CALGARY, AB, May 5, 2021 /CNW/ -
HIGHLIGHTS
- Sales volumes averaged 80,540 Boe/d (43% liquids) in the first
quarter of 2021, well ahead of the Company's first half 2021
production guidance of 74,000 Boe/d to 76,000 Boe/d (43% liquids)
due to significant outperformance at Karr as well as higher than
expected field reliability corporately. (1)
-
- Sales volumes at Karr averaged 33,230 Boe/d (55% liquids) in
the quarter compared to 26,914 Boe/d (56% liquids) in the fourth
quarter of 2020.
-
- This increase was driven by strong performance from the six
well 3-10 pad that was brought onstream in February and the five
well 5-16 West pad that was brought onstream in the fourth quarter
of 2020, as well as workovers on the 16-4 pad that were completed
in the fourth quarter of 2020.
- Paramount achieved an important milestone at Karr, with first
quarter exit sales volumes exceeding targeted plateau production of
40,000 Boe/d for the first time and March sales volumes averaging
39,938 Boe/d (53% liquids). Paramount estimates that 12 to 16 new
wells per year will be required to maintain plateau production.
- At plateau production of 40,000 Boe/d, annual asset level free
cash flow at Karr would be $260
million to $290 million.
(2)
- Sales volumes at Wapiti averaged 14,107 Boe/d (62% liquids) in
the quarter compared to 10,764 Boe/d (64% liquids) in the fourth
quarter of 2020. The 31% increase in sales volumes was primarily
due to new well production from the 5-3 West pad that was brought
onstream partway through the fourth quarter.
________________________________________
|
(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)
|
"Asset level free
cash flow" is a Non-GAAP financial measure. See "Non-GAAP Financial
Measures" in the Advisories section. Stated amounts are
illustrative assuming Karr per-unit netbacks of $26.00/Boe,
consistent with the first quarter of 2021, and 12 to 16 new wells
per year at an average DCET cost of $7.5 million per well and
excludes the cost of any potential incremental infrastructure
requirements in the future.
|
- First quarter capital spending totaled $59.3 million, which was focused on drilling and
completion activities at Karr and Wapiti.
-
- All-in lease construction, drilling, completion, equip and
tie-in (collectively "DCET") costs for the six well Karr 3-10 pad
averaged a pacesetting $6.8 million
per well, $0.2 million lower per well
than prior estimates and representing a 12% reduction relative to
average DCET costs for Karr wells in 2020.
- Preliminary DCET costs at the three well Karr 4-28 pad, which
was brought on production in late April
2021, were $6.9 million per
well.
- Paramount's continued focus on strong execution, cost control
and innovation has contributed to anticipated cost savings of
$30 million in the Company's 2021
capital program.
- Abandonment and reclamation expenditures in the first quarter
totaled $8.4 million, net of
$1.7 million in funding under the
Alberta Site Rehabilitation Program. Activities included the
abandonment of 120 wells, 119 of which were abandoned under the
Company's ongoing area-based closure program at Zama.
- Cash from operating activities was $81.3
million in the first quarter. Adjusted funds flow was
$90.9 million or $0.69 per share. (1)
- Paramount generated $23.2 million
of free cash flow in the first quarter that, along with
approximately $80 million in cash
proceeds from non-core dispositions, was directed to debt
reduction. (1)
- Free cash flow in 2021 is expected to be directed towards debt
reduction, with anticipated year-end 2021 net debt to adjusted
funds flow of less than 1.5x.(1)
______________________________
|
(1)
|
"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.
|
NON-CORE ASSET DISPOSITION
Paramount has entered into a definitive agreement for the sale
of its non-operated Birch asset in northeast British Columbia for total consideration of
approximately $77 million (the "Birch
Disposition"). Closing is subject to customary conditions and
is anticipated to occur in early July. Estimated second half
2021 production from the asset, net to Paramount, was approximately
1,900 Boe/d.
REVISED 2021 GUIDANCE
Paramount is increasing its 2021 sales volume forecast as a
result of strong year-to-date performance. Sales volumes in 2021
are now expected to average between 80,000 Boe/d and
82,000 Boe/d (44% liquids) after taking into account the Birch
Disposition. This is an increase from previous guidance
of 77,000 Boe/d to 80,000 Boe/d (45% liquids).
Second quarter 2021 sales volumes are expected to average
between 77,000 Boe/d and 78,000 Boe/d (42% liquids). Second
half 2021 sales volumes guidance remains unchanged at between
80,000 Boe/d and 84,000 Boe/d (45% liquids) notwithstanding the
Birch Disposition.
The Company will be advancing approximately $60 million of activities in the Wapiti area by
six months into the second half of 2021, capitalizing on the
$30 million of anticipated cost
savings in its 2021 capital program, incremental cash flow
generation in light of higher production guidance and the Birch
Disposition. Accordingly, the Company's capital budget for
2021 is being increased to between $265
million and $285
million, excluding land acquisitions and abandonment
and reclamation activities. This is an increase of $30
million at the mid-point from the previous guidance range of
between $230 million and $260 million. Additional activities at
Wapiti will include drilling, completing and bringing onstream the
seven well 9-22 pad, the tie-in of a pre-existing well from the
10-22 pad and the installation of associated infrastructure.
Initial production from these activities is anticipated to come
onstream in December 2021.
Inclusive of the increased capital at Wapiti, Paramount
forecasts 2021 free cash flow of approximately $140 million. This 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 $39.50/Boe (US$60.84/Bbl WTI, US$2.84/MMBtu NYMEX, $2.78/GJ AECO), (iv) royalties of $2.60/Boe, (v) operating costs of $11.30/Boe and (vi) transportation and processing
costs of $3.85/Boe.
Approximately 52% of forecast midpoint production is hedged over
the final three quarters of 2021. After taking such hedging into
account, 2021 forecast free cash flow would still be approximately
$60 million at an average WTI oil
price of US$40.00/Bbl over the final
three quarters of the year and would rise to $155 million at an average WTI oil price of
US$65.00/Bbl over the final three
quarters of the year.
The Company targets net debt to adjusted funds flow of between
1.0x and 2.0x. Free cash flow in 2021 is expected to be
directed towards debt reduction, with anticipated year-end net
debt to adjusted funds flow of less than 1.5x. The
Company currently prioritizes the allocation of free cash flow to:
(i) achieving the targeted range of net debt to adjusted funds
flow; (ii) shareholder returns; and (iii) incremental
growth.
PRELIMINARY 2022 GUIDANCE
Paramount expects to finalize its 2022 capital budget and
related guidance in the first quarter of 2022. Based on
preliminary planning and current market conditions, Paramount
anticipates 2022 capital spending, excluding land acquisitions and
abandonment and reclamation activities, to range between
$325 million and $385 million, broken down as follows:
- $250 million of sustaining
capital and maintenance activities;
- $75 million of growth capital
with production benefits in 2022; and
- $60 million of discretionary
growth capital with production benefits largely in 2023.
A capital program in this range would be expected to result in
2022 annual average sales volumes of between 84,000 Boe/d and
88,000 Boe/d (45% liquids) and free cash flow of approximately
$185 million. The free cash
flow estimate is based on the following assumptions for 2022: (i)
the midpoint of forecast capital spending and production, (ii)
$30 million in abandonment and
reclamation costs, (iii) realized pricing of $37.25/Boe (US$57.78/Bbl WTI, US$2.71/MMBtu NYMEX, $2.43/GJ AECO), (iv) royalties of $2.35/Boe, (v) operating costs of $11.10/Boe and (vi) transportation and processing
costs of $3.75/Boe. If all
expected free cash flow was directed towards debt reduction,
anticipated year-end 2022 net debt to adjusted funds flow would be
significantly less than 1.0x.
CORPORATE
The Company successfully closed non-core asset dispositions for
cash proceeds of approximately $80
million in the first quarter of 2021.
In May 2021, Moody's Investors
Service Inc. assigned a "B2" corporate family rating to the Company
with a positive outlook and S&P Global Ratings assigned its
"B-" issuer credit rating to the Company with a positive
outlook.
Paramount continues to evaluate and pursue opportunities to
provide environmentally sustainable value creation for its
stakeholders. Advancements in technology paired with
government incentive programs have the potential to create
stakeholder benefits from both a greenhouse gas ("GHG") emissions
reduction and economic perspective.
The Company has engaged an outside engineering firm and is
working with Clean Energy Systems, Inc. ("CES") to assess the
opportunity for ultra-low emission upgrades to one of the Company's
facilities. The project envisions deploying CES's
oxy-combustion technology with CO2 capture to eliminate
GHG emissions and generate excess electricity. The captured
CO2 could be used for enhanced oil recovery in a
Paramount owned and operated oil development or sequestered using
the facility's existing H2S and CO2 disposal
system. The CES technology also provides an opportunity to
treat produced water that can be used in place of fresh water for
Paramount's future developments. Paramount has held an
indirect ownership interest in CES (through its investment in
Paxton Corporation) for over a decade and is excited about the
prospects for this technology.
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Grande Prairie Region sales volumes and netbacks are summarized
below:(1)
|
Q1
2021
|
Q4
2020
|
%Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
122.6
|
94.3
|
30
|
Condensate and oil
(Bbl/d)
|
23,974
|
19,635
|
22
|
Other NGLs
(Bbl/d)
|
2,984
|
2,429
|
23
|
Total
(Boe/d)
|
47,385
|
37,782
|
25
|
%
liquids
|
57%
|
58%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
194.0
|
45.50
|
125.1
|
36.00
|
55
|
Royalties
|
(11.6)
|
(2.72)
|
(6.2)
|
(1.78)
|
87
|
Operating
expense
|
(49.0)
|
(11.49)
|
(42.4)
|
(12.20)
|
16
|
Transportation and NGLs
processing
|
(20.0)
|
(4.69)
|
(14.2)
|
(4.07)
|
41
|
|
113.4
|
26.60
|
62.3
|
17.95
|
82
|
________________________________
|
(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:
|
Q1
2021
|
Q4
2020
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
90.2
|
70.5
|
28
|
Condensate and oil
(Bbl/d)
|
16,095
|
13,348
|
21
|
Other NGLs
(Bbl/d)
|
2,108
|
1,817
|
16
|
Total
(Boe/d)
|
33,230
|
26,914
|
23
|
%
liquids
|
55%
|
56%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
132.5
|
44.31
|
86.1
|
34.79
|
54
|
Royalties
|
(8.6)
|
(2.89)
|
(4.6)
|
(1.87)
|
87
|
Operating
expense
|
(31.9)
|
(10.67)
|
(27.8)
|
(11.24)
|
15
|
Transportation and NGLs
processing
|
(14.0)
|
(4.68)
|
(10.5)
|
(4.26)
|
33
|
|
78.0
|
26.07
|
43.2
|
17.42
|
81
|
First quarter sales volumes at Karr averaged 33,230 Boe/d (55%
liquids) compared to 26,914 Boe/d (56% liquids) in the fourth
quarter of 2020. Sales volumes increased as a result of new
well production that came onstream in the first quarter and from a
full quarter of production from wells that came onstream in the
fourth quarter of 2020. Incremental production from existing
wells following workovers in the fourth quarter of 2020 also
contributed to the overall increase.
The 3-10 pad has continued to outperform internal type well
projections, averaging gross peak 30-day production per well of
2,068 Boe/d (6.0 MMcf/d of shale gas and 1,073 Bbl/d of NGLs) with
an average CGR of 180 Bbl/MMcf.(1)
Likewise, production at the five well 5-16 West pad that came
onstream in November 2020 continues
to exhibit higher initial production rates than predicted by the
type well. This performance, along with higher than
anticipated production from the two well 16-4 pad, post-workover,
combined to increase first quarter production above prior
projections.
Three new Montney wells on the
4-28 pad were brought onstream in late April. Pressure data
collected pre-completion from the pad confirms the northeast
portion of Karr is in the over-pressured window of the
Montney. This new data has resulted in an adjustment of the
over-pressured boundary to the east of Karr and has increased the
potential well inventory.
Additional gas lift compression was recently installed to
support base and incremental production in the area. The
Company anticipates base production up-lift at a number of pads
that had been impacted by insufficient lift gas supply.
Per unit operating costs trended lower as a result of higher
production volumes combined with a continued focus on cost
reduction initiatives. The Company achieved per unit
operating costs of $10.67/Boe in the
first quarter of 2021 and anticipates operating costs of
approximately $10.00/Boe at plateau
production levels.
Paramount continues to focus on driving DCET costs lower while
maintaining well performance and in the first quarter realized cost
improvements relative to the most recent pacesetting results.
All-in DCET costs at the six well 3-10 pad averaged a pacesetting
$6.8 million per well, $0.2 million lower per well than prior estimates
and representing a 12% reduction relative to average DCET costs for
Karr wells in 2020. Preliminary DCET costs at the three well
4-28 pad averaged $6.9 million per
well.
Drilling operations at the five well 7-18 pad were completed in
the first quarter under budget and included one new pacesetter
well, drilling an average 313 meters per day. Paramount plans
to complete, tie-in and bring on production all five wells on the
7-18 pad by the third quarter. Drilling of the five well 5-16
East pad recently commenced, and the Company plans to complete,
tie-in and bring on production all five wells by the fourth
quarter. Paramount anticipates commencing drilling operations
on the ten well 16-17 pad in the fourth quarter and expects that
seven wells will be drilled by year end.
Production in the second quarter will be impacted by scheduled
curtailments at the third-party Karr 6-18 facility related to inlet
separation and liquids handling optimization. The
curtailments are anticipated to reduce sales volumes by
approximately 50% for seven days in May.
_________________________________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 7% and liquids sales volumes are lower by
approximately 7% due to shrinkage. Excludes days when the wells did
not produce. The production rates and volumes stated are over a
short period of time and, therefore, are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells. CGR means condensate to gas ratio and is
calculated by dividing raw wellhead liquids volumes by raw wellhead
natural gas volumes. See Oil and Gas Measures and Definitions in
the Advisories section.
|
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
|
Q1
2021
|
Q4
2020
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
32.1
|
23.3
|
38
|
Condensate and oil
(Bbl/d)
|
7,884
|
6,286
|
25
|
Other NGLs
(Bbl/d)
|
867
|
589
|
47
|
Total
(Boe/d)
|
14,107
|
10,764
|
31
|
%
liquids
|
62%
|
64%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
61.4
|
48.42
|
38.9
|
39.30
|
58
|
Royalties
|
(2.9)
|
(2.32)
|
(1.6)
|
(1.58)
|
81
|
Operating
expense
|
(16.8)
|
(13.25)
|
(14.2)
|
(14.36)
|
18
|
Transportation and NGLs
processing
|
(6.0)
|
(4.73)
|
(3.6)
|
(3.62)
|
67
|
|
35.7
|
28.12
|
19.5
|
19.74
|
83
|
First quarter sales volumes at Wapiti averaged 14,107 Boe/d (62%
liquids), 3,343 Boe/d higher than in the fourth quarter of 2020
primarily due to new well production from the 5-3 West pad that was
brought onstream partway through the fourth quarter.
Drilling operations were completed at the seven well 6-4 pad in
the first quarter, $4.4 million under
budget for the pad. A pilot project to test the
viability of monobore drilling techniques on two wells on the 6-4
pad was successful. Lower drilling and completion costs and
higher frac fluid pumping rates in the wellbore compared to
conventional multiple casing wellbores are anticipated to further
enhance the economics and productivity of these wells. The
Company anticipates completing and bringing on production all seven
wells by the third quarter.
In the first quarter Paramount tied its Wapiti gas lift
infrastructure into the high-pressure gas gathering system managed
by the third-party operator of the Wapiti natural gas processing
plant. This new connection provides Wapiti area wells with a
more reliable source of lift gas which is anticipated to reduce the
time required to re-start wells after turnarounds, workovers and
other disruptions.
The 2021 capital program at Wapiti is being expanded to bring
forward activities by approximately six months to advance the next
major phase of development. Activities include drilling,
completing and bringing onstream the seven well 9-22 pad, the
tie-in of a pre-existing well from the 10-22 pad and the
installation of associated infrastructure. Initial production
from these activities is anticipated to come onstream in
December 2021.
KAYBOB REGION
Kaybob Region sales volumes averaged 24,938 Boe/d (28% liquids)
in the first quarter of 2021 compared to 27,056 Boe/d (27% liquids)
in the fourth quarter of 2020. Production in the Kaybob
Region was relatively flat after adjusting for the impact of
non-core asset dispositions in the first quarter. The Company
completed and recently brought on production one Montney oil well in Ante Creek that was
drilled in 2020.
Paramount holds material positions in Duvernay and Montney resource plays in the Kaybob Region
that will compete for capital in the medium term.
CENTRAL ALBERTA AND OTHER
REGION
Central Alberta and Other
Region sales volumes averaged 8,217 Boe/d (14% liquids) in the
first quarter compared to 8,622 (15% liquids) in the fourth quarter
of 2020.
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 operations are ongoing at a
two well, liquids rich Duvernay
pad in the Willesden Green area and Paramount plans to complete,
tie-in and bring on production both wells in the second half of the
year.
HEDGING
The Company's commodity hedging position at March 31, 2021 is summarized below:
- Natural Gas:
April – December 2021
60,000 MMBtu/d at US$2.71/MMBtu
April – October
2021
50,000 GJ/d at CDN$2.52/GJ
April – December
2021
50,000 GJ/d at CDN$2.51/GJ
- Oil:
April – June
2021
23,000 Bbl/d at US$46.93/Bbl
July – September
2021
15,000 Bbl/d at US$45.87/Bbl
October – December
2021
10,000 Bbl/d at US$45.82/Bbl
April – September
2021 3,000
Bbl/d at CDN$65.29/Bbl
The Company has also hedged the differential on 4,000 Bbl/d of
condensate at Edmonton for the
second quarter at WTI plus US$0.06/Bbl.
Further details of Paramount's commodity hedging position are
provided in its first quarter 2021 Management's Discussion and
Analysis and Consolidated Financial Statements.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused
Canadian energy company that explores for and develops both
conventional and unconventional petroleum and natural gas reserves
and resources, including longer-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are located in
Alberta and British Columbia. Paramount's class A common
shares are listed on the Toronto Stock Exchange under the symbol
"POU".
Paramount's first quarter 2021 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at:
https://mma.prnewswire.com/media/1503692/Paramount_Resources_Ltd_Announces_Q1_2021_Results.pdf .
A summary of historical financial and operating results is also
available on Paramount's website at
http://www.paramountres.com/investor-relations/financial-reports#2021.
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at
www.sedar.com.
FINANCIAL AND
OPERATING RESULTS (1)
($ millions,
except as noted)
|
|
|
|
Q1
2021
|
Q4
2020
|
Net income
(loss)
|
|
|
|
|
(82.5)
|
311.5
|
per share – basic
and diluted ($/share)
|
|
|
|
|
(0.62)
|
2.35
|
Cash from
operating activities
|
|
|
|
|
81.3
|
53.2
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.61
|
0.40
|
Adjusted funds
flow
|
|
|
|
|
90.9
|
67.9
|
per share – basic
and diluted ($/share)
|
|
|
|
|
0.69
|
0.51
|
Total
assets
|
|
|
|
|
3,583.1
|
3,497.0
|
Long-term
debt
|
|
|
|
|
712.7
|
813.5
|
Net
debt
|
|
|
|
|
761.7
|
854.1
|
Common shares
outstanding (thousands)(2)
|
|
|
|
|
132,754
|
132,284
|
|
|
|
|
|
|
|
Sales
volumes
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
|
273.1
|
256.3
|
Condensate and oil
(Bbl/d)
|
|
|
29,854
|
25,752
|
Other NGLs
(Bbl/d) (3)
|
|
|
5,170
|
4,987
|
Total
(Boe/d)
|
|
|
80,540
|
73,460
|
%
liquids
|
|
|
43%
|
42%
|
|
|
|
|
|
Grande Prairie Region
(Boe/d)
|
|
|
47,385
|
37,782
|
Kaybob Region
(Boe/d)
|
|
|
24,938
|
27,056
|
Central Alberta and
Other Region (Boe/d)
|
|
|
8,217
|
8,622
|
Total
(Boe/d)
|
|
|
80,540
|
73,460
|
|
|
|
|
|
|
|
|
|
Netback
|
|
|
|
|
|
$/Boe
(4)
|
|
$/Boe
(4)
|
Natural gas
revenue
|
|
|
|
|
77.3
|
3.14
|
66.7
|
2.83
|
Condensate and oil
revenue
|
|
|
|
|
185.9
|
69.20
|
123.3
|
52.03
|
Other NGLs revenue
(3)
|
|
|
|
|
15.0
|
32.29
|
9.5
|
20.61
|
Royalty and other
revenue
|
|
|
|
|
1.7
|
─
|
2.5
|
─
|
Petroleum and
natural gas sales
|
|
|
|
|
279.9
|
38.61
|
202.0
|
29.89
|
Royalties
|
|
|
|
|
(18.6)
|
(2.57)
|
(11.7)
|
(1.73)
|
Operating
expense
|
|
|
|
|
(84.3)
|
(11.63)
|
(79.8)
|
(11.80)
|
Transportation and NGLs
processing (5)
|
|
|
|
|
(27.9)
|
(3.84)
|
(24.6)
|
(3.63)
|
Netback
|
|
|
|
|
149.1
|
20.57
|
85.9
|
12.73
|
Financial commodity
contract settlements
|
|
|
|
|
(32.7)
|
(4.51)
|
7.9
|
1.18
|
Netback including
financial commodity contract settlements
|
116.4
|
16.06
|
93.8
|
13.91
|
Total Capital
Expenditures
|
|
|
|
|
Grande Prairie
Region
|
|
|
51.3
|
64.3
|
Kaybob
Region
|
|
|
5.0
|
1.8
|
Central Alberta and
Other Region
|
|
|
1.2
|
0.8
|
Corporate
(6)
|
|
|
1.8
|
(1.8)
|
Total capital
expenditures
|
|
|
59.3
|
65.1
|
Asset retirement
obligation settlements
|
|
|
8.4
|
0.1
|
(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 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): Q1 2021: 1,914
and Q4 2020: 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
|
Kabob Region
|
Central Alberta
and
Other Region
|
|
Q1
2021
|
Q4
2020
|
Q1
2021
|
Q4
2020
|
Q1
2021
|
Q4
2020
|
Q1
2021
|
Q4
2020
|
Shale gas
(MMcf/d)
|
197.8
|
170.7
|
120.6
|
92.7
|
42.1
|
41.9
|
35.1
|
36.1
|
Conventional natural
gas (MMcf/d)
|
75.3
|
85.6
|
2.0
|
1.6
|
65.8
|
76.3
|
7.5
|
7.7
|
Natural gas
(MMcf/d)
|
273.1
|
256.3
|
122.6
|
94.3
|
107.9
|
118.2
|
42.6
|
43.8
|
Condensate
(Bbl/d)
|
27,017
|
22,782
|
23,974
|
19,635
|
2,611
|
2,631
|
433
|
515
|
Other NGLs
(Bbl/d)
|
5,170
|
4,987
|
2,984
|
2,429
|
1,677
|
1,953
|
509
|
605
|
NGLs
(Bbl/d)
|
32,187
|
27,769
|
26,958
|
22,064
|
4,288
|
4,584
|
942
|
1,120
|
Tight oil
(Bbl/d)
|
479
|
437
|
–
|
–
|
342
|
299
|
136
|
138
|
Light and Medium crude
oil (Bbl/d)
|
2,358
|
2,533
|
–
|
–
|
2,321
|
2,480
|
37
|
54
|
Crude oil
(Bbl/d)
|
2,837
|
2,970
|
–
|
–
|
2,663
|
2,779
|
173
|
192
|
Total
(Boe/d)
|
80,540
|
73,460
|
47,385
|
37,782
|
24,938
|
27,056
|
8,217
|
8,622
|
|
Karr
|
Wapiti
|
|
Q1 2021
|
Q4
2020
|
Q1
2021
|
Q4
2020
|
Shale gas
(MMcf/d)
|
89.1
|
69.6
|
31.5
|
22.8
|
Conventional natural
gas (MMcf/d)
|
1.1
|
0.9
|
0.6
|
0.5
|
Natural gas
(MMcf/d)
|
90.2
|
70.5
|
32.1
|
23.3
|
NGLs
(Bbl/d)
|
18,203
|
15,165
|
8,751
|
6,875
|
Total
(Boe/d)
|
33,230
|
26,914
|
14,107
|
10,764
|
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
quarter 2021 sales volumes are expected to average between 77,000
Boe/d and 78,000 Boe/d (58% shale gas and conventional natural gas
combined, 36% 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 estimated number of wells required per year to maintain
plateau production at Karr;
- illustrative asset level free cash flow at Karr at plateau
production;
- anticipated cost savings in the Company's 2021 capital
program;
- the anticipated closing of the Birch Disposition;
- forecast sales volumes for 2021 and certain periods
therein;
- forecast free cash flow in 2021;
- planned capital expenditures in 2021;
- planned abandonment and reclamation expenditures in 2021;
- the Company's expectation that 2021 free cash flow will be
directed towards debt reduction;
- forecast 2021 year-end net debt to annual adjusted funds
flow;
- 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;
- planned exploration, development and production activities,
including the expected timing of completing and bringing new wells
on production;
- scheduled facility curtailments at Karr and the anticipated
impact thereof;
- anticipated operating costs;
- the expected benefits of monobore drilling techniques; and
- the expected benefits of additional gas lift compression
at Karr and new gas lift infrastructure at Wapiti.
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 satisfaction of the conditions to closing of the Birch
Disposition;
- 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. There are no assurances that the Birch
Disposition will close at the anticipated time or at all.
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;
- the failure to satisfy the conditions to closing of the Birch
Disposition;
- 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, free cash flow and
year-end net debt to adjusted funds 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.
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", "asset level free
cash 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 operating activities
before net changes in non-cash working capital, geological and
geophysical expenses, asset retirement obligation settlements and
provision. 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 March 31, 2021 and December 31, 2020:
Three months
ended
|
|
|
March 31,
2021
(MM$)
|
Dec 31,
2020
(MM$)
|
Cash from
operating activities
|
|
|
81.3
|
53.2
|
Change in non-cash
working capital
|
|
|
(7.9)
|
12.5
|
Geological and
geophysical expenses
|
|
|
1.6
|
2.1
|
Asset retirement
obligations settled
|
|
|
8.4
|
0.1
|
Provision
|
|
|
7.5
|
–
|
Adjusted funds
flow
|
|
|
90.9
|
67.9
|
"Asset level free cash flow" refers to aggregate netback from an
asset during the period less capital expenditures with respect to
such asset for the period. Asset level free cash flow is used
by management and investors to assess the cash generating capacity
of an asset.
"Free cash flow" refers to adjusted funds flow less total
capital expenditures and asset retirement obligation
settlements. Free cash flow is used by management and
investors to assess the amount of internally generated cash
available to repay debt, reinvest in the business or return to
shareholders. The following is the calculation of free cash
flow from the nearest GAAP measure for the three months ended
March 31, 2021:
Three months
ended
|
|
|
March 31,
2021
(MM$)
|
Cash from
operating activities
|
|
|
81.3
|
Change in non-cash
working capital
|
|
|
(7.9)
|
Geological and
geophysical expenses
|
|
|
1.6
|
Asset retirement
obligations settled
|
|
|
8.4
|
Provision
|
|
|
7.5
|
Adjusted funds
flow
|
|
|
90.9
|
Total capital
expenditures
|
|
|
(59.3)
|
Asset retirement
obligation settlements
|
|
|
(8.4)
|
Free cash
flow
|
|
|
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 ended March 31, 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 the sum of 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
|
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 three
months ended March 31, 2021, the
value ratio between crude oil and natural gas was approximately
25:1. 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.