CALGARY, AB, March 3, 2021
/CNW/ -
HIGHLIGHTS
- Annual sales volumes averaged 68,340 Boe/d (39% liquids) in
2020. Fourth quarter 2020 sales volumes averaged 73,460 Boe/d (42%
liquids), ahead of guidance of 70,000 to 72,000 Boe/d.(1)
-
- Fourth quarter sales volumes at Karr, which benefitted from
bringing onstream the five-well 5-16 West pad in November, averaged
26,914 Boe/d (56% liquids), compared to 19,246 Boe/d (57% liquids)
in the third quarter.
- Fourth quarter sales volumes at Wapiti averaged 10,764 Boe/d
(64% liquids), compared to 7,925 Boe/d (63% liquids) in the third
quarter. The Company brought five new wells onstream on the 5-3
West pad during the fourth quarter.
- Cash from operating activities was $81
million in 2020 and $53
million in the fourth quarter. Adjusted funds flow in 2020
was $150 million or $1.12 per share. Fourth quarter 2020 adjusted
funds flow was $68 million or
$0.51 per share.(2)
- Capital spending in 2020 totaled $221
million, below guidance of $225
million. Fourth quarter 2020 capital spending was
$65 million, resulting in free cash
flow of $3 million in the
quarter.(2)
- Abandonment and reclamation expenditures in 2020 totaled
$35 million. In addition,
approximately $4 million of
activities were funded through government programs. Activities
included the abandonment of 254 inactive wells, 236 of which were
abandoned under the Company's ongoing area-based closure program at
Hawkeye and Zama.
- Based on Paramount's strong financial and operational
performance, in March 2021 the
Company elected to exit the covenant relief period under its
$1.0 billion bank credit facility
prior to the scheduled expiry of the period on June 30, 2021.
_________________________
|
(1)
|
In this press
release, "liquids" refers to NGLs (including condensate) and oil
combined, "natural gas" refers to conventional natural gas and
shale gas combined, "condensate and oil" refers to condensate,
light and medium crude oil and tight oil combined and "other NGLs"
refers to ethane, propane and butane. See the Product Type
Information section for a complete breakdown of sales volumes for
applicable periods by specific product type 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"
and "free cash flow" are Non-GAAP financial measures. See "Non-GAAP
Financial Measures" in the Advisories section.
|
- The Company exceeded its previously announced 2020 cost
reduction targets of $25 million in
operating costs and $15 million in
general and administrative expenses ("G&A").
-
- Operating costs were $0.62/Boe
lower in 2020 than in 2019, averaging $11.88/Boe in 2020. Fourth quarter operating
costs were $11.80/Boe and included
unbudgeted workovers on five wells in Karr, which partially
contributed to fourth quarter production outperformance.
- G&A costs were approximately $20
million ($0.43/Boe) lower in
2020 than in 2019, averaging $1.31/Boe in 2020.
- The Company successfully closed non-core asset dispositions for
cash proceeds of approximately $80
million in the first quarter of 2021. The estimated impact
to average 2021 production is approximately 2,600 Boe/d (15 MMcf/d
of conventional natural gas and 135 Bbl/d of NGLs).
GRANDE PRAIRIE ACTIVITIES
AND PERFORMANCE
- At Karr, a total of 15 new Montney wells were brought on production in
the second half of 2020 following completion of an expansion to the
third-party Karr 6-18 facility in July.
-
- The five-well 12-18 pad and the five-well 2-1 pad were brought
on production in the third quarter. These 10 wells averaged 1,502
Boe/d (3.6 MMcf/d of shale gas and 905 Bbl/d of NGLs) of peak
30-day wellhead production per well, with an average condensate to
gas ratio ("CGR") of 253 Bbl/MMcf.(1)
- The five-well 5-16 West pad was brought onstream in
November 2020. These wells averaged
1,617 Boe/d (3.7 MMcf/d of shale gas and 1,002 Bbl/d of NGLs) of
peak 30-day wellhead production per well, with an average CGR of
271 Bbl/MMcf.(1)
- Six new Montney wells on the
3-10 pad at Karr were brought onstream in February 2021, two months ahead of schedule. The
wells averaged 1,850 Boe/d (5.1 MMcf/d of shale gas and 1,000 Bbl/d
of NGLs) of raw wellhead production per well over the first 20 days
of production with an average CGR of 196 Bbl/MMcf.(1)
- At Wapiti, five Montney wells
on the 5-3 West pad were brought onstream in 2020 and averaged
1,271 Boe/d (2.7 MMcf/d of shale gas and 827 Bbl/d of NGLs) of peak
30-day wellhead production per well, with an average CGR of 311
Bbl/MMcf.(2) A pre-existing tenure well was also brought
onstream.
- Through a continued focus on innovation, technological
advancement and efficient execution, the Company realized
significant cost savings in its 2020 capital program without
compromising deliverability from new wells. Cost savings have been
achieved across many aspects of the capital program through
improvements in well design, drill bit technology, fluid selection
and reducing vendor rates.
-
- All-in lease construction, drilling, completion, equip and
tie-in (collectively, "DCET") costs for the five-well Karr 5-16
West pad averaged $7.5 million per
well.
_____________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 7% and liquids sales volumes are lower by
approximately 7% 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)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 15% and liquids sales volumes are lower by
approximately 3% 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.
|
- Drilling of the six-well Karr 3-10 pad finished ahead of
schedule allowing the Company to accelerate completion operations
into 2020. Preliminary DCET costs averaged a pacesetting
$7.0 million per well.
- DCET costs for the last four pads (comprised of 21 wells) at
Karr averaged approximately $7.5
million per well. As a consequence of structural cost
improvements, the Company is revising downward its internal Karr
type well DCET cost assumption to $7.5
million from the previous assumption of $8.4 million, the latter of which was used by the
Company's independent third-party reserves evaluator in the
preparation of the 2020 reserves report.(1)
- At Wapiti, DCET costs on the five-well 5-3 West pad averaged
$7.6 million per well. This
represents a 27% reduction compared with average DCET costs for the
initial two Wapiti pads and is consistent with Paramount's internal
type well DCET cost assumption for Wapiti of $7.9 million, which was also used by the
Company's independent third-party reserves evaluator in the
preparation of the 2020 reserves report. (1)
2021 GUIDANCE
The Company's capital budget for 2021 is expected to range
between $230 million and $260 million, excluding land acquisitions and
abandonment and reclamation activities. Over 60% of the
capital budget will be incurred in the first half of 2021.
Approximately 85% of the 2021 program will be focused on advancing
the Company's liquids-rich Montney
developments at Karr and Wapiti. Approximately 70% of the 2021
capital budget is being allocated to sustaining capital and
maintenance activities and the remaining 30% to production
growth.
- At Karr, Paramount plans to drill 21 Montney wells and bring
onstream a total of 19 wells in 2021. The six-well 3-10 pad was
brought on production in February
2021, and the Company is currently drilling the three-well
4-28 East pad and the five-well 7-18 Pad that are expected to be
onstream late in the second quarter and third quarter,
respectively. The Company also plans to drill and bring onstream
the five-well 5-16 East pad by the end of the third quarter and
begin drilling the ten-well 16-17 pad during the fourth
quarter.
- At Wapiti, the Company is currently drilling the remaining four
Montney wells on the seven-well
6-4 pad. All seven wells are expected to be brought onstream
starting in the third quarter of 2021. The Company also plans to
drill a tenure well at Wapiti in 2021.
- Other key activities include a two-well Duvernay pad at Willesden Green, completion of
a single well at Ante Creek (Montney oil) and the initiation of an enhanced
oil recovery pilot at the Kaybob North Montney oil pool.
The Company expects 2021 sales volumes to average between 77,000
Boe/d and 80,000 Boe/d (45% liquids), slightly higher than
preliminary guidance after accounting for first quarter
dispositions of approximately 2,600 Boe/d of annualized production.
(2)
- First half 2021 sales volumes are expected to average between
74,000 Boe/d and 76,000 Boe/d (43% liquids) as the majority of new
wells will be brought on later in the year and volumes will be
impacted by a scheduled outage at Karr in the second quarter.
- Despite a scheduled outage at Wapiti in the third quarter,
second half 2021 sales volumes are expected to increase to average
between 80,000 Boe/d and 84,000 Boe/d (46% liquids) as additional
liquids-rich wells are brought onstream.
__________________
|
(1)
|
Readers are referred
to the advisories concerning "Reserves Data" in the Advisories
section of this document.
|
(2)
|
See the Product Type
Information section for further information respecting the
composition of forecast sales volumes.
|
The Company forecasts 2021 free cash flow of approximately
$160 million based on: (i) the
midpoint of forecast capital spending and production, (ii)
$25 million in abandonment and
reclamation costs, (iii) realized pricing of $39.50/Boe (US$58.60/Bbl WTI, US$3.00/MMBtu NYMEX, $2.80/GJ AECO), (iv) operating costs of
$11.65/Boe, and (v) transportation
and processing costs of $4.00/Boe.
With approximately 57% of forecast midpoint 2021 production
hedged, forecast free cash flow would still be approximately
$100 million at an average 2021 WTI
oil price of US$43.50/Bbl.(1)
The Company has budgeted approximately $31 million for abandonment and reclamation
activities in 2021. Approximately $6
million is to be funded directly through the Alberta Site
Rehabilitation Program ("ASRP"), resulting in approximately
$25 million net to Paramount. The
majority of these funds will be directed to the Zama area.
____________________
|
(1)
|
"Free cash flow" is a
Non-GAAP financial measure. See "Non-GAAP Financial Measures" in
the Advisories section.
|
RESERVES (1)
- Despite a significant reduction in commodity price assumptions
used by the independent third-party reserves evaluator, Paramount's
2020 proved plus probable ("P+P") reserves were unchanged versus
2019 at 632 MMBoe while proved developed producing ("PDP") reserves
increased by 8% to 121 MMBoe. This reflects the Company's success
in sustainably reducing both its operating and capital cost
structure, as well as improvements in well performance. Optimizing
Paramount's 5-year capital program resulted in a 2020 total proved
("TP") reserves decrease of 7% to 311 MMBoe compared to 335 MMBoe
in 2019.
- Total undiscounted future development costs were reduced by
$962 million for TP reserves and by
$1,196 million for P+P reserves.
Further reductions may be realized if actual DCET costs continue to
be lower than the costs used by the Company's independent
third-party reserves evaluator in 2020.
- The liquids weighting of the Company's 2020 reserves remain
largely unchanged from 2019 (P+P 53% natural gas, 39% condensate
and oil, 8% other NGLs).
- The Company's reserves replacement ratio was 1.4x for PDP
reserves.
- PDP finding and development costs were $6.31/Boe in 2020.
- Estimated future net revenue at December
31, 2020, discounted at 10% before tax, totaled $1.9 billion for TP reserves and $3.6 billion for P+P reserves.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
Paramount has a long history of sustainable resource development
and environmental stewardship and is committed to creating value
for our stakeholders in an environmentally and socially responsible
manner. Environmental, Social and Governance ("ESG")
highlights in 2020 include:
- Publication of the Company's inaugural ESG report, which is
available on Paramount's website at
http://www.paramountres.com.
- Participation in the 2020 CDP Climate Change Survey.
- Completion of a multi-year project to replace approximately
1,900 high vent controllers with modern low or no vent units,
reducing Paramount's annual greenhouse gas emissions by an
estimated 75,000 tonnes of carbon dioxide equivalent
("tCO2e"). Information about Paramount's other emissions
reduction activities can be found in our ESG report.
- Paramount has implemented a corporate pandemic response plan
aimed at ensuring the health and safety of its staff and
contractors and the people they come in contact with. The Company
is conducting its operations in compliance with public health
requirements and guidelines, including providing additional
personal protective equipment and restricting access to its work
sites to critical personnel.
_________________
|
(1)
|
Readers are referred
to the advisories concerning "Reserves Data" and "Oil and Gas
Measures and Definitions" in the Advisories section of this
document. Reserves evaluated by McDaniel & Associates
Consultants Ltd. ("McDaniel") as of December 31, 2020 and December
31, 2019 in accordance with National Instrument 51-101 definitions,
standards and procedures. Reserves are gross reserves representing
working interest before royalties. Net present values of future net
revenue were determined using forecast prices and costs and do not
represent fair market value.
|
CORPORATE
- To provide greater certainty of free cash flow levels and the
funding of the Company's 2021 capital program, Paramount has hedged
approximately 57% of its 2021 forecast production. The Company's
current 2021 hedging position is summarized below:
-
- Natural Gas: approximately 67,400 MMBtu/d at US$2.73/MMBtu and approximately 89,200 GJ/d at
CDN$2.53/GJ over 2021.
- Oil: approximately 18,100 Bbl/d at US$46.35/Bbl in 2021 and 3,000 Bbl/d at
CDN$65.29/Bbl in the second and third
quarters.
- Condensate: 1,000 Bbl/d at US$WTI plus US$0.50/Bbl in the first quarter and 4,000 Bbl/d
at US$WTI plus US$0.06/Bbl in the
second quarter.
- Paramount's natural gas diversification strategy includes
arrangements to sell approximately 60,000 GJ/d of natural gas at
Dawn, approximately 22,000 GJ/d of natural gas at Malin, and 40,000
GJ/d of natural gas sales priced in the US Midwest.
- The Company's long-term debt at December
31, 2020 was $813 million. In
January 2021, Paramount's
$1.0 billion senior secured revolving
bank credit facility was amended to remove prior conditions on
facility availability in excess of $900
million. Concurrent with the amendments, the Company
completed a private placement of $35
million of senior unsecured convertible debentures.
- In March 2021, the Company
elected to exit the covenant relief period under its $1.0 billion bank credit facility prior to the
scheduled expiry of the period on June 30,
2021.
FINANCIAL AND
OPERATING RESULTS (1) ($ millions, except as
noted)
|
|
Three months ended
December 31
|
Twelve months
ended December 31
|
|
2020
|
|
2019
|
2020
|
2019
|
Net income
(loss)
|
311.5
|
|
(31.1)
|
|
(22.7)
|
(87.9)
|
per share – basic
and diluted ($/share)
|
2.35
|
|
(0.24)
|
|
(0.17)
|
(0.67)
|
Cash from
operating activities
|
53.2
|
|
70.5
|
|
80.9
|
255.7
|
per share – basic
and diluted ($/share)
|
0.40
|
|
0.54
|
|
0.61
|
1.96
|
Adjusted funds
flow
|
67.9
|
|
93.5
|
|
150.0
|
299.0
|
per share – basic
and diluted ($/share)
|
0.51
|
|
0.71
|
|
1.12
|
2.29
|
Total
assets
|
|
|
|
|
3,497.0
|
3,531.3
|
Long-term
debt
|
|
|
|
|
813.5
|
632.3
|
Net
debt
|
|
|
|
|
854.1
|
703.5
|
Common shares
outstanding (thousands) (2)
|
|
|
|
|
132,284
|
133,337
|
|
|
|
|
|
|
|
Sales
volumes
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
256.3
|
|
299.0
|
248.7
|
303.3
|
Condensate and oil
(Bbl/d)
|
25,752
|
|
28,516
|
22,565
|
25,079
|
Other NGLs
(Bbl/d) (3)
|
4,987
|
|
7,064
|
4,325
|
6,767
|
Total
(Boe/d)
|
73,460
|
|
85,411
|
68,340
|
82,394
|
%
liquids
|
42%
|
|
42%
|
39%
|
39%
|
Grande Prairie Region
(Boe/d)
|
37,782
|
|
36,789
|
31,076
|
29,040
|
Kaybob Region
(Boe/d)
|
27,056
|
|
33,167
|
28,685
|
35,500
|
Central Alberta and
Other Region (Boe/d)
|
8,622
|
|
15,455
|
8,579
|
17,854
|
Total
(Boe/d)
|
73,460
|
|
85,411
|
68,340
|
82,394
|
|
|
|
|
|
|
|
|
|
|
Netback
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
Natural gas
revenue
|
66.7
|
2.83
|
75.1
|
2.73
|
|
204.9
|
2.25
|
261.0
|
2.36
|
Condensate and oil
revenue
|
123.3
|
52.03
|
175.0
|
66.70
|
|
383.8
|
46.47
|
610.2
|
66.66
|
Other NGLs revenue
(3)
|
9.5
|
20.61
|
8.5
|
13.03
|
|
24.7
|
15.63
|
37.7
|
15.24
|
Royalty and other
revenue
|
2.5
|
─
|
1.3
|
─
|
|
12.6
|
─
|
6.0
|
─
|
Petroleum and
natural gas sales
|
202.0
|
29.89
|
259.9
|
33.08
|
|
626.0
|
25.03
|
914.9
|
30.42
|
Royalties
|
(11.7)
|
(1.73)
|
(17.2)
|
(2.19)
|
|
(31.3)
|
(1.25)
|
(63.3)
|
(2.10)
|
Operating
expense
|
(79.8)
|
(11.80)
|
(105.0)
|
(13.36)
|
|
(297.1)
|
(11.88)
|
(376.0)
|
(12.50)
|
Transportation and NGLs
processing (5)
|
(24.6)
|
(3.63)
|
(22.8)
|
(2.90)
|
|
(101.3)
|
(4.05)
|
(94.7)
|
(3.15)
|
Netback
|
85.9
|
12.73
|
114.9
|
14.63
|
|
196.3
|
7.85
|
380.9
|
12.67
|
Commodity
contract settlements
|
7.9
|
1.18
|
4.7
|
0.60
|
|
37.6
|
1.50
|
13.2
|
0.44
|
Netback including
commodity contract settlements
|
93.8
|
13.91
|
119.6
|
15.23
|
|
233.9
|
9.35
|
394.1
|
13.11
|
|
|
|
|
|
|
Total capital
expenditures
|
|
|
|
|
|
Grande Prairie Region
(6)
|
64.3
|
|
60.7
|
196.9
|
302.2
|
Kaybob
Region
|
1.8
|
|
9.5
|
16.4
|
80.7
|
Central Alberta and
Other Region
|
0.8
|
|
0.6
|
4.6
|
7.6
|
Corporate
(7)
|
(1.8)
|
|
─
|
2.3
|
6.0
|
Land and property
acquisitions
|
─
|
|
1.4
|
0.6
|
7.6
|
Total
|
65.1
|
|
72.2
|
220.8
|
404.1
|
|
|
|
|
|
|
Asset retirement
obligations settlements
|
0.1
|
|
18.0
|
35.0
|
29.4
|
(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. Readers are referred to the Product
Type Information section of this document for a complete breakdown
of sales volumes for applicable periods by specific product
type.
|
(2) Common
shares are presented net of shares held in trust under the
Company's restricted share unit plan (000's of common shares):
2020: 1,914; 2019: 860; 2018: 574.
|
(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) Total
capital expenditures for the year ended December 31, 2019 includes
$45.5 million of capital spending related to the Karr 6-18 natural
gas facility prior to its sale (three months ended December 31,
2019 – nil).
|
(7) Corporate
capital expenditures includes transfers between regions.
|
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 2020 annual results, including the Review of
Operations, Management's Discussion and Analysis and the Company's
Consolidated Financial Statements can be obtained at:
https://mma.prnewswire.com/media/1448762/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_2020_A.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#2020.
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at www.sedar.com.
PRODUCT TYPE INFORMATION
This press release refers to sales volumes of "liquids",
"natural gas", "condensate and oil" and "other
NGLs". "Liquids" means NGLs (including
condensate) and oil combined, "natural gas" refers to conventional
natural gas and shale gas combined, "condensate and oil" refers to
condensate, light and medium crude oil and tight oil combined and
"other NGLs" refers to ethane, propane and butane. Below is a
complete breakdown of sales volumes for applicable periods by
specific product type of shale gas, conventional natural gas, NGLs,
tight oil and light and medium crude oil. Numbers may not add
due to rounding.
|
Annual
|
|
Total
|
Grande Prairie
Region
|
Kabob
Region
|
Central Alberta
and
Other Region
|
|
2020
|
2019
|
2020
|
2019
|
2020
|
2019
|
2020
|
2019
|
Shale gas
(MMcf/d)
|
156.7
|
166.0
|
77.2
|
78.0
|
43.8
|
50.3
|
35.7
|
37.7
|
Conventional natural
gas (MMcf/d)
|
92.0
|
137.3
|
1.4
|
1.5
|
82.1
|
95.9
|
8.5
|
39.9
|
Natural gas
(MMcf/d)
|
248.7
|
303.3
|
78.6
|
79.5
|
125.9
|
146.2
|
44.2
|
77.6
|
Condensate
(Bbl/d)
|
19,334
|
19,746
|
15,991
|
13,920
|
2,885
|
4,361
|
458
|
1,464
|
Other NGLs
(Bbl/d)
|
4,325
|
6,767
|
1,964
|
1,814
|
1,812
|
2,476
|
549
|
2,477
|
NGLs
(Bbl/d)
|
23,659
|
26,513
|
17,955
|
15,734
|
4,697
|
6,837
|
1,007
|
3,941
|
Tight oil
(Bbl/d)
|
462
|
631
|
–
|
–
|
301
|
360
|
161
|
271
|
Light and Medium crude
oil (Bbl/d)
|
2,768
|
4,703
|
14
|
53
|
2,709
|
3,929
|
46
|
721
|
Crude oil
(Bbl/d)
|
3,230
|
5,334
|
14
|
53
|
3,010
|
4,289
|
207
|
992
|
Total
(Boe/d)
|
68,340
|
82,394
|
31,076
|
29,040
|
28,685
|
35,500
|
8,579
|
17,854
|
|
Q4
|
|
Total
|
Grande Prairie
Region
|
Kabob
Region
|
Central Alberta
and
Other Region
|
|
2020
|
2019
|
2020
|
2019
|
2020
|
2019
|
2020
|
2019
|
Shale gas
(MMcf/d)
|
170.7
|
176.6
|
92.7
|
91.5
|
41.9
|
48.3
|
36.1
|
36.8
|
Conventional natural
gas (MMcf/d)
|
85.6
|
122.4
|
1.6
|
1.9
|
76.3
|
89.1
|
7.7
|
31.4
|
Natural gas
(MMcf/d)
|
256.3
|
299.0
|
94.3
|
93.4
|
118.2
|
137.4
|
43.8
|
68.2
|
Condensate
(Bbl/d)
|
22,782
|
23,956
|
19,635
|
18,760
|
2,631
|
3,899
|
515
|
1,298
|
Other NGLs
(Bbl/d)
|
4,987
|
7,064
|
2,429
|
2,376
|
1,953
|
2,504
|
605
|
2,184
|
NGLs
(Bbl/d)
|
27,769
|
31,020
|
22,064
|
21,136
|
4,584
|
6,403
|
1,120
|
3,482
|
Tight oil
(Bbl/d)
|
437
|
745
|
–
|
–
|
299
|
541
|
138
|
203
|
Light and Medium crude
oil (Bbl/d)
|
2,533
|
3,815
|
–
|
91
|
2,480
|
3,331
|
54
|
393
|
Crude oil
(Bbl/d)
|
2,970
|
4,560
|
–
|
91
|
2,779
|
3,872
|
192
|
596
|
Total
(Boe/d)
|
73,460
|
85,411
|
37,782
|
36,789
|
27,056
|
33,167
|
8,622
|
15,455
|
Fourth quarter 2020 sales volumes at Karr averaged 26,914 Boe/d
(69.6 MMcf/d of shale gas, 0.9 MMcf/d of conventional natural gas
and 15,165 Bbl/d of NGLs), compared to 19,246 Boe/d (48.6 MMcf/d of
shale gas, 0.6 MMcf/d of conventional natural gas and 11,044 Bbl/d
of NGLs) in the third quarter of 2020. Fourth quarter 2020 sales
volumes at Wapiti averaged 10,764 Boe/d (22.8 MMcf/d of shale gas,
0.5 MMcf/d of conventional natural gas and 6,875 Bbl/d of NGLs),
compared to 7,925 Boe/d (17.4 MMcf/d of shale gas, 0.4 MMcf/d of
conventional natural gas and 4,962 Bbl/d of NGLs) in the third
quarter of 2020.
The Company forecasts that 2021 sales volumes will average
between 77,000 Boe/d and 80,000 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). First
half 2021 sales volumes are expected to average between 74,000
Boe/d and 76,000 Boe/d (57% shale gas and conventional natural gas
combined, 37% light and medium crude oil, tight oil and condensate
combined and 6% other NGLs). Second half 2021 sales volumes are
expected to increase to average between 80,000 Boe/d and 84,000
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).
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 2021 and the timing and
allocation thereof;
- forecast sales volumes for 2021 and certain periods within
2021;
- forecast free cash flow in 2021;
- planned exploration, development and production activities,
including the expected timing of completing and bringing new wells
on production;
- planned abandonment and reclamation expenditures and activities
in 2021 and anticipated funding under the ASRP;
- planned facility outages and turnarounds;
- the potential to realize further reductions in future
development costs if actual DCET costs continue to be lower than
the costs used by the Company's independent third-party reserves
evaluator in 2020; and
- expected GHG reductions associated with controller
upgrades.
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; 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).
Statements relating to reserves are also deemed to be forward
looking statements, as they involve the implied assessment, based
on certain estimates and assumptions, that the reserves described
exist in the quantities predicted or estimated and that the
reserves can be profitably produced in the future.
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 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;
- 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, 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, 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.
Non-GAAP Financial Measures
In this press release, "Adjusted funds flow", "Netback", "Free
cash flow", "Net Debt" and "Total Capital Expenditure", 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 operating activities
before net changes in non-cash working capital, geological and
geophysical expenses, asset retirement obligation settlements,
closure costs, transaction and reorganization costs, provision and
other and dispute settlements. 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 and twelve months ended
December 31, 2020 and December 31, 2019:
Year ended
December 31
|
|
|
2020
(MM$)
|
2019
(MM$)
|
Cash from
operating activities
|
|
|
80.9
|
255.7
|
Change in non-cash
working capital
|
|
|
17.9
|
(15.9)
|
Geological and
geophysical expenses
|
|
|
8.5
|
11.0
|
Asset retirement
obligations settled
|
|
|
35.0
|
29.4
|
Closure
costs
|
|
|
─
|
14.0
|
Transaction and
reorganization costs
|
|
|
3.0
|
2.3
|
Provision and
other
|
|
|
4.7
|
2.5
|
Adjusted funds
flow
|
|
|
150.0
|
299.0
|
Three months ended
December 31
|
|
|
2020
(MM$)
|
2019
(MM$)
|
Cash from
operating activities
|
|
|
53.2
|
70.5
|
Change in non-cash
working capital
|
|
|
12.5
|
(8.0)
|
Geological and
geophysical expenses
|
|
|
2.1
|
3.5
|
Asset retirement
obligations settled
|
|
|
0.1
|
18.0
|
Closure
costs
|
|
|
─
|
4.7
|
Transaction and
reorganization costs
|
|
|
─
|
2.3
|
Dispute
settlements
|
|
|
─
|
2.5
|
Adjusted funds
flow
|
|
|
67.9
|
93.5
|
"Free cash flow" refers to adjusted funds flow less total
capital expenditures and asset retirement obligation
settlements. Free cash flow is used by management and
investors to assess the amount of internally generated cash
available to repay debt, reinvest in the business or return to
shareholders. The following is the calculation of free cash
flow from the nearest GAAP measure for the three months ended
December 31, 2020:
Three months ended
December 31
|
|
|
2020
(MM$)
|
Cash from
operating activities
|
|
|
53.2
|
Change in non-cash
working capital
|
|
|
12.5
|
Geological and
geophysical expenses
|
|
|
2.1
|
Asset retirement
obligations settled
|
|
|
0.1
|
Closure
costs
|
|
|
─
|
Transaction and
reorganization costs
|
|
|
─
|
Provision and
other
|
|
|
─
|
Adjusted funds
flow
|
|
|
67.9
|
Total capital
expenditures
|
|
|
(65.1)
|
Asset retirement
obligation settlements
|
|
|
(0.1)
|
Free cash
flow
|
|
|
2.7
|
"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 Management's Discussion and Analysis for
the year ended December 31, 2020 (the
"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 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.
Reserves Data
Reserves data set forth in this press release is based upon an
evaluation of the Company's reserves prepared by McDaniel &
Associates Consultants Ltd. ("McDaniel") dated March 2, 2021 and effective December 31, 2020 (the "McDaniel Report").
The price forecast used in the McDaniel Report is an average of the
January 1, 2021 price forecasts for
McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2020 price forecast of Sproule
Associates Ltd. The estimates of reserves contained in the
McDaniel Report and referenced in this press release are estimates
only and there is no guarantee that the estimated reserves will be
recovered. Actual reserves may be greater than or less than
the estimates contained in the McDaniel Report and referenced in
this press release. There is no assurance that the forecast
prices and costs assumptions used in the McDaniel Report will be
attained, and variances could be material. Estimated future
net revenue does not represent fair market value. The
estimates of reserves for individual properties may not reflect the
same confidence level as estimates of reserves for all properties,
due to the effects of aggregation. Readers should refer to the
Company's annual information form for the year ended December 31, 2020, which is available on SEDAR at
www.sedar.com, for a complete description of the McDaniel Report
(including reserves by specific product type of shale gas,
conventional natural gas, NGLs, tight oil and light and medium
crude oil) and the material assumptions, limitations and risk
factors pertaining thereto.
Oil and Gas Measures and Definitions
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 year ended December 31,
2020, the value ratio between crude oil and natural gas was
approximately 21:1. This value ratio is significantly different
from the energy equivalency ratio of 6:1. Using a 6:1 ratio would
be misleading as an indication of value.
This press release contains metrics commonly used in the oil and
natural gas industry. Each of these metrics is determined by the
Company as set out below or elsewhere in this press release. The
metrics are "CGR", "reserves replacement ratio" and "finding and
development costs". These metrics do not have standardized meanings
and may not be comparable to similar measures presented by other
companies. As such, they should not be used to make comparisons.
Management uses these oil and gas metrics for its own performance
measurements and to provide shareholders with measures to compare
the Company's performance over time; however, such measures are not
reliable indicators of the Company's future performance and future
performance may not compare to the performance in previous periods
and therefore should not be unduly relied upon.
"CGR" means condensate to gas ratio and is calculated by
dividing wellhead raw liquids volumes by wellhead raw natural gas
volumes.
"Reserves replacement ratio" is calculated by dividing: (i) the
net changes in reserves from the prior year from
extensions/improved recovery, technical revisions and economic
factors, by (ii) the aggregate production during the year.
Reserves replacement ratio is a measure commonly used by management
and investors to assess the rate at which reserves depleted by
production are being replaced by reserves added through
operations.
"Finding and development costs" are calculated by dividing: (i)
total capital expenditures for the period (excluding corporate
expenditures and land and property acquisitions) by (ii) the net
changes in reserves from the prior year from extensions/improved
recovery, technical revisions and economic factors. Finding and
development costs are a measure commonly used by management and
investors to assess the relationship between capital invested in
oil and gas exploration and development projects and reserve
additions associated with such projects.
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.