii)
transportation and processing costs of $3.55/Boe.
|
(2)
|
Assuming no changes to
the other stated free cash flow forecast assumptions for
2023.
|
(3)
|
The stated free cash
flow estimate is based on the following assumptions for 2024: (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
$58.80/Boe (US$75.00/Bbl WTI, US$4.50/MMBtu NYMEX, $4.27/GJ AECO),
(v) a $US/$CAD exchange rate of $0.735, (vi) royalties of
$9.75/Boe, (vii) operating costs of $10.25/Boe and (vii)
transportation and processing costs of $3.50/Boe.
|
(4)
|
Assuming no changes to
the other stated free cash flow estimate assumptions for
2024.
|
(5)
|
Based on 142.3 million
outstanding Common Shares as at November 1, 2022.
|
(6)
|
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) 2023 realized pricing of
$63.00/Boe (US$80.00/Bbl WTI, US$5.00/MMBtu NYMEX, $4.74/GJ AECO)
and thereafter commodity prices of US$75.00/Bbl WTI, US$4.50/MMBtu
NYMEX and $4.27/GJ AECO, (v) a 2023 $US/$CAD exchange rate of
$0.730 and thereafter a $US/$CAD exchange rate of $0.735 and (vi)
internal management estimates of future royalties, operating costs,
transportation and processing costs and, beginning in 2026, cash
taxes.
|
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Sales volumes and netbacks in the Grande Prairie Region, which
includes Karr and Wapiti, are summarized below:
|
Q3 2022
|
Q2 2022
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
189.6
|
139.8
|
36
|
Condensate and oil
(Bbl/d)
|
30,615
|
22,516
|
36
|
Other NGLs
(Bbl/d)
|
3,758
|
2,914
|
29
|
Total
(Boe/d)
|
65,981
|
48,736
|
35
|
%
liquids
|
52 %
|
52 %
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
Change in $
millions (%)
|
Natural gas revenue
(2)
|
119.9
|
6.87
|
85.1
|
6.69
|
41
|
Condensate and oil
revenue
|
319.2
|
113.34
|
276.4
|
134.91
|
15
|
Other NGLs
revenue
|
18.3
|
52.95
|
17.1
|
64.31
|
7
|
Royalty and other
revenue (3)
|
0.1
|
–
|
1.3
|
–
|
NM
|
Petroleum and natural
gas sales
|
457.5
|
75.37
|
379.9
|
85.65
|
20
|
Royalties
|
(70.5)
|
(11.62)
|
(62.9)
|
(14.17)
|
12
|
Operating
expense
|
(68.1)
|
(11.22)
|
(55.9)
|
(12.61)
|
22
|
Transportation
and NGLs processing
|
(25.7)
|
(4.24)
|
(22.1)
|
(4.99)
|
16
|
|
293.2
|
48.29
|
239.0
|
53.88
|
23
|
(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) Per unit natural gas revenue presented as
$/Mcf.
(3)
Second quarter royalty and other revenue includes $1.3 million
related to a business interruption insurance claim.
NM means not
meaningful.
|
KARR AREA
Karr sales volumes and netbacks are summarized below:
|
Q3 2022
|
Q2 2022
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
113.4
|
94.6
|
20
|
Condensate and oil
(Bbl/d)
|
16,799
|
13,551
|
24
|
Other NGLs
(Bbl/d)
|
2,394
|
1,978
|
21
|
Total
(Boe/d)
|
38,088
|
31,295
|
22
|
%
liquids
|
50 %
|
50 %
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
Change in $
millions (%)
|
Natural gas revenue
(2)
|
71.7
|
6.87
|
56.3
|
6.54
|
27
|
Condensate and oil
revenue
|
178.8
|
115.68
|
166.0
|
134.60
|
8
|
Other NGLs
revenue
|
11.3
|
51.35
|
11.6
|
64.31
|
(3)
|
Petroleum and natural
gas sales
|
261.8
|
74.70
|
233.9
|
82.14
|
12
|
Royalties
|
(47.7)
|
(13.62)
|
(45.8)
|
(16.09)
|
4
|
Operating
expense
|
(39.6)
|
(11.29)
|
(36.0)
|
(12.65)
|
10
|
Transportation
and NGLs processing
|
(15.6)
|
(4.46)
|
(15.2)
|
(5.34)
|
3
|
|
158.9
|
45.33
|
136.9
|
48.06
|
16
|
(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)
Per unit natural gas revenue presented as $/Mcf.
NM means not
meaningful.
|
Third quarter 2022 sales volumes at Karr averaged 38,088 Boe/d (50%
liquids) compared to 31,295 Boe/d (50% liquids) in the second
quarter. Sales volumes were higher in the third quarter as
production resumed following plant turnarounds that occurred in the
second quarter and as new well production from the remaining five
wells at the twelve-well 16-17 pad came onstream late in the third
quarter. Although September production averaged 40,485 Boe/d
(49% liquids), production earlier in the quarter was impacted by
unplanned facility outages and downtime related to extended
workover operations.
All-in drilling, completion, equipping and tie-in ("DCET") costs
for the remaining five wells on the twelve-well 16-17 pad averaged
$8.5 million.
Drilling operations at the five-well 4-2 South pad and the
five-well 4-2 North pad commenced in the third quarter.
Paramount anticipates nine of these wells will be drilled by
year-end. The drilling of the four-well 1-2 North pad that
also commenced in the third quarter is ongoing and the Company
plans to bring all four wells onstream in the first quarter of
2023. Paramount is bringing additional gas lift compression
onstream in the fourth quarter to support liquids production and
continues to build out infrastructure to debottleneck future
production.
The Company is targeting an increase in plateau production at
Karr to approximately 50,000 Boe/d in the second half of 2023
through the newly expanded infrastructure by drilling 13 (13.0 net)
Montney wells and bringing
onstream 22 (22.0 net) wells. The four wells on the 1-2 North
pad are expected to come onstream early in the first quarter while
the ten wells on the 4-2 North and 4-2 South pads are anticipated
to come onstream in the second quarter. Drilling operations
at the five-well 7-33 South pad and the three-well 6-36 pad are
planned to commence in the first and second quarters,
respectively. All five 7-33 South pad wells are expected to
come onstream late in the second quarter and into the third quarter
while the three 6-36 pad wells are expected to come onstream by the
fourth quarter. Additional planned development activities at
Karr in 2023 that are expected to benefit 2024 production include
the drilling, completion and tie-in of the four-well 7-33 North pad
and the commencement of drilling operations at the three-well 15-24
South pad.
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
|
Q3 2022
|
Q2 2022
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
76.2
|
45.2
|
69
|
Condensate and oil
(Bbl/d)
|
13,816
|
8,965
|
54
|
Other NGLs
(Bbl/d)
|
1,364
|
936
|
46
|
Total
(Boe/d)
|
27,893
|
17,441
|
60
|
%
liquids
|
54 %
|
57 %
|
|
Netback
(1)
|
($ millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
Change in
$ millions (%)
|
Natural gas revenue
(2)
|
48.2
|
6.87
|
28.8
|
6.98
|
67
|
Condensate and oil
revenue
|
140.4
|
110.49
|
110.4
|
135.36
|
27
|
Other NGLs
revenue
|
7.0
|
55.77
|
5.5
|
64.30
|
27
|
Royalty and other
revenue (3)
|
0.1
|
–
|
1.3
|
–
|
NM
|
Petroleum and natural
gas sales
|
195.7
|
76.27
|
146.0
|
91.94
|
34
|
Royalties
|
(22.8)
|
(8.88)
|
(17.1)
|
(10.72)
|
33
|
Operating
expense
|
(28.5)
|
(11.12)
|
(19.9)
|
(12.56)
|
43
|
Transportation
and NGLs processing
|
(10.1)
|
(3.94)
|
(6.9)
|
(4.35)
|
46
|
|
134.3
|
52.33
|
102.1
|
64.31
|
32
|
(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)
Per unit natural gas revenue presented as $/Mcf.
(3)
Second quarter royalty and other revenue includes $1.3 million
related to a business interruption insurance claim.
NM means not
meaningful.
|
Third quarter 2022 sales volumes at Wapiti averaged 27,893 Boe/d
(54% liquids) compared to 17,441 Boe/d (57% liquids) in the second
quarter. The increase is attributable to a combination of new well
production, which has exhibited higher natural gas contribution
with similar liquids volumes compared to previous Wapiti wells, and
improved runtime at the third-party Wapiti natural gas processing
plant.
In September, strong production from the two eight-well pads at
8-22 and 6-32 contributed to Wapiti monthly sales volumes exceeding
the targeted plateau production level of 30,000 Boe/d for the first
time, one quarter ahead of expectations. All-in DCET costs
averaged $7.5 million at the
eight-well 6-32 pad. Initial production results are strong,
averaging gross peak 30-day production per well of 1,722 Boe/d (4.4
MMcf/d of shale gas and 995 Bbl/d of NGLs) with an average CGR of
228 Bbl/MMcf.(1)
Completion operations at the eight-well 16-15 pad have recently
commenced. The Company plans to complete, tie-in and bring on
production six of these wells by the end of 2022 with the remaining
two wells to come onstream in early 2023.
In 2023, the Company plans to maintain production of between
28,000 Boe/d and 30,000 Boe/d at Wapiti by drilling 21 (21.0 net)
wells and bringing on production 13 (13.0 net) wells.
Paramount now plans to commence the drilling of the three-well 1-27
pad in the fourth quarter of 2022 and anticipates all three of
these wells will come onstream in the second quarter of 2023.
Drilling operations at the eight-well 8-15 pad that were originally
planned to commence in the fourth quarter of 2022 are now expected
to commence late in the first quarter of 2023 with all eight wells
anticipated to come onstream in the third quarter. Additional
planned development activities at Wapiti in 2023 that are expected
to benefit 2024 production include the
_________________________________________
|
(1)
|
Production measured at
the wellhead. Natural gas sales volumes are lower by approximately
11% 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.
|
four-well 14-5 East pad that is expected to be drilled in the
third quarter and the six-well 2-18 pad that is anticipated to be
drilled in the fourth quarter.
KAYBOB REGION
Kaybob Region sales volumes averaged 24,021 Boe/d (35% liquids)
in the third quarter of 2022 compared to 21,642 Boe/d (27% liquids)
in the second quarter. The increase was primarily the result
of new Duvernay production from
the four-well Smoky 10-35 pad and the three-well Kaybob North 12-21
pad that came onstream in late July and early August, respectively,
along with a Gething oil well.
Initial production results from the Smoky 10-35 pad wells are
encouraging with average gross peak 30-day production per well of
843 Boe/d (1.6 MMcf/d of shale gas and 584 Bbl/d of NGLs) and an
average CGR of 377 Bbl/MMcf.(1) During
this period, these wells have been choked due to infrastructure
capacity constraints. All-in DCET costs at the 10-35 pad
averaged $9.2 million per well.
Like the new Smoky wells, the three new Kaybob North 12-21 pad
wells have been choked due to infrastructure capacity
constraints. Average gross peak 30-day production per well
was 862 Boe/d (0.8 MMcf/d of shale gas and 732 Bbl/d of NGLs) with
an average CGR of 933 Bbl/MMcf.(2)
All-in DCET costs averaged $11.7
million per well on the 12-21 pad, which came on production
ahead of schedule in the quarter.
The Company is evaluating the optimization of existing
infrastructure in the Kaybob Region to minimize future backout and
the need to choke new wells.
Planned activities at Kaybob in 2023 include the drilling of 15
(14.4 net) wells and the bringing on production of 12 (11.4 net)
wells. At Kaybob North, Paramount plans to commence drilling
operations at the three-well 4-13 South
Duvernay pad and bring all three wells onstream by the end
of the third quarter and drill the five-well 15-7 Duvernay pad commencing in the second quarter
and bring onstream all five wells by the end of the fourth
quarter. At Smoky, the Company plans to commence the drilling
of the three-well 2-35 Duvernay
pad in the third quarter and bring the wells onstream in
2024. A total of four (3.4 net) Montney gas wells are also expected to be
drilled, completed and brought on production over the second and
third quarters.
__________________________________
|
(1)
|
Production measured at
the wellhead. Natural gas sales volumes are lower by approximately
14% and liquids sales volumes are lower by approximately 8% 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.
|
(2)
|
Production measured at
the wellhead. Natural gas sales volumes are lower by approximately
20% and liquids sales volumes are lower by approximately 9% 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.
|
CENTRAL ALBERTA AND OTHER
REGION
Central Alberta and Other
Region sales volumes increased to 7,599 Boe/d (28% liquids) in the
third quarter of 2022 compared to 6,934 Boe/d (21% liquids) in the
second quarter mainly as a result of the Willesden Green Duvernay
acquisition that closed in late August.
The Company has accelerated planned activities in its Willesden
Green Duvernay core area following the two acquisitions that closed
earlier this year. The majority of the capital expenditure
increase in the Company's five-year outlook is the result of this
acceleration. Paramount has allocated approximately
$125 million and $210 million of capital, at the mid-point, to the
development of the Willesden Green Duvernay in 2023 and 2024,
respectively. Facility and associated infrastructure spend is
expected to represent over half of the total capital expenditures
at Willesden Green in these two years.
In light of the Company's large land footprint, Paramount plans
to construct additional capacity at Willesden Green in stages
across multiple facilities, with a total of approximately 100
MMcf/d of raw gas processing and 20,000 Bbl/d of liquids handling
available by 2027.
Two four-well Duvernay pads are
planned in 2023, which will initially double mid-point Willesden
Green production from 3,750 Boe/d (47% liquids) in 2023 to 7,500
Boe/d (59% liquids) in 2024. Production is then expected to
average between 15,000 Boe/d and 20,000 Boe/d (59% liquids) for
each of 2025 and 2026.
The capital program over the next five years at Willesden Green
is anticipated to grow production to approximately 30,000 Boe/d
(58% liquids) by 2027. In addition, Paramount anticipates
beginning to build out the oil window in the eastern portion of its
land base near the end of the five-year plan. Paramount
controls approximately 250,000 net acres of contiguous land at
Willesden Green with over 600 internally high-graded Duvernay drilling locations, which supports a
targeted full field development plateau production of over 50,000
Boe/d that can be sustained for over 20 years
(1)
_________________________
|
(1) See
"Oil and Gas Measures and Definitions" in the Advisories section
for additional information respecting internally estimated drilling
locations
|
HEDGING
The Company's current commodity and foreign exchange contracts
are summarized below:
|
Type
(1)
|
|
Q4
2022
|
Q1
2023
|
Q2
2023
|
H2
2023
|
Average Price (2)
|
Oil
|
|
|
|
|
|
|
|
WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
3,500
|
–
|
–
|
–
|
US$75.79/Bbl
|
WTI Swaps (Sale)
(Bbl/d)
|
Financial
|
|
3,500
|
–
|
–
|
–
|
CAD$91.38/Bbl
|
WTI Collars
(Bbl/d)
|
Financial
|
|
7,000
|
–
|
–
|
–
|
CAD$82.50/Bbl
(Floor)
|
|
|
|
|
|
|
|
CAD$100.47/Bbl
(Ceiling)
|
|
|
|
|
|
|
|
|
Condensate – Basis
(Sale) (Bbl/d)
|
Physical
|
|
–
|
3,146
|
–
|
–
|
WTI –
US$1.17/Bbl
|
Sweet Crude Oil – Basis
(Sale) (Bbl/d)
|
Physical
|
|
–
|
3,146
|
3,112
|
3,078
|
WTI –
US$3.73/Bbl
|
Natural
Gas
|
|
|
|
|
|
|
|
NYMEX Swaps (Sale)
(MMBtu/d)
|
Financial
|
|
3,370
|
–
|
–
|
–
|
US$4.91/MMBtu
|
AECO Fixed Price
(GJ/d)
|
Physical
|
|
26,957
|
–
|
–
|
–
|
CAD$3.78/GJ
|
Dawn
Fixed Price (MMBtu/d)
|
Physical
|
|
6,739
|
–
|
–
|
–
|
US$4.03/MMBtu
|
NYMEX Collars
(MMBtu/d)
|
Financial
|
|
13,261
|
20,000
|
–
|
–
|
US$7.50/MMBtu
(Floor)
|
|
|
|
|
|
|
|
US$12.13/MMBtu
(Ceiling)
|
AECO Collars
(GJ/d)
|
Financial
|
|
13,261
|
20,000
|
–
|
–
|
CAD$7.25/GJ
(Floor)
|
|
|
|
|
|
|
|
CAD$9.60/GJ
(Ceiling)
|
Chicago Index Swap
(Sale) (MMBtu/d)(3)
|
Financial
|
|
3,315
|
5,000
|
–
|
–
|
Daily –
US$0.09/MMBtu
|
Foreign Currency
Exchange
|
|
|
|
|
|
|
|
Forward Sales
(US$MM/Month)
|
Forwards
|
|
$30
|
–
|
–
|
–
|
1.2863 CAD$ /
US$
|
|
Forwards
|
|
–
|
$30
|
–
|
–
|
1.2975 CAD$ /
US$
|
|
Forwards
|
|
–
|
–
|
$20
|
–
|
1.3025 CAD$ /
US$
|
Collars
(US$MM/Month)
|
Financial
|
|
$3.3
|
–
|
–
|
–
|
1.25 CAD$ / US$
(Floor)
|
|
|
|
|
|
|
|
1.30 CAD$ / US$
(Ceiling)
|
Swaps (Sale)
(US$MM/Month)
|
Financial
|
|
$10
|
$10
|
–
|
–
|
1.2888 CAD$ /
US$
|
(1)
Financial, refers to financial commodity
and foreign currency exchange contracts. Physical, refers to
fixed-priced physical and basis differential contracts.
Forwards, refers to foreign currency exchange forwards
contracts.
(2)
Average price is calculated using a
weighted average of notional volumes and prices.
(3)
"Chicago Index" refers to Chicago
Citygate Index pricing. These contracts convert price
exposure of Chicago monthly index to daily index.
|
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 third 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)
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Net
income
|
221.9
|
182.2
|
292.7
|
per share – basic
($/share)
|
1.57
|
1.29
|
2.20
|
per share – diluted
($/share)
|
1.51
|
1.24
|
2.06
|
Cash from operating
activities
|
248.9
|
318.9
|
97.0
|
per share – basic
($/share)
|
1.76
|
2.26
|
0.73
|
per share – diluted
($/share)
|
1.69
|
2.16
|
0.68
|
Adjusted funds
flow
|
334.3
|
258.3
|
148.4
|
per share – basic
($/share)
|
2.37
|
1.83
|
1.12
|
per share – diluted
($/share)
|
2.27
|
1.75
|
1.04
|
Free cash
flow
|
137.5
|
68.3
|
73.8
|
per share – basic
($/share)
|
0.97
|
0.48
|
0.56
|
per share – diluted
($/share)
|
0.93
|
0.46
|
0.52
|
Total
assets
|
4,261.3
|
4,076.2
|
3,882.9
|
Investments in
securities
|
451.3
|
468.8
|
302.9
|
Long-term
debt
|
306.3
|
227.7
|
522.4
|
Net
debt
|
347.0
|
374.0
|
576.8
|
Common shares
outstanding (millions) (2)
|
141.2
|
141.2
|
133.2
|
|
|
|
|
Sales volumes
(3)
|
|
|
|
Natural gas
(MMcf/d)
|
315.9
|
267.2
|
269.7
|
Condensate and
oil (Bbl/d)
|
38,804
|
27,750
|
32,177
|
Other NGLs
(Bbl/d)
|
6,144
|
5,021
|
5,017
|
Total
(Boe/d)
|
97,601
|
77,312
|
82,150
|
%
liquids
|
46 %
|
42 %
|
45 %
|
Grande Prairie
Region (Boe/d)
|
65,981
|
48,736
|
54,586
|
Kaybob Region
(Boe/d)
|
24,021
|
21,642
|
21,054
|
Central Alberta &
Other Region (Boe/d)
|
7,599
|
6,934
|
6,510
|
Total
(Boe/d)
|
97,601
|
77,312
|
82,150
|
|
|
|
|
|
|
|
|
Netback
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
|
Natural gas
revenue
|
185.7
|
6.39
|
164.0
|
6.75
|
96.5
|
3.89
|
|
Condensate and
oil revenue
|
401.8
|
112.56
|
340.0
|
134.65
|
249.9
|
84.42
|
|
Other NGLs
revenue
|
28.9
|
51.20
|
28.7
|
62.80
|
21.7
|
47.05
|
|
Royalty and
other revenue
|
2.5
|
─
|
3.5
|
─
|
1.1
|
─
|
|
Petroleum and
natural gas sales
|
618.9
|
68.92
|
536.2
|
76.22
|
369.2
|
48.86
|
|
Royalties
|
(89.4)
|
(9.96)
|
(85.2)
|
(12.11)
|
(30.9)
|
(4.09)
|
|
Operating
expense
|
(110.0)
|
(12.25)
|
(88.7)
|
(12.61)
|
(83.3)
|
(11.02)
|
|
Transportation and NGLs
processing
|
(34.4)
|
(3.83)
|
(30.8)
|
(4.37)
|
(30.3)
|
(4.01)
|
|
Sales of commodities
purchased (5)
|
77.9
|
8.67
|
42.7
|
6.06
|
31.3
|
4.14
|
|
Commodities
purchased (5)
|
(76.4)
|
(8.51)
|
(41.1)
|
(5.84)
|
(31.4)
|
(4.16)
|
|
Netback
|
386.6
|
43.04
|
333.1
|
47.35
|
224.6
|
29.72
|
|
Risk management
contract settlements
|
(44.4)
|
(4.94)
|
(61.9)
|
(8.79)
|
(59.0)
|
(7.81)
|
|
Netback including
risk management contract settlements
|
342.2
|
38.10
|
271.2
|
38.56
|
165.6
|
21.91
|
|
|
|
|
|
Capital
expenditures
|
|
|
|
Grande Prairie
Region
|
133.5
|
107.2
|
53.1
|
Kaybob
Region
|
30.8
|
57.9
|
1.7
|
Central Alberta &
Other Region
|
0.2
|
0.8
|
9.7
|
Fox Drilling and
Cavalier Energy
|
10.8
|
3.7
|
1.9
|
Corporate
|
9.0
|
14.5
|
(0.3)
|
Total
|
184.3
|
184.1
|
66.1
|
|
|
|
|
Asset retirement
obligations settled
|
10.2
|
4.0
|
6.9
|
(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: Q3 2022: 0.8 million; Q2 2022: 0.8
million; Q3 2021: 1.5 million.
|
(3)
|
Refer to the Product
Type Information section of this document for a complete breakdown
of sales volumes for applicable periods by specific product
type.
|
(4)
|
Natural gas revenue
presented as $/Mcf.
|
(5)
|
Sales of commodities
purchased and commodities purchased are treated as corporate items
and not allocated to individual regions or
properties.
|
|
|
PRODUCT TYPE INFORMATION
This press release includes references to sales volumes of
"natural gas", "condensate and oil", "NGLs", "Other NGLs" and
"liquids". "Natural gas" refers to conventional natural gas
and shale gas combined. "Condensate and oil" refers to
condensate, light and medium crude oil and tight oil
combined. "NGLs" refers to condensate and Other NGLs
combined. "Other NGLs" refers to ethane, propane and
butane. "Liquids" refers to condensate and oil and
Other NGLs combined. Below is a complete breakdown of sales
volumes for applicable periods by the specific product types of
shale gas, conventional natural gas, NGLs, tight oil and light and
medium crude oil. Numbers may not add due to rounding.
|
Total
|
Grande Prairie
Region
|
Kaybob
Region
|
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Shale gas
(MMcf/d)
|
253.8
|
203.7
|
207.1
|
188.2
|
138.8
|
145.8
|
38.5
|
37.9
|
36.9
|
Conventional natural
gas (MMcf/d)
|
62.1
|
63.5
|
62.6
|
1.4
|
1.0
|
2.2
|
54.8
|
56.7
|
54.4
|
Natural gas
(MMcf/d)
|
315.9
|
267.2
|
269.7
|
189.6
|
139.8
|
148.0
|
93.3
|
94.6
|
91.3
|
Condensate
(Bbl/d)
|
35,747
|
25,374
|
29,670
|
30,610
|
22,511
|
26,639
|
4,157
|
2,092
|
2,072
|
Other NGLs
(Bbl/d)
|
6,144
|
5,021
|
5,017
|
3,758
|
2,914
|
3,274
|
1,666
|
1,585
|
1,415
|
NGLs
(Bbl/d)
|
41,891
|
30,395
|
34,687
|
34,368
|
25,425
|
29,913
|
5,823
|
3,677
|
3,487
|
Tight oil
(Bbl/d)
|
449
|
402
|
475
|
-
|
-
|
-
|
208
|
253
|
368
|
Light and medium crude
oil (Bbl/d)
|
2,608
|
1,974
|
2,032
|
5
|
5
|
9
|
2,434
|
1,946
|
1,979
|
Crude oil
(Bbl/d)
|
3,057
|
2,376
|
2,507
|
5
|
5
|
9
|
2,642
|
2,199
|
2,347
|
Total
(Boe/d)
|
97,601
|
77,312
|
82,150
|
65,981
|
48,736
|
54,586
|
24,021
|
21,642
|
21,054
|
|
Central Alberta and
Other
Region
|
Karr
|
Wapiti
|
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Q3
2022
|
Q2
2022
|
Q3
2021
|
Shale gas
(MMcf/d)
|
27.1
|
27.0
|
24.4
|
112.9
|
94.2
|
113.0
|
75.3
|
44.6
|
32.8
|
Conventional natural
gas (MMcf/d)
|
5.9
|
5.8
|
6.0
|
0.5
|
0.4
|
1.4
|
0.9
|
0.6
|
0.8
|
Natural gas
(MMcf/d)
|
33.0
|
32.8
|
30.4
|
113.4
|
94.6
|
114.4
|
76.2
|
45.2
|
33.6
|
Condensate
(Bbl/d)
|
980
|
771
|
959
|
16,799
|
13,551
|
18,328
|
13,811
|
8,960
|
8,311
|
Other NGLs
(Bbl/d)
|
720
|
522
|
328
|
2,394
|
1,978
|
2,477
|
1,364
|
936
|
797
|
NGLs
(Bbl/d)
|
1,700
|
1,293
|
1,287
|
19,193
|
15,529
|
20,805
|
15,175
|
9,896
|
9,108
|
Tight oil
(Bbl/d)
|
241
|
149
|
107
|
-
|
-
|
-
|
-
|
-
|
-
|
Light and medium crude
oil (Bbl/d)
|
169
|
23
|
44
|
-
|
-
|
-
|
5
|
5
|
9
|
Crude oil
(Bbl/d)
|
410
|
172
|
151
|
-
|
-
|
-
|
5
|
5
|
9
|
Total
(Boe/d)
|
7,599
|
6,934
|
6,510
|
38,088
|
31,295
|
39,878
|
27,893
|
17,441
|
14,708
|
The Company forecasts that fourth quarter 2022 sales volumes will
average between 103,000 Boe/d and 107,000 Boe/d (55% shale gas and
conventional natural gas combined, 39% light and medium crude oil,
tight oil and condensate combined and 6% other NGLs).
The Company forecasts that 2022 annual sales volumes will
average between 90,000 Boe/d and 91,000 Boe/d (55% shale gas and
conventional natural gas combined, 38% light and medium crude oil,
tight oil and condensate combined and 7% other NGLs).
The Company forecasts that 2023 annual sales volumes will
average between 105,000 Boe/d and 110,000 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 2023 sales volumes are expected to average between 101,000
Boe/d and 106,000 Boe/d (55% shale gas and conventional natural gas
combined, 39% light and medium crude oil, tight oil and condensate
combined and 6% other NGLs). Second half 2023 sales volumes are
expected to average between 109,000 Boe/d and 114,000 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).
SPECIFIED FINANCIAL MEASURES
Non-GAAP Financial Measures
Netback and netback including risk management contract
settlements are non-GAAP financial measures. These measures
are not standardized measures under IFRS and might not be
comparable to similar financial measures presented by other
issuers. These measures should not be considered in isolation
or construed as alternatives to their most directly comparable
measure disclosed in the Company's primary financial statements or
other measures of financial performance calculated in accordance
with IFRS.
Netback equals petroleum and natural gas sales (the most
directly comparable measure disclosed in the Company's primary
financial statements) plus sales of commodities purchased less
royalties, operating expense, transportation and NGLs processing
expense and commodities purchased. Sales of commodities
purchased and commodities purchased are treated as Corporate items
and not are allocated to individual regions or properties.
Netback is used by investors and Management to compare the
performance of the Company's producing assets between periods.
Netback including risk management contract settlements equals
netback after including (or deducting) risk management contract
settlements received (paid). Netback including risk management
contract settlements is used by investors and Management to assess
the performance of the producing assets after incorporating
Management's risk management strategies.
Refer to the table under the heading "Financial and Operating
Results" in this press release for the calculation of netback and
netback including risk management contract settlements for the
three months ended September 30,
2022, June 30, 2022 and
September 30, 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 and nine months
ended September 30, 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 September 30, 2022
and 2021 and (iii) a calculation of net debt as at
September 30, 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) petroleum and natural gas sales, revenue,
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.
Petroleum and natural gas sales, revenue, 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 petroleum and natural
gas sales, revenue, royalties, operating expenses, transportation
and NGLs processing expense, sales of commodities purchased or
commodities purchased, as applicable, over the referenced period by
the aggregate units (Bbl, Mcf or Boe) produced 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 Company's free cash flow priorities, including its plans to
direct the majority of its near-term free cash flows to further
reduce credit facility drawings;
- planned capital expenditures in 2022 and 2023 and the
allocation thereof;
- forecast sales volumes for 2022 and 2023 and certain periods
therein;
- forecast free cash flow in 2022 and 2023;
- planned abandonment and reclamation expenditures in 2022 and
2023;
- preliminary anticipated capital expenditures in 2024 and the
allocation thereof and the resulting expected 2024 average sales
volumes and free cash flow;
- the Company's five-year outlook for capital spending,
cumulative free cash flow and production;
- the statement that Paramount does not forecast cash tax in its
five-year outlook until 2026;
- expected or targeted plateau production rates at Karr and
Wapiti and the ability to achieve or maintain such rates;
- expected production during certain periods at Willesden Green
and the expectation that the capital program over the next five
years at Willesden Green will grow production to approximately
30,000 Boe/d (58% liquids) by 2027;
- internally estimated drilling locations and targeted plateau
production volumes at Willesden Green and the time period over
which targeted plateau production volumes may be maintained;
- planned exploration, development and production activities,
including the expected timing of drilling, completing and bringing
new wells on production and the expected timing of completion, cost
and capacity of planned facilities and infrastructure; and
- the potential payment of future dividends.
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;
- the impact of the Russian invasion of the Ukraine;
- royalty rates, taxes and capital, operating, general &
administrative and other costs;
- foreign currency exchange rates, interest rates and the rate
and impacts of inflation;
- general business, economic and market conditions;
- the performance of wells and facilities;
- the availability to Paramount of the required capital to fund
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 expected and
acceptable costs 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:
- the risks set out in the Company's Management's Discussion and
Analysis for the three and nine months ended September 30, 2022;
- fluctuations in commodity prices;
- changes in capital spending plans and planned exploration and
development activities;
- the potential for changes to preliminary anticipated 2024
capital expenditures prior to finalization and changes to the
resulting expected 2024 average sales volumes and free cash
flow;
- the potential for changes to the Company's five-year outlook
for capital spending, production 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
production, future revenue, free cash flow, 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 expected and acceptable costs,
including the potential effects of inflation and supply chain
disruptions;
- potential disruptions, delays or unexpected technical or other
difficulties in designing, developing, expanding or operating new,
expanded or existing facilities (including third-party
facilities);
- 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 to fund, or to otherwise finance, 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 Indigenous 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 any future dividends or the amount or
timing of any such dividends.
With respect to the statement that Paramount does not forecast
cash tax in its five-year outlook until 2026, taxable income varies
depending on total income and expenses and estimates as to the
timing of paying cash tax are sensitive to assumptions regarding
commodity prices, production, cash from operating activities,
capital spending levels, the allocation of free cash flow and
acquisition and disposition transactions. Changes in these factors
could result in the Company paying income taxes earlier or later
than expected.
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, 2023 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 nine months ended September
30, 2022, the value ratio between crude oil and natural gas
was approximately 23:1. 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, the
availability of facilities, 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.