CALGARY, AB, Nov. 5, 2020 /CNW/ -
HIGHLIGHTS
- Sales volumes averaged 61,064 Boe/d (39 percent liquids) in the
third quarter of 2020 compared to 68,839 Boe/d (39 percent liquids)
in the second quarter.
-
- Third quarter sales volumes at Karr averaged 19,246 Boe/d (57
percent liquids) compared to 16,009 Boe/d (52 percent liquids) in
the second quarter.
- At Wapiti, third quarter sales volumes were 7,925 Boe/d (63
percent liquids), approximately 7,000 Boe/d lower than the second
quarter, due to an unplanned six-week outage at a third-party
natural gas processing facility in the Wapiti field (the "Wapiti
Plant"). Paramount is pursuing a claim under its contingent
business interruption insurance policy related to the outage. The
policy has a 30-day waiting period and recoveries are expected to
exceed $5 million.
- At Karr, the five wells on the 2-1 pad were brought on
production through permanent facilities in early September. Average
gross peak 30-day production per well was 1,463 Boe/d, including
735 Bbl/d of wellhead liquids, with an average wellhead CGR of 168
Bbl/MMcf.(1)
- Despite lower production, Paramount's netback was $44.3 million in the third quarter of 2020
compared to $21.7 million in the
second quarter of 2020, reflecting higher liquids
prices.(2)
- Cash from operating activities was $11.4
million in the third quarter of 2020. Adjusted funds flow
was $29.5 million or $0.22 per share.(2)
- Third quarter capital spending totaled $50.5 million, primarily related to drilling and
completion activities at Karr. Spending included a portion of the
previously-announced acceleration of certain activities from
2021.
- The Company continues to realize significant cost savings in
its capital program through its focus on well design, increased
efficiencies and lower vendor rates, while not compromising on
completion effectiveness:
-
- All-in lease construction, drilling, completion, equip and
tie-in (collectively, "DCET") costs for the five-well (all Middle
Montney) Karr 2-1 pad averaged $7.3
million per well, $0.2 million
lower than prior estimates. This represents a 39 percent reduction
compared with average DCET costs for Karr wells in 2018 and
2019.
- Completion activities at the five-well (three Upper Montney and
two Middle Montney) Karr 5-16 West pad have recently been concluded
and preliminary lease construction, drilling and completion costs
are estimated at $7.2 million per
well.
- At Wapiti, completion activities at the five-well (two Middle
Montney and three Lower Montney) 5-3 West pad were recently
concluded. The Company estimates preliminary lease construction,
drilling and completion costs of $7.3
million per well. Despite higher fluid and proppant
intensity, estimated completion costs are approximately 30 percent
lower than the 2019 5-3 East pad due to improved efficiencies and
optimized completion design.
_____________________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 7 percent and liquids sales volumes are lower by
approximately 7 percent 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. CGRs are 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)
|
"Netback" and
"Adjusted funds flow" are Non-GAAP measures. See "Non-GAAP
Measures" in the Advisories section.
|
- Paramount, in collaboration with its vendors, has received
approval for up to approximately $10
million of funding under the Alberta Site Rehabilitation
Program ("ASRP") to date. It is anticipated that approximately
$4 million of abandonment and
reclamation work under the ASRP will occur in the fourth quarter of
2020, with the remainder to be undertaken in 2021.
- The Company has completed the installation of the remaining
low-bleed controllers in the Grande Prairie Region which brings the
high-bleed emission reduction project to completion across the
organization. In total, 1,900 high-bleed controllers have been
replaced, reducing annual GHG emissions by an estimated 75,000
tonnes of carbon dioxide equivalent
("CO2e").(1)
CORPORATE
- Paramount has now exceeded its previously announced 2020 cost
reduction targets of $25 million in
operating costs and $15 million in
general and administrative expenses.
-
- Operating costs averaged $11.10/Boe in the third quarter of 2020. Fourth
quarter operating costs are now anticipated to average
approximately $11.50/Boe as a result
of higher fourth quarter production and the Company's continued
efforts in sustainably improving its cost structure.
- The Company is maintaining its 2020 capital guidance of
$225 million.
- Paramount has largely brought back production that was
previously shut-in due to the deterioration of commodity prices in
the second quarter.
- Paramount is increasing the mid-point of its production
guidance, with sales volumes anticipated to average between 70,000
Boe/d and 72,000 Boe/d in the fourth quarter of 2020, reflecting
the Company's confidence in the onstream timing of new wells.
- Long-term debt at September 30,
2020 was $792.7 million.
- Paramount has undertaken an active hedging program and in the
third quarter added several additional hedges to provide greater
funds flow certainty and further protect the Company's capital
program. Nearly 50 percent of the Company's anticipated fourth
quarter production is hedged. See below under "Hedging".
_____________________________
|
(1)
|
Excludes GHG
emissions related to certain natural gas-weighted properties that
were sold in late 2019.
|
2021 CAPITAL PROGRAM
Paramount expects to finalize its 2021 capital budget and
related guidance in the first quarter of 2021. Based on
preliminary planning and current market conditions, Paramount
anticipates 2021 capital spending, excluding land acquisitions and
abandonment and reclamation activities, to range between
$225 million and $275 million. A capital program in this
range would be expected to result in:
- 2021 annual average sales volumes of between 77,500 Boe/d and
82,500 Boe/d (45% liquids); and
- adjusted funds flow that exceeds capital spending by
approximately $100 million, assuming
the midpoint of the capital spending and production ranges,
realized pricing of $32.00/Boe,
operating costs of $11.25/Boe and
transportation and processing costs of $4.00/Boe.
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Grande Prairie Region sales volumes and netbacks are summarized
below:
|
Q3
2020
|
Q2 2020
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
67.3
|
78.3
|
(14)
|
Condensate and oil
(Bbl/d)
|
13,960
|
16,309
|
(14)
|
Other NGLs
(Bbl/d)
|
2,060
|
1,680
|
23
|
Total
(Boe/d)
|
27,237
|
31,039
|
(12)
|
%
liquids
|
59%
|
58%
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change in
$
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
millions
|
Petroleum and natural
gas sales
|
79.1
|
31.58
|
60.3
|
21.34
|
31
|
Royalties
(1)
|
(2.2)
|
(0.90)
|
0.3
|
0.12
|
NM
|
Operating
expense
|
(38.8)
|
(15.47)
|
(38.8)
|
(13.73)
|
-
|
Transportation
and NGLs processing
|
(15.6)
|
(6.23)
|
(12.9)
|
(4.58)
|
21
|
|
22.5
|
8.98
|
8.9
|
3.15
|
153
|
(1)
Second quarter royalties were impacted by lower prices and
adjustments related to prior year gas cost allowance. NM means not
meaningful
|
Karr
Karr sales volumes and netbacks are summarized below:
|
Q3
2020
|
Q2 2020
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
49.2
|
46.1
|
7
|
Condensate and oil
(Bbl/d)
|
9,541
|
7,501
|
27
|
Other NGLs
(Bbl/d)
|
1,503
|
829
|
81
|
Total
(Boe/d)
|
19,246
|
16,009
|
20
|
%
liquids
|
57%
|
52%
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change in
$
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
millions
|
Petroleum and natural
gas sales
|
54.9
|
31.01
|
29.4
|
20.20
|
87
|
Royalties
(1)
|
(1.4)
|
(0.80)
|
1.3
|
0.87
|
NM
|
Operating
expense
|
(26.2)
|
(14.77)
|
(22.4)
|
(15.39)
|
17
|
Transportation
and NGLs processing
|
(10.9)
|
(6.17)
|
(7.2)
|
(4.91)
|
51
|
|
16.4
|
9.27
|
1.1
|
0.77
|
NM
|
(1)
Second quarter royalties were impacted by lower prices and
adjustments related to prior year gas cost allowance. NM means not
meaningful
|
Third quarter sales volumes at Karr averaged 19,246 Boe/d (57
percent liquids) compared to 16,009 Boe/d (52 percent liquids) in
the second quarter. Sales volumes were higher primarily due to
production contributions from the 12-18 pad that first flowed
through test facilities in the second quarter and was subsequently
brought onstream through permanent facilities in early July, as
well as the 2-1 pad that was brought onstream through permanent
facilities in early September. Sales volumes also benefited from a
pipeline debottlenecking project designed to mitigate current and
potential future back-out issues as new pads are brought on
production. The project included the installation of booster pumps
servicing the southwest extents of the Karr gathering system and
has resulted in improved runtime of both legacy and new wells in
the area.
Per unit operating costs continue to trend lower as a result of
increasing volumes combined with the impact of two water disposal
wells that were brought into service at the end of the first
quarter. The Company continues to expect these wells to meet Karr
area development needs as production ramps up. Per unit operating
and transportation costs are expected to decline as the Company
ramps up production in the fourth quarter of 2020 and into
2021.
The five-wells on the 2-1 pad averaged gross peak 30-day
production per well of 1,463 Boe/d, including 735 Bbl/d of wellhead
liquids, and an average wellhead CGR of 168 Bbl/MMcf.(1)
These wells exhibit higher gas production compared to other
recently drilled Karr wells, which is in line with
expectations.
In 2020, Paramount implemented data analytics workflows that
incorporate and leverage proprietary geoscience characterization
and daily well performance with public data sources. Utilizing this
data foundation, Paramount is able to generate advanced predictive
models to rapidly assess development opportunities at its
Grande Prairie Montney assets under
a variety of scenarios and implement changes to completion design,
well spacing and other factors to maximize returns. Improved
completion design is one of the primary reasons that costs in the
Karr area have been trending downward while completion
effectiveness has been maintained. All-in DCET costs at the 2-1 pad
averaged $7.3 million per well,
representing a 39 percent reduction compared with average DCET
costs for Karr wells in 2018 and 2019.
At the five-well 5-16 West pad, completion activities were
recently concluded and preliminary lease construction, drilling and
completion costs are coming in at an estimated $7.2 million per well. The pre-building and
modularization of above ground well equipment packages on this pad
improved schedule efficiency, and the Company anticipates bringing
these wells on production in late November.
Paramount recently commenced drilling six Middle Montney wells
on the Karr 3-10 pad. The Company plans to complete, tie-in and
bring on production all six of these wells in the first half of
2021. Additionally, lease construction at the five-well 7-18 pad
has begun, with drilling anticipated to start in December 2020.
_____________________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 7 percent and liquids sales volumes are lower by
approximately 7 percent 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. CGRs are calculated by
dividing raw wellhead liquids volumes by raw wellhead natural gas
volumes. See Oil and Gas Measures and Definitions in the Advisories
section.
|
The following table summarizes the performance of Karr wells on
the 2-1, 12-18, 1-19, and 4-24 pads, as well as the five wells
drilled in 2018 and the 27 wells drilled in the 2016/2017 capital
program at Karr:
|
Peak 30-Day
(1)
|
Cumulative
(2)
|
|
|
Total
|
Wellhead
Liquids
|
CGR
(3)
|
Total
|
Wellhead Liquids
|
CGR
(3)
|
Days
on Production
|
|
(Boe/d)
|
(Bbl/d)
|
(Bbl/MMcf)
|
(MBoe)
|
(MBbl)
|
(Bbl/MMcf)
|
|
2-1
Pad
|
|
|
|
|
|
|
|
03/14-12-066-05W6/0
|
1,490
|
764
|
175
|
87
|
39
|
133
|
67
|
04/16-12-066-05W6/0
|
1,723
|
977
|
218
|
97
|
50
|
174
|
65
|
05/15-12-066-05W6/0
|
1,376
|
621
|
137
|
88
|
40
|
137
|
67
|
05/16-12-066-05W6/0
|
1,428
|
667
|
146
|
92
|
45
|
160
|
66
|
06/15-12-066-05W6/0
|
1,300
|
646
|
165
|
84
|
39
|
144
|
65
|
Avg. per
well
|
1,463
|
735
|
168
|
90
|
43
|
151
|
66
|
12-18
Pad
|
|
|
|
|
|
|
|
00/09-17-065-05W6/2
|
1,304
|
1,056
|
710
|
85
|
67
|
616
|
127
|
00/16-17-065-05W6/0
|
1,644
|
1,262
|
550
|
125
|
92
|
476
|
124
|
02/09-17-065-05W6/0
|
1,757
|
1,350
|
553
|
145
|
107
|
473
|
127
|
02/16-17-065-05W6/0
|
1,692
|
1,181
|
385
|
166
|
111
|
335
|
128
|
03/09-17-065-05W6/0
|
1,567
|
1,232
|
614
|
146
|
111
|
533
|
127
|
Avg. per
well
|
1,593
|
1,216
|
538
|
133
|
98
|
454
|
127
|
1-19
Pad
|
|
|
|
|
|
|
|
03/13-29-065-05W6/0
|
1,704
|
1,209
|
407
|
339
|
228
|
342
|
312
|
03/14-29-065-05W6/0
|
1,357
|
1,067
|
611
|
192
|
142
|
474
|
244
|
04/13-29-065-05W6/0
|
1,566
|
1,170
|
493
|
279
|
195
|
386
|
304
|
Avg. per
well
|
1,542
|
1,149
|
486
|
270
|
188
|
384
|
287
|
4-24
Pad
|
|
|
|
|
|
|
|
00/01-11-065-06W6/0
|
1,878
|
1,271
|
349
|
408
|
242
|
244
|
407
|
00/02-12-065-06W6/0
|
1,836
|
1,308
|
413
|
329
|
223
|
351
|
412
|
00/03-12-065-06W6/0
|
2,307
|
1,583
|
365
|
527
|
330
|
279
|
425
|
00/04-12-065-06W6/0
|
2,097
|
1,329
|
289
|
537
|
316
|
238
|
418
|
02/03-12-065-06W6/0
|
2,029
|
1,308
|
302
|
463
|
284
|
263
|
419
|
Avg. per
well
|
2,029
|
1,360
|
338
|
453
|
279
|
268
|
416
|
2018
Wells
|
|
|
|
|
|
|
|
5 wells (Avg. per
well)
|
1,877
|
1,121
|
247
|
651
|
337
|
180
|
680
|
2016/2017
Wells
|
|
|
|
|
|
|
|
27 wells (Avg. per
well)
|
1,969
|
1,171
|
245
|
758
|
377
|
165
|
918
|
(1)
|
Peak 30-Day is the
highest daily average production rate over a 30-day consecutive
period for each well, measured at the wellhead. Natural gas sales
volumes are approximately 7 percent lower and liquids sales volumes
are approximately 7 percent lower due to shrinkage. Excludes days
when the wells did not produce. The production rates and volumes
shown are 30-day peak rates 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. These wells were produced at restricted rates from
time-to-time due to facility and gathering system constraints. See
ʺOil and Gas Measures and Definitionsʺ in the
Advisories.
|
(2)
|
Cumulative is the
aggregate production measured at the wellhead to October 31, 2020.
Natural gas sales volumes are approximately 7 percent lower and
liquids sales volumes are approximately 7 percent lower due to
shrinkage. These wells were produced at restricted rates from
time-to-time due to facility and gathering system constraints. The
production rates and volumes shown are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells.
|
(3)
|
CGRs calculated by
dividing raw wellhead liquids volumes by raw wellhead natural gas
volumes.
|
Wapiti
Wapiti sales volumes and netbacks are summarized below:
|
Q3
2020
|
Q2 2020
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
17.8
|
31.9
|
(44)
|
Condensate and oil
(Bbl/d)
|
4,414
|
8,786
|
(50)
|
Other NGLs
(Bbl/d)
|
548
|
841
|
(35)
|
Total
(Boe/d)
|
7,925
|
14,940
|
(47)
|
%
liquids
|
63%
|
64%
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change in
$
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
millions
|
Petroleum and natural
gas sales
|
24.1
|
33.10
|
30.7
|
22.61
|
(21)
|
Royalties
|
(0.9)
|
(1.18)
|
(1.0)
|
(0.70)
|
(10)
|
Operating
expense
|
(12.3)
|
(16.88)
|
(15.9)
|
(11.69)
|
(23)
|
Transportation
and NGLs processing
|
(4.7)
|
(6.42)
|
(5.8)
|
(4.24)
|
(19)
|
|
6.2
|
8.62
|
8.0
|
5.98
|
(23)
|
Third quarter sales volumes at Wapiti averaged 7,925 Boe/d (63
percent liquids) compared to 14,940 Boe/d (64 percent liquids) in
the second quarter. Production was shut-in due to a six-week
unplanned outage at the Wapiti Plant. Paramount is pursuing a
claim under its contingent business interruption insurance policy
related to the outage. The policy has a 30-day waiting period
and recoveries are expected to exceed $5
million.
Completion operations at the five-well 5-3 West pad commenced in
October, and despite utilizing higher fluid and proppant intensity
compared to the 5-3 East pad drilled in 2019, the Company estimates
per well completion costs to come in approximately 30 percent lower
as a result of improved efficiencies and completion design.
Preliminary lease construction, drilling and completion costs are
estimated at $7.3 million per
well. Paramount plans to equip, tie-in and bring on
production these five wells in the coming months.
Drilling of the remaining six wells on the eight-well (four
Middle Montney and four Lower Montney) Wapiti 6-4 pad is scheduled
to commence late in the fourth quarter. The Company plans to
complete, tie-in and bring on production all eight wells in
mid-2021.
The following table summarizes the performance of Wapiti wells
on the 5-3 East and 9-3 pads:
|
Peak 30-Day
(1)
|
Cumulative
(2)
|
|
|
Total
|
Wellhead
Liquids
|
CGR
(3)
|
Total
|
Wellhead Liquids
|
CGR
(3)
|
Days on
Production
|
|
(Boe/d)
|
(Bbl/d)
|
(Bbl/MMcf)
|
(MBoe)
|
(MBbl)
|
(Bbl/MMcf)
|
|
5-3 East
Pad
|
|
|
|
|
|
|
|
03/11-27-067-06W6/0
|
2,174
|
1,360
|
279
|
263
|
151
|
226
|
263
|
04/06-15-068-06W6/0
|
1,703
|
1,154
|
351
|
190
|
124
|
313
|
224
|
02/09-28-067-06W6/0
|
1,797
|
1,130
|
283
|
152
|
92
|
257
|
145
|
02/11-27-067-06W6/0
|
2,017
|
1,296
|
299
|
248
|
150
|
256
|
257
|
00/12-27-067-06W6/0
|
1,390
|
926
|
332
|
158
|
95
|
250
|
195
|
02/12-27-067-06W6/0
|
1,949
|
1,277
|
317
|
209
|
120
|
224
|
197
|
00/09-28-067-06W6/0
|
1,585
|
1,060
|
336
|
179
|
106
|
241
|
173
|
03/06-15-068-06W6/0
|
1,409
|
984
|
385
|
184
|
125
|
350
|
211
|
00/05-15-068-06W6/0
|
1,432
|
1,018
|
410
|
155
|
109
|
387
|
193
|
02/05-15-068-06W6/0
|
1,563
|
1,070
|
362
|
172
|
116
|
339
|
182
|
00/08-16-068-06W6/0
|
1,396
|
934
|
338
|
170
|
112
|
317
|
177
|
02/08-16-068-06W6/0
|
1,711
|
1,214
|
407
|
129
|
88
|
357
|
101
|
Avg. per
well
|
1,677
|
1,119
|
334
|
184
|
116
|
282
|
193
|
9-3
Pad
|
|
|
|
|
|
|
|
00/11-27-067-06W6/0
|
1,360
|
880
|
306
|
246
|
152
|
268
|
364
|
03/08-15-068-06W6/0
|
962
|
689
|
421
|
176
|
126
|
414
|
331
|
04/09-27-067-06W6/0
|
1,536
|
1,102
|
423
|
368
|
229
|
276
|
447
|
03/09-27-067-06W6/0
|
1,268
|
794
|
279
|
334
|
205
|
265
|
448
|
02/06-15-068-06W6/0
|
1,511
|
1,088
|
429
|
234
|
158
|
347
|
316
|
02/09-27-067-06W6/0
|
1,094
|
769
|
395
|
298
|
187
|
282
|
429
|
03/07-15-068-06W6/0
|
1,042
|
787
|
516
|
229
|
151
|
318
|
414
|
02/10-27-067-06W6/0
|
1,137
|
779
|
362
|
289
|
181
|
278
|
409
|
03/10-27-067-06W6/0
|
1,111
|
749
|
345
|
292
|
173
|
244
|
429
|
02/08-15-068-06W6/0
|
969
|
693
|
419
|
207
|
139
|
338
|
385
|
02/07-15-068-06W6/0
|
1,192
|
815
|
360
|
227
|
152
|
340
|
371
|
Avg. per
well
|
1,198
|
831
|
378
|
264
|
168
|
295
|
395
|
(1)
|
Peak 30-Day is the
highest daily average production rate over a 30-day consecutive
period for each well, measured at the wellhead. Natural gas sales
volumes are approximately 11 percent lower and liquids sales
volumes are approximately 3 percent lower due to shrinkage under
normalized operations. Excludes days when the wells did not
produce. The production rates and volumes shown are 30-day peak
rates 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. These wells
were produced at restricted rates from time-to-time due to facility
and gathering system constraints. See ʺOil and Gas Measures and
Definitionsʺ in the Advisories
|
(2)
|
Cumulative is the
aggregate production measured at the wellhead to October 31, 2020.
Natural gas sales volumes are approximately 11 percent lower and
liquids sales volumes are approximately 3 percent lower due to
shrinkage under normalized operating conditions. These wells were
produced at restricted rates from time-to-time due to facility and
gathering system constraints. The production rates and volumes
shown are not necessarily indicative of average daily production,
long-term performance or of ultimate recovery from the
wells
|
(3)
|
CGRs calculated by
dividing raw wellhead liquids volumes by raw wellhead natural gas
volumes
|
KAYBOB REGION
Kaybob Region sales volumes averaged 25,477 Boe/d (26 percent
liquids) in the third quarter compared to 29,561 Boe/d (26 percent
liquids) in the second quarter. The quarter over quarter
decrease was primarily attributable to natural declines and planned
maintenance outages during the third quarter. The Company
completed a major turnaround in the quarter of its Presley 3-29
facility on schedule, under budget and without incident.
Paramount continues to focus on operational excellence, making
progress on improving its cost structure while maintaining best
practices in safety, asset integrity, reliability and environmental
performance. Improvements in operational efficiency have been
especially impactful in the Kaybob Region, resulting in significant
cost savings compared with previous years.
Paramount holds material positions in the Duvernay and Montney resource plays in the
Kaybob Region that will compete for capital in the medium term. The
Company is monitoring regional competitor activity and using this
information to evaluate the full field development plans for these
plays. Recent competitor results have been encouraging,
including an offsetting well just north-east of the Company's
Kaybob North Duvernay field that appears to have produced the
highest ever monthly oil/condensate volume for a Duvernay well in the basin.
Supporting production in the Region is a network of owned
infrastructure including the Company's crude oil terminal that was
first put into service in the fourth quarter of 2019. The
pipeline connected terminal provides Paramount the opportunity to
increase netbacks for its Kaybob area crude and condensate volumes
and capture incremental value in price differentials.
CENTRAL ALBERTA AND OTHER
REGION
Central Alberta and Other
Region sales volumes averaged 8,350 Boe/d (14 percent liquids)
compared to 8,239 Boe/d (12 percent liquids) in the second
quarter.
Paramount holds a material, contiguous Duvernay position at Willesden Green and
continues to actively evaluate longer-term full field development
plans for this asset.
GREENHOUSE GAS REDUCTION INITIATIVE
As part of Paramount's continued commitment to responsible
energy development, the Company has been participating in GHG
emission reduction programs and investing in new equipment to
reduce GHG emissions from its operations. Upstream emissions
intensity (combined Scope 1 and Scope 2) was 18.5 kg
CO2e/Boe in 2019, an 18 percent reduction from the
previous year. This compares to the Oil and Gas Climate
Initiative ("OGCI") group average of 21.1 kg CO2e/Boe in
2019 and their stated target of 20.0 kg CO2e/Boe by the
year 2025. OGCI is an international industry-led organization
comprised of 12 of the world's largest energy companies,
representing over one fifth of global oil and gas production.
The Company has completed its project in the Grande Prairie area to replace approximately
200 high-bleed controllers with modern low-bleed units at well
sites. These new units are expected to eliminate
approximately 8,600 tonnes of GHG emissions per year and generate
approximately $0.5 million in GHG
credits under current regulations through 2022. This project,
which was part of a larger, multi-year initiative where
approximately 1,900 high-bleed controllers have been replaced, is
estimated to reduce annual GHG emissions by approximately 75,000
tonnes of CO2e when compared to baseline 2017
emissions.(1) Paramount continues to
evaluate its assets for further methane reduction
opportunities.
____________________________________
|
(1)
|
Excludes GHG
emissions related to certain natural gas-weighted properties that
were sold in late 2019.
|
HEDGING
The Company's commodity hedging position as at September 30, 2020 is summarized below:
Rest of
2020
|
~60,000 MMBtu/d at
US$2.58/MMBtu
|
|
~66,800 GJ/d at
CDN$2.18/GJ
|
|
|
2021
|
~67,500 MMBtu/d at
US$2.73/MMBtu
|
|
~60,000 GJ/d at
CDN$2.54/GJ
|
Rest of
2020
|
~4,000 Bbl/d at
CDN$80.11/Bbl
|
|
~9,700 Bbl/d at
US$43.22/Bbl
|
2021
|
5,000 Bbl/d at
US$44.10/Bbl
|
Subsequent to September 30, 2020,
the Company hedged the differential on 1,000 Bbl/d of condensate at
Edmonton for the first quarter of
2021 at WTI plus US$0.50/Bbl.
Further details of Paramount's commodity hedging position are
provided in its third quarter 2020 Management's Discussion and
Analysis and Consolidated Financial Statements.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused
Canadian energy company that explores for and develops both
conventional and unconventional petroleum and natural gas reserves
and resources, including longer-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are located in
Alberta and British Columbia. Paramount's Class A common
shares are listed on the Toronto Stock Exchange under the symbol
"POU".
Paramount's third quarter 2020 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at
https://mma.prnewswire.com/media/1328030/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_Third.pdf
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at
www.sedar.com. A summary of historical financial and
operating results is also available on Paramount's website at
http://www.paramountres.com/investor-relations/financial-reports#2020.
FINANCIAL AND
OPERATING RESULTS (1)
($ millions,
except as noted)
|
|
|
|
Q3
2020
|
Q2
2020
|
|
Net
loss
|
|
|
|
|
(23.3)
|
(75.7)
|
|
per share – basic
and diluted ($/share)
|
|
|
|
|
(0.17)
|
(0.57)
|
|
Cash from (used
in) operating activities
|
|
|
|
|
11.4
|
(14.2)
|
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.09
|
(0.11)
|
|
Adjusted funds
flow
|
|
|
|
|
29.5
|
19.0
|
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.22
|
0.14
|
|
Total
assets
|
|
|
|
|
3,041.9
|
3,066.4
|
|
Long-term
debt
|
|
|
|
|
792.7
|
754.9
|
|
Net
debt
|
|
|
|
|
836.5
|
810.7
|
|
Common shares
outstanding (thousands)(2)
|
|
|
|
|
133,784
|
133,784
|
|
Sales
volumes
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
|
224.0
|
253.2
|
|
Condensate and oil
(Bbl/d)
|
|
|
19,782
|
22,823
|
|
Other NGLs
(Bbl/d) (3)
|
|
|
3,952
|
3,817
|
|
Total
(Boe/d)
|
|
|
61,064
|
68,839
|
|
%
liquids
|
|
|
39%
|
39%
|
|
Grande Prairie Region
(Boe/d)
|
|
|
27,237
|
31,039
|
|
Kaybob Region
(Boe/d)
|
|
|
25,477
|
29,561
|
|
Central Alberta and
Other Region (Boe/d)
|
|
|
8,350
|
8,239
|
|
Total
(Boe/d)
|
|
|
61,064
|
68,839
|
|
Netback
|
|
|
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
|
Natural gas
revenue
|
|
|
|
|
40.0
|
1.94
|
44.7
|
1.94
|
|
Condensate and
oil revenue
|
|
|
|
|
88.7
|
48.74
|
60.3
|
29.05
|
|
Other NGLs
revenue (3)
|
|
|
|
|
6.6
|
18.10
|
4.3
|
12.28
|
|
Royalty and
sulphur revenue
|
|
|
|
|
3.5
|
─
|
3.9
|
─
|
|
Petroleum and
natural gas sales
|
|
|
|
|
138.8
|
24.70
|
113.2
|
18.07
|
|
Royalties
|
|
|
|
|
(4.3)
|
(0.77)
|
(3.6)
|
(0.57)
|
|
Operating
expense
|
|
|
|
|
(62.4)
|
(11.10)
|
(62.6)
|
(9.99)
|
|
Transportation
and NGLs processing (5)
|
|
|
|
|
(27.8)
|
(4.95)
|
(25.3)
|
(4.04)
|
|
Netback
|
|
|
|
|
44.3
|
7.88
|
21.7
|
3.47
|
|
Commodity contract
settlements
|
|
|
|
|
9.8
|
1.75
|
12.9
|
2.05
|
|
Netback including
commodity contract settlements
|
54.1
|
9.63
|
34.6
|
5.52
|
|
Total Capital
Expenditures
|
|
|
|
|
|
Grande Prairie
Region
|
|
|
46.1
|
36.7
|
|
Kaybob
Region
|
|
|
2.7
|
1.8
|
|
Central Alberta and
Other Region
|
|
|
0.2
|
0.8
|
|
Corporate
|
|
|
1.5
|
1.5
|
|
Land and property
acquisitions
|
|
|
─
|
0.6
|
|
Total capital
expenditures
|
|
|
50.5
|
41.4
|
|
Asset retirement
obligation settlements
|
|
|
0.7
|
4.0
|
|
(1)
|
Readers are referred
to the advisories concerning Non-GAAP Measures and Oil and Gas
Measures and Definitions in the Advisories section of this
document. This table contains the following Non-GAAP measures:
Adjusted Funds Flow, Net Debt, Netback, and Total Capital
Expenditures
|
(2)
|
Common shares are
presented net of shares held in trust under the Company's
restricted share unit plan (000's of common shares): Q3 2020: 414
and Q2 2020: 414
|
(3)
|
Other NGLs means
ethane, propane and butane
|
(4)
|
Natural gas revenue
presented as $/Mcf
|
(5)
|
Includes downstream
transportation costs and NGLs fractionation costs
|
ADVISORIES
Forward-looking Information
Certain statements in this press release constitute
forward-looking information under applicable securities
legislation. Forward-looking information typically contains
statements with words such as "anticipate", "believe", "estimate",
"will", "expect", "plan", "schedule", "intend", "propose", or
similar words suggesting future outcomes or an outlook.
Forward-looking information in this press release includes, but is
not limited to:
- planned capital expenditures for 2020;
- anticipated sales volumes in the fourth quarter of 2020;
- the expectation that Paramount will finalize its 2021 capital
budget and related guidance in the first quarter of 2021;
- preliminary anticipated capital expenditures in 2021 and the
resulting expected 2021 average sales volumes and excess of
adjusted funds flow over such expenditures;
- planned exploration, development and production
activities;
- estimated lease construction, drilling and completion
costs;
- expected GHG reductions and credits associated with controller
upgrades;
- planned abandonment and reclamation expenditures using funding
under the Alberta Site Rehabilitation Program;
- anticipated operating costs in the fourth quarter of 2020;
- the expectation that two additional water disposal wells will
meet Karr area development needs as production ramps up;
- the expectation that per unit operating and transportation
costs at Karr will continue to decline as the Company ramps up
production in the fourth quarter of 2020 and into 2021; and
- expected recoveries under Paramount's contingent business
interruption insurance related to the Wapiti Plant outage.
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 natural gas and liquids 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, 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 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;
- the application of Paramount's contingent business interruption
insurance policy to the Wapiti Plant outage; 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:
- those risks set out in the Management's Discussion and Analysis
for the three and nine months ended September 30, 2020 ("MD&A") under "Risk
Factors";
- fluctuations in natural gas and liquids 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 2021
capital expenditures prior to finalization and changes to the
resulting expected 2021 average sales volumes and excess of
adjusted funds flow over such expenditures;
- changes in foreign currency exchange rates and interest
rates;
- the uncertainty of estimates and projections relating to future
revenue, production, reserve additions, liquids 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 flow from operations
and obtain financing to fund planned exploration, development and
operational activities and meet current and future commitments and
obligations (including product processing, transportation,
fractionation and similar commitments and obligations);
- changes in, or in the interpretation of, laws, regulations or
policies (including environmental laws);
- the ability to obtain required governmental or regulatory
approvals in a timely manner, and to obtain and maintain leases and
licenses;
- the effects of weather and other factors including wildlife and
environmental restrictions which affect field operations and
access;
- 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.
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, 2019 and in
the MD&A, which are 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.
Non-GAAP Measures
In this press release, "Adjusted funds flow", "Netback", "Net
Debt" and "Total Capital Expenditure", together the "Non-GAAP
measures", are used and do not have any standardized meanings as
prescribed by International Financial Reporting Standards.
"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, reorganization costs and provision and other.
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
September 30, 2020 and June 30, 2020:
Three months
ended
|
|
|
Sept 30,
2020
(MM$)
|
Jun 30,
2020
(MM$)
|
Cash from (used
in) operating activities
|
|
|
11.4
|
(14.2)
|
Change in non-cash
working capital
|
|
|
15.6
|
24.0
|
Geological and
geophysical expenses
|
|
|
1.7
|
1.9
|
Asset retirement
obligations settled
|
|
|
0.7
|
4.0
|
Reorganization
costs
|
|
|
─
|
3.0
|
Provision and
other
|
|
|
0.1
|
0.3
|
Adjusted funds
flow
|
|
|
29.5
|
19.0
|
"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 table under the heading "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 MD&A for the calculation of Net
Debt.
"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 Company's MD&A for the calculation thereof.
Non-GAAP 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
measures are unlikely to be comparable to similar measures
presented by other issuers.
Oil and Gas Measures and Definitions
The term "liquids" includes oil, condensate and Other NGLs
(ethane, propane and butane). NGLs consist of condensate and
Other NGLs.
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
|
|
|
|
AECO
|
AECO-C reference
price
|
Oil
Equivalent
|
|
WTI
|
West Texas
Intermediate
|
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", "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, 2020, 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 this oil and gas metric for its
own performance measurements and to provide shareholders with
measures to compare the Company's performance over time; however,
such measure is not a reliable indicator 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, including a breakdown of 2019 annual and
quarterly production volumes by product type, is provided in the
Company's annual information form for the year ended December 31, 2019 which is available on SEDAR at
www.sedar.com.
SOURCE Paramount Resources Ltd.