CALGARY, AB, Aug. 4, 2021 /CNW/ -
HIGHLIGHTS
- Sales volumes averaged 79,995 Boe/d (43 percent liquids) in the
second quarter of 2021, ahead of the Company's guidance of 77,000
Boe/d to 78,000 Boe/d (42 percent liquids), driven by continued
outperformance at Karr.(1)
-
- Sales volumes at Karr averaged 38,679 Boe/d (54 percent
liquids) in the second quarter, ahead of expectations and
approximately 5,500 Boe/d higher than first quarter production,
despite a seven-day scheduled curtailment at the third-party 6-18
facility in May. The six-well 3-10 pad continues to outperform and
achieved payout in four months after coming onstream in
February.
- Sales volumes at Wapiti averaged 10,604 Boe/d (59 percent
liquids) in the second quarter, in line with expectations. The
Company expects Wapiti sales volumes to increase in the second half
of 2021 as new production is brought onstream.
- Operating costs averaged $11.23/Boe in the second quarter of 2021, down
from $11.63/Boe in the first quarter.
Paramount achieved another important milestone at Karr, with second
quarter operating costs coming in at $9.40/Boe, beating the Company's target of
$10.00/Boe at plateau production of
approximately 40,000 Boe/d.
- Cash from operating activities was $112.1 million in the second quarter. Adjusted
funds flow was $86.0 million or
$0.65 per share. Free cash flow was
($0.7) million. Full year 2021 free
cash flow is now forecast to be $45
million higher at approximately $185
million resulting in anticipated year-end net debt to
adjusted funds flow of approximately 1.0x, reflecting stronger
commodity prices and year-to-date
performance.(2)
- Second quarter capital spending, which was focused on drilling
and completion activities at Karr, Wapiti and the Willesden Green
Duvernay, totaled $83.5 million.
Strong execution resulted in faster drilling and completion times
on certain projects, translating into lower than budgeted costs and
allowing the Company to complete certain activities in the second
quarter that were initially planned for the third quarter. The
Company remains on track for 2021 annual capital spending to be
between $265 million and $285 million.
-
- Preliminary all-in lease construction, drilling, completion,
equip and tie-in (collectively "DCET") costs at the five well Karr
7-18 pad that was brought on production in late July 2021 averaged a pacesetting $6.0 million per well, approximately 11 percent
lower than average DCET costs of the last two pads at Karr.
- DCET costs for the seven well Wapiti 6-4 pad averaged a
pacesetting $6.9 million per well,
nine percent lower than average Wapiti DCET costs in 2020.
- Paramount's use of the drilling rigs and crews of its
wholly-owned Fox Drilling subsidiary has resulted in consistency of
execution and efficiencies that have contributed to well cost
reductions at Karr and Wapiti.
- The Company finished drilling the two well 4-7 pad in the
Willesden Green Duvernay during the second quarter. The wells were
completed in July and are expected to be brought on production in
late August. One of these wells was drilled to a lateral length of
approximately 4,000 meters and a total measured depth of
approximately 7,400 meters, representing the longest horizontal
well ever drilled by the Company.
- Abandonment and reclamation expenditures in the second quarter
totaled $3.2 million, net of
$0.8 million in funding under the
Alberta Site Rehabilitation Program.
- The Company's strong financial outlook and operating results
enabled it to implement a monthly dividend of $0.02 per class A common share ("Common Share")
and a normal course issuer bid ("NCIB") under which up to 7.3
million Common Shares may be purchased for cancellation. The
inaugural cash dividend was paid on July 30,
2021.
- The Company's senior secured revolving bank credit facility
(the "Paramount Facility") was amended in the second quarter to
extend the maturity date to June 2,
2024 and change its size to $900
million, with an accordion feature providing flexibility to
increase the size to $1.0
billion.
- In the second quarter, Paramount received $67 million cash in settlement of its previously
disclosed dissent proceedings respecting Strath Resources Ltd. and
for the sale of its remaining securities in Strathcona Resources
Ltd.
- The Company closed the sale of its non-operated Birch assets in
July for gross proceeds of approximately $88
million before customary closing adjustments.
- Subsequent to quarter-end, Paramount entered into several
additional hedges to further protect its free cash flow profile.
See below under "Hedging".
_________________________
|
|
(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 combined. 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, tight oil and light and
medium crude oil. See also "Oil and Gas Measures and Definitions"
in the Advisories section.
|
(2)
|
"Adjusted funds
flow", "free cash flow" and "net debt to adjusted funds flow" are
Non-GAAP financial measures. See "Non-GAAP Financial Measures" in
the Advisories section.
|
GUIDANCE
Paramount is reaffirming its 2021 average sales volumes guidance
of between 80,000 Boe/d and 82,000 Boe/d (44
percent liquids). Second half 2021 sales volumes guidance
remains unchanged at between 80,000 Boe/d and 84,000 Boe/d (45
percent liquids).
The Company continues to expect 2021 annual capital spending to
be between $265 million and
$285 million, excluding land
acquisitions and abandonment and reclamation activities.
Paramount is updating its forecast of 2021 free cash flow from
approximately $140 million to
approximately $185 million to reflect
year-to-date actual results and revised commodity price and other
assumptions for the second half of 2021. This forecast is
based on the following assumptions for 2021: (i) the midpoint of
forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs,
(iii) realized pricing of $44.00/Boe
(US$64.05/Bbl WTI, US$3.41/MMBtu NYMEX, $3.37/GJ AECO), (iv) royalties of $3.90/Boe, (v) operating costs of $11.20/Boe and (vi) transportation and processing
costs of $4.00/Boe.
Approximately 53 percent of forecast midpoint production is
hedged over the second half of 2021. After taking such hedging into
account, 2021 forecast free cash flow would still be approximately
$140 million at an average WTI oil
price of US$50.00/Bbl over the second
half of the year and would rise to $210
million at an average WTI oil price of US$75.00/Bbl over the second half of the
year.
The Company currently prioritizes the allocation of free cash
flow to: (i) achieving a targeted range of net debt to adjusted
funds flow of between 1.0x and 2.0x; (ii) shareholder returns;
and (iii) incremental growth. Free cash flow in 2021 is
expected to be directed towards debt reduction and the payment of
dividends, with the Company maintaining the flexibility to make
purchases of Common Shares under the NCIB. Year-end net debt
to adjusted funds flow is now anticipated to be approximately 1.0x
based on forecast 2021 free cash flow and a monthly dividend of
$0.02 per Common Share.
Paramount's previously announced preliminary 2022 capital
spending and sales volumes guidance remains unchanged. The
Company continues to anticipate 2022 spending, excluding land
acquisitions and abandonment and reclamation activities, to range
between $325 million and $385 million. A capital program in
this range would be expected to result in 2022 annual sales volumes
of between 84,000 Boe/d and 88,000 Boe/d (45 percent liquids) and
free cash flow of approximately $320
million, based on the following updated assumptions for
2022: (i) the midpoint of forecast capital spending and production,
(ii) $30 million in abandonment and
reclamation costs, (iii) realized pricing of $43.20/Boe (US$62.18/Bbl WTI, US$3.30/MMBtu NYMEX, $3.10/GJ AECO), (iv) royalties of $4.15/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing
costs of $3.85/Boe. If all free
cash flow was directed towards debt reduction, year-end 2022 net
debt to adjusted funds flow would be less than 0.5x.
AUGUST DIVIDEND
The Board of Directors has declared a cash dividend of
$0.02 per Common Share that will be
payable on August 31, 2021 to
shareholders of record on August 16,
2021. The dividend will be designated as an "eligible
dividend" for Canadian income tax purposes.
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Grande Prairie Region sales volumes and netbacks are summarized
below:(1)
|
Q2
2021
|
Q1 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
134.3
|
122.6
|
10
|
Condensate and oil
(Bbl/d)
|
24,090
|
23,974
|
-
|
Other NGLs
(Bbl/d)
|
2,874
|
2,984
|
(4)
|
Total
(Boe/d)
|
49,345
|
47,385
|
4
|
%
liquids
|
55%
|
57%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in
$
millions
|
Petroleum and natural
gas sales
|
217.7
|
48.47
|
194.0
|
45.50
|
12
|
Royalties
|
(15.3)
|
(3.40)
|
(11.6)
|
(2.72)
|
32
|
Operating
expense
|
(48.8)
|
(10.88)
|
(49.0)
|
(11.49)
|
-
|
Transportation and
NGLs processing
|
(21.4)
|
(4.76)
|
(20.0)
|
(4.69)
|
7
|
|
132.2
|
29.43
|
113.4
|
26.60
|
17
|
|
(1)
|
"Netback" is a
Non-GAAP financial measure. See "Non-GAAP Financial Measures" in
the Advisories section.
|
KARR AREA
Karr sales volumes and netbacks are summarized below:
|
Q2 2021
|
Q1 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
107.6
|
90.2
|
19
|
Condensate and oil
(Bbl/d)
|
18,458
|
16,095
|
15
|
Other NGLs
(Bbl/d)
|
2,281
|
2,108
|
8
|
Total
(Boe/d)
|
38,679
|
33,230
|
16
|
%
liquids
|
54%
|
55%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in
$
millions
|
Petroleum and natural
gas sales
|
168.0
|
47.72
|
132.5
|
44.31
|
27
|
Royalties
|
(13.1)
|
(3.72)
|
(8.6)
|
(2.89)
|
52
|
Operating
expense
|
(33.1)
|
(9.40)
|
(31.9)
|
(10.67)
|
4
|
Transportation and
NGLs processing
|
(16.0)
|
(4.52)
|
(14.0)
|
(4.68)
|
14
|
|
105.8
|
30.08
|
78.0
|
26.07
|
36
|
Second quarter sales volumes at Karr averaged 38,679 Boe/d (54
percent liquids) compared to 33,230 Boe/d (55 percent liquids) in
the first quarter. The increase in sales volumes was driven
by strong performance from the six well 3-10 pad that was brought
onstream in February and continues to outperform internal type well
projections as well as production contributions from the three well
4-28 pad that was brought onstream in late April. Sales
volumes also benefitted from additional gas lift compression
installed in the first quarter that became fully operational in
April. Combined, these more than offset the impact of
scheduled curtailments at the third-party Karr 6-18 facility
related to inlet separation and liquids handling optimization that
reduced sales volumes by approximately 50 percent for seven days in
May.
The 4-28 pad has performed in line with internal type well
projections, averaging gross peak 30-day production per well of
1,295 Boe/d (3.4 MMcf/d of shale gas and 728 Bbl/d of NGLs) with an
average CGR of 214
Bbl/MMcf.(1)
Paramount continues to focus on driving DCET costs lower while
maintaining well performance and has realized cost improvements
relative to previous pacesetting results. Preliminary all-in
DCET costs at the five well Karr 7-18 pad, which was brought on
production in late July 2021,
averaged a pacesetting $6.0 million
per well. This represents an approximate 11 percent reduction
relative to average DCET costs of the last two pads at Karr.
Continued outperformance from the 3-10 pad coupled with strong
commodity prices has resulted in all wells on the 3-10 pad paying
out in June, four months after coming onstream.
Drilling operations on the five well 5-16 East pad were
completed in the second quarter. The average spud to rig
release time for this pad came in at just under 24 days, 12 percent
faster than on the 5-16 West pad drilled last year from the same
surface location. The Company plans to complete the pad late
in the third quarter and equip and tie-in the wells in the fourth
quarter. The Company recently started drilling operations on the
ten well 16-17 pad and expects that seven of the ten wells will be
drilled by year-end.
Karr unit operating costs trended lower in the second quarter as
a result of higher production volumes combined with a continued
focus on capturing efficiencies and streamlining operations.
Paramount achieved operating costs at Karr of $9.40/Boe in the second quarter of 2021, lower
than targeted operating costs of $10.00/Boe at plateau production of approximately
40,000 Boe/d.
Royalties at Karr increased in the second quarter of 2021
compared to the first quarter as a result of higher volumes and
prices as well as a number of wells having fully utilized their new
well royalty incentives.
_____________________________
|
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 7% and liquids sales volumes are lower by
approximately 6% due to shrinkage. Excludes days when the wells did
not produce. The production rates and volumes stated are over a
short period of time and, therefore, are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells. CGR means condensate to gas ratio and is
calculated by dividing raw wellhead liquids volumes by raw wellhead
natural gas volumes. See Oil and Gas Measures and Definitions in
the Advisories section.
|
WAPITI AREA
Wapiti sales volumes and netbacks are summarized
below:
|
Q2 2021
|
Q1 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
26.4
|
32.1
|
(18)
|
Condensate and oil
(Bbl/d)
|
5,629
|
7,884
|
(29)
|
Other NGLs
(Bbl/d)
|
582
|
867
|
(33)
|
Total
(Boe/d)
|
10,604
|
14,107
|
(25)
|
%
liquids
|
59%
|
62%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
49.6
|
51.41
|
61.4
|
48.42
|
(19)
|
Royalties
|
(2.1)
|
(2.24)
|
(2.9)
|
(2.32)
|
(30)
|
Operating
expense
|
(15.4)
|
(16.00)
|
(16.8)
|
(13.25)
|
(8)
|
Transportation and
NGLs processing
|
(5.5)
|
(5.65)
|
(6.0)
|
(4.73)
|
(9)
|
|
26.6
|
27.52
|
35.7
|
28.12
|
(26)
|
Second quarter sales volumes at Wapiti averaged 10,604 Boe/d (59
percent liquids) compared to 14,107 Boe/d (62 percent liquids) in
the first quarter due to natural declines, the temporary shut-in of
certain offsetting wells due to completion activities at the 6-4
pad and production curtailments at the third-party Wapiti natural
gas processing facility caused by high ambient temperatures in
June.
Production in July 2021 was
impacted by the previously disclosed scheduled ten-day outage at
the third-party Wapiti natural gas processing facility. This
outage, which was undertaken to permanently address the source of
the unscheduled outage that occurred at the facility in the third
quarter of 2020, was completed as planned and the Company has
restored production.
The seven well 6-4 pad was brought onstream in early July with
encouraging initial results. DCET costs averaged a
pacesetting $6.9 million per well,
representing a nine percent reduction compared to average Wapiti
DCET costs in 2020.
The Company has commenced drilling the seven well 9-22 pad,
which is scheduled to be brought onstream in December 2021 along with the previously drilled
and completed 10-22 well. The Company has also commenced the
installation of infrastructure that will be operational later in
2021 and will accommodate production growth at Wapiti.
KAYBOB REGION
Kaybob Region sales volumes averaged 22,688 Boe/d (28 percent
liquids) in the second quarter of 2021 compared to 24,938 Boe/d (28
percent liquids) in the first quarter. The decrease in
production was due to natural declines and non-core asset
dispositions completed in the first quarter.
Paramount holds material positions in the Duvernay and Montney resource plays in the Kaybob Region
that will compete for capital in the medium term. In 2022,
the Company has preliminary plans to drill, complete and tie-in a
four well Duvernay pad at Kaybob
Smoky and a three well Duvernay
pad at Kaybob North on an existing pad where one of the three wells
was previously drilled in 2019. The Company expects to
realize capital cost efficiencies in its Kaybob Duvernay plays,
similar to the gains achieved over the past 18 months at Karr and
Wapiti, as it commences pad development and captures economies of
scale. These lower costs are expected to materially improve
Duvernay economics.
CENTRAL ALBERTA AND OTHER
REGION
Central Alberta and Other
Region sales volumes averaged 7,962 Boe/d (13 percent liquids) in
the second quarter of 2021 compared to 8,217 Boe/d (14 percent
liquids) in the first quarter.
The Company holds a material, contiguous Duvernay position at Willesden Green and
continues to actively evaluate longer-term full field development
plans for this asset. Drilling, completion and equipping of a
two well, liquids rich Duvernay
pad in the Willesden Green area was recently completed and
Paramount plans to tie-in and bring both wells on production in
late August.
HEDGING
Subsequent to June 30, 2021, the
Company entered into the following oil and natural gas hedges:
- Oil:
October 2021 – March
2022 6,000
Bbl/d at $87.18/Bbl (WTI)
- Natural Gas:
October 2021 – March
2022 20,000
MMBtu/d at US$4.10/MMBtu (NYMEX)
October 2021 – March
2022 20,000 GJ/d at
$4.01/GJ (AECO)
Further details of Paramount's commodity hedging position are
provided in its second quarter 2021 Management's Discussion and
Analysis and Consolidated Financial Statements.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused
Canadian energy company that explores for and develops both
conventional and unconventional petroleum and natural gas reserves
and resources, including longer-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are located in
Alberta and British Columbia. Paramount's class A common
shares are listed on the Toronto Stock Exchange under the symbol
"POU".
Paramount's second quarter 2021 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at:
https://mma.prnewswire.com/media/1587964/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_Second.pdf
A summary of historical financial and operating results is also
available on Paramount's website at
http://www.paramountres.com/investor-relations/financial-reports#2021.
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at
www.sedar.com.
FINANCIAL AND
OPERATING RESULTS (1)
($ millions,
except as noted)
|
|
|
|
Q2
2021
|
Q1
2021
|
Net
loss
|
|
|
|
|
(74.3)
|
(82.5)
|
per share – basic
and diluted ($/share)
|
|
|
|
|
(0.56)
|
(0.62)
|
Cash from
operating activities
|
|
|
|
|
112.1
|
81.3
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.84
|
0.61
|
Adjusted funds
flow
|
|
|
|
|
86.0
|
90.9
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.65
|
0.69
|
Total
assets
|
|
|
|
|
3,655.6
|
3,583.1
|
Long-term
debt
|
|
|
|
|
608.4
|
712.7
|
Net
debt
|
|
|
|
|
724.5
|
761.7
|
Common shares
outstanding (thousands) (2)
|
|
|
|
|
133,314
|
132,754
|
Sales
volumes
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
|
273.1
|
273.1
|
Condensate and oil
(Bbl/d)
|
|
|
29,543
|
29,854
|
Other NGLs (Bbl/d)
(3)
|
|
|
4,938
|
5,170
|
Total
(Boe/d)
|
|
|
79,995
|
80,540
|
%
liquids
|
|
|
43%
|
43%
|
Grande Prairie Region
(Boe/d)
|
|
|
49,345
|
47,385
|
Kaybob Region
(Boe/d)
|
|
|
22,688
|
24,938
|
Central Alberta and
Other Region (Boe/d)
|
|
|
7,962
|
8,217
|
Total
(Boe/d)
|
|
|
79,995
|
80,540
|
Netback
|
|
|
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
Natural gas
revenue
|
|
|
|
|
74.8
|
3.01
|
77.3
|
3.14
|
Condensate and
oil revenue
|
|
|
|
|
209.6
|
77.96
|
185.9
|
69.20
|
Other NGLs
revenue (3)
|
|
|
|
|
14.4
|
32.11
|
15.0
|
32.29
|
Royalty and
other revenue
|
|
|
|
|
0.9
|
─
|
1.7
|
─
|
Petroleum and
natural gas sales
|
|
|
|
|
299.7
|
41.17
|
279.9
|
38.61
|
Royalties
|
|
|
|
|
(24.9)
|
(3.43)
|
(18.6)
|
(2.57)
|
Operating
expense
|
|
|
|
|
(81.8)
|
(11.23)
|
(84.3)
|
(11.63)
|
Transportation
and NGLs processing (5)
|
|
|
|
|
(30.3)
|
(4.16)
|
(27.9)
|
(3.84)
|
Netback
|
|
|
|
|
162.7
|
22.35
|
149.1
|
20.57
|
Financial commodity
contract settlements
|
|
|
|
|
(54.1)
|
(7.44)
|
(32.7)
|
(4.51)
|
Netback including
financial commodity contract settlements
|
108.6
|
14.91
|
116.4
|
16.06
|
Total Capital Expenditures
|
|
|
|
|
Grande Prairie
Region
|
|
|
66.5
|
51.3
|
Kaybob
Region
|
|
|
3.9
|
5.0
|
Central Alberta and
Other Region
|
|
|
11.8
|
1.2
|
Corporate
(6)
|
|
|
1.2
|
1.8
|
Land
acquisitions
|
|
|
0.1
|
─
|
Total capital
expenditures
|
|
|
83.5
|
59.3
|
Asset retirement obligation settlements
|
|
|
3.2
|
8.4
|
|
|
(1)
|
Readers are referred
to the advisories concerning Non-GAAP Financial Measures and Oil
and Gas Measures and Definitions in the Advisories section of this
document. This table contains the following Non-GAAP financial
measures: Adjusted funds flow, Net debt, Netback and Total
capital expenditures. Readers are referred to the Product
Type Information section of this document for a complete breakdown
of sales volumes for applicable periods by the specific product
types.
|
(2)
|
Common shares are
presented net of shares held in trust under the Company's
restricted share unit plan (000's of common shares): Q2 2021: 1,538
and Q1 2021: 1,914.
|
(3)
|
Other NGLs means
ethane, propane and butane.
|
(4)
|
Natural gas revenue
presented as $/Mcf.
|
(5)
|
Includes downstream
transportation costs and NGLs fractionation costs.
|
(6)
|
Includes transfers
between regions.
|
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 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
|
Central Alberta
and
Other Region
|
|
Q2
2021
|
Q1
2021
|
Q2
2021
|
Q1
2021
|
Q2
2021
|
Q1
2021
|
Q2
2021
|
Q1
2021
|
Shale gas
(MMcf/d)
|
205.8
|
197.8
|
132.2
|
120.6
|
39.3
|
42.1
|
34.3
|
35.1
|
Conventional natural
gas (MMcf/d)
|
67.3
|
75.3
|
2.1
|
2.0
|
58.0
|
65.8
|
7.2
|
7.5
|
Natural gas
(MMcf/d)
|
273.1
|
273.1
|
134.3
|
122.6
|
97.3
|
107.9
|
41.5
|
42.6
|
Condensate
(Bbl/d)
|
26,784
|
27,017
|
24,086
|
23,974
|
2,319
|
2,611
|
379
|
433
|
Other NGLs
(Bbl/d)
|
4,938
|
5,170
|
2,874
|
2,984
|
1,569
|
1,677
|
495
|
509
|
NGLs
(Bbl/d)
|
31,722
|
32,187
|
26,960
|
26,958
|
3,888
|
4,288
|
874
|
942
|
Tight oil
(Bbl/d)
|
494
|
479
|
–
|
–
|
354
|
342
|
140
|
136
|
Light and medium
crude oil (Bbl/d)
|
2,265
|
2,358
|
4
|
–
|
2,224
|
2,321
|
37
|
37
|
Crude oil
(Bbl/d)
|
2,759
|
2,837
|
4
|
–
|
2,578
|
2,663
|
177
|
173
|
Total
(Boe/d)
|
79,995
|
80,540
|
49,345
|
47,385
|
22,688
|
24,938
|
7,962
|
8,217
|
|
Karr
|
Wapiti
|
|
Q2 2021
|
Q1
2021
|
Q2
2021
|
Q1
2021
|
Shale gas
(MMcf/d)
|
106.3
|
89.1
|
25.9
|
31.5
|
Conventional natural
gas (MMcf/d)
|
1.3
|
1.1
|
0.5
|
0.6
|
Natural gas
(MMcf/d)
|
107.6
|
90.2
|
26.4
|
32.1
|
NGLs
(Bbl/d)
|
20,739
|
18,203
|
6,211
|
8,751
|
Total
(Boe/d)
|
38,679
|
33,230
|
10,604
|
14,107
|
The Company forecasts that 2021 sales volumes will average
between 80,000 Boe/d and 82,000 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 2021 sales volumes are expected to average between 80,000
Boe/d and 84,000 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).
ADVISORIES
Forward-looking Information
Certain statements in this press release constitute
forward-looking information under applicable securities
legislation. Forward-looking information typically contains
statements with words such as "anticipate", "believe", "estimate",
"will", "expect", "plan", "schedule", "intend", "propose", or
similar words suggesting future outcomes or an outlook.
Forward-looking information in this press release includes, but is
not limited to:
- the expectation that sales volumes at Wapiti will increase in
the second half of 2021;
- preliminary estimated drilling, completion and equipping
costs;
- forecast free cash flow in 2021;
- forecast 2021 year-end net debt to annual adjusted funds
flow;
- planned capital expenditures in 2021;
- forecast sales volumes for 2021 and certain periods
therein;
- the Company's expectation that 2021 free cash flow will be
directed towards debt reduction and the payment of dividends;
- preliminary anticipated capital expenditures in 2022 and the
resulting expected 2022 average sales volumes, free cash flow and
year-end net debt to adjusted funds flow;
- the payment of future dividends under the Company's monthly
dividend program;
- planned exploration, development and production activities,
including the expected timing of completing and bringing new wells
on production; and
- the expectation that the Company will realize capital cost
efficiencies in its Kaybob Duvernay plays and the expectation that
lower costs will materially improve Duvernay economics.
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 and the potential impact of the
COVID-19 pandemic thereon;
- the likely impact of the COVID-19 pandemic on operations;
- the ability to realize expected cost savings;
- royalty rates, taxes and capital, operating, processing,
transportation, general & administrative and other costs;
- foreign currency exchange rates and interest rates;
- general business, economic and market conditions;
- 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, services,
supplies 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 production 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, product 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, including in relation to the
impact of the COVID-19 pandemic;
- changes in capital spending plans and planned exploration and
development activities;
- the potential for changes to preliminary anticipated 2022
capital expenditures prior to finalization and changes to the
resulting expected 2022 average sales volumes and free cash
flow;
- changes in foreign currency exchange rates and interest
rates;
- 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, services, supplies 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 enter into and maintain leases
and licenses;
- the effects of weather and other factors including wildlife and
environmental restrictions which affect field operations and
access;
- 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, 2020, 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 2021 and forecast 2021
year-end net debt to annual adjusted funds flow, 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.
Non-GAAP Financial Measures
In this press release, "adjusted funds flow", "free cash flow",
"netback", "net debt", "net debt to adjusted funds flow" and "total
capital expenditures", together the "Non-GAAP financial measures",
are used and do not have any standardized meanings as prescribed by
International Financial Reporting Standards. Certain
comparative figures have been reclassified to conform to the
current years' presentation.
"Adjusted funds flow" refers to cash from (used in) operating
activities before net changes in non-cash working capital,
geological and geophysical expenses, asset retirement obligation
settlements, closure costs, provisions and other, dispute
settlements and transaction and reorganization costs.
Adjusted funds flow is used to assist management and investors in
measuring the Company's ability to fund capital programs and meet
financial obligations, including the settlement of asset retirement
obligations. Asset retirement obligation settlements are
excluded from the calculation of adjusted funds flow because such
expenditures are not directly linked to the revenue generating
activities of the Company. Paramount manages the timing of
expenditures related to asset retirement obligation settlements in
accordance with regulatory requirements and its overall approach to
managing its asset retirement obligations and, as a result, amounts
incurred may vary significantly from period to period. Adjusted
funds flow is not intended to represent cash from operating
activities, net loss or any other GAAP measure and should not be
construed as being an alternative to, or more meaningful than, cash
flow from operating activities as determined in accordance with
IFRS. The following are the calculations of adjusted funds
flow from the nearest GAAP measure for the three months ended
June 30, 2021 and March 31, 2021:
Three months
ended
|
|
|
Jun 30,
2021
(MM$)
|
Mar 31,
2021
(MM$)
|
Cash from
operating activities
|
|
|
112.1
|
81.3
|
Change in non-cash
working capital
|
|
|
(47.6)
|
(7.9)
|
Geological and
geophysical expenses
|
|
|
1.8
|
1.6
|
Asset retirement
obligations settled
|
|
|
3.2
|
8.4
|
Closure
costs
|
|
|
–
|
–
|
Provisions and
other
|
|
|
16.5
|
7.5
|
Dispute
settlements
|
|
|
–
|
–
|
Transaction and
reorganization costs
|
|
|
–
|
–
|
Adjusted funds
flow
|
|
|
86.0
|
90.9
|
"Free cash flow" refers to adjusted funds flow less total
capital expenditures and asset retirement obligation
settlements. Free cash flow is used by management and
investors to assess the amount of internally generated cash
available to repay debt, reinvest in the business or return to
shareholders. The following is the calculation of free cash
flow from the nearest GAAP measure for the three months ended
June 30, 2021 and March 31, 2021:
Three months
ended
|
|
|
Jun 30,
2021
(MM$)
|
Mar 31,
2021
(MM$)
|
Cash from
operating activities
|
|
|
112.1
|
81.3
|
Change in non-cash
working capital
|
|
|
(47.6)
|
(7.9)
|
Geological and
geophysical expenses
|
|
|
1.8
|
1.6
|
Asset retirement
obligations settled
|
|
|
3.2
|
8.4
|
Closure
costs
|
|
|
–
|
–
|
Provisions and
other
|
|
|
16.5
|
7.5
|
Dispute
settlements
|
|
|
–
|
–
|
Transaction and
reorganization costs
|
|
|
–
|
–
|
Adjusted funds
flow
|
|
|
86.0
|
90.9
|
Total capital
expenditures
|
|
|
(83.5)
|
(59.3)
|
Asset retirement
obligation settlements
|
|
|
(3.2)
|
(8.4)
|
Free cash
flow
|
|
|
(0.7)
|
23.2
|
"Netback" equals petroleum and natural gas sales less
royalties, operating expense and transportation and NGLs processing
costs. Netback is commonly used by management and investors
to compare the results of the Company's oil and gas operations
between periods. Refer to the tables under the headings "Review of
Operations" and "Financial and Operating Results" for the
calculation thereof.
"Net debt" is a measure of the Company's overall debt
position after adjusting for certain working capital and other
amounts and is used by management to assess the Company's overall
leverage position. Refer to the Liquidity and Capital
Resources section of the Company's Management's Discussion and
Analysis for the three months and six months ended June 30, 2021 (the "MD&A") for the
calculation of net debt.
"Net debt to adjusted funds flow" is a ratio calculated as
the period end net debt divided by adjusted funds flow for the
trailing four quarters. The ratio of net debt to adjusted funds
flow is commonly used by management and investors to assess the
Company's overall debt position and to measure the strength of the
Company's balance sheet.
"Total capital expenditures" refers to the Company's
property, plant and equipment and exploration expenditures. Refer
to the Property, Plant and Equipment and Exploration Expenditures
section of the MD&A for the calculation thereof.
Non-GAAP financial measures should not be considered in
isolation or construed as alternatives to their most directly
comparable measure calculated in accordance with GAAP, or other
measures of financial performance calculated in accordance with
GAAP. The Non-GAAP financial measures are unlikely to be comparable
to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
Abbreviations
Liquids
|
|
Natural
Gas
|
Bbl
|
Barrels
|
|
GJ
|
Gigajoules
|
Bbl/d
|
Barrels per
day
|
|
GJ/d
|
Gigajoules per
day
|
MBbl
|
Thousands of
barrels
|
|
Mcf
|
Thousands of cubic
feet
|
NGLs
|
Natural gas
liquids
|
|
MMcf
|
Millions of cubic
feet
|
Condensate
|
Pentane and heavier
hydrocarbons
|
MMcf/d
|
Millions of cubic
feet per day
|
WTI
|
West Texas
Intermediate
|
|
AECO
|
AECO-C reference
price
|
|
|
|
NYMEX
|
New York Mercantile
Exchange
|
|
|
|
MMbtu
|
Millions of British
thermal units
|
|
|
|
MMbtu/d
|
Millions of British
thermal units per day
|
Oil
Equivalent
|
Boe
|
Barrels of oil
equivalent
|
MBoe
|
Thousands of barrels
of oil equivalent
|
|
MMBoe
|
Millions of barrels
of oil equivalent
|
|
Boe/d
|
Barrels of oil
equivalent per day
|
|
|
|
|
|
This press release contains disclosures expressed as "Boe",
"$/Boe" and "Boe/d". Natural gas equivalency volumes
have been derived using the ratio of six thousand cubic feet of
natural gas to one barrel of oil when converting natural gas to
Boe. Equivalency measures may be misleading, particularly if
used in isolation. A conversion ratio of six thousand cubic feet of
natural gas to one barrel of oil is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the well head. For the six
months ended June 30, 2021, the value
ratio between crude oil and natural gas was approximately 26:1.
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.
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, 2020 which is available on SEDAR at www.sedar.com.
SOURCE Paramount Resources Ltd.