CALGARY, AB, Nov. 4, 2021
/CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company")
(TSX: POU) is pleased to announce strong third quarter 2021
financial and operating results, upwardly revised 2021 guidance and
its approved 2022 capital expenditure budget that is forecast to
generate approximately $455 million
in free cash flow in 2022 on production of between 90,000 Boe/d and
94,000 Boe/d (46 percent liquids).(1)(2) The Company is
also pleased to announce a tripling of its regular monthly dividend
from $0.02 to $0.06 per class A common share ("Common Share")
effective November 2021.
Q3 2021 HIGHLIGHTS
- Sales volumes averaged 82,150 Boe/d (45 percent liquids) in the
third quarter of 2021.
-
- Karr sales volumes averaged 39,878 Boe/d (52 percent liquids),
in line with expectations.
- Wapiti sales volumes averaged 14,651 Boe/d (62 percent
liquids), approximately 4,000 Boe/d higher than in the second
quarter despite a 10-day scheduled plant outage. This 38 percent
increase in production was mainly the result of new production from
the seven well 6-4 pad that was brought onstream in July.
- Early production rates at the two-well Willesden Green 4-7 pad
brought onstream in July are extremely encouraging. Despite being
restricted by facility constraints, average gross peak 30-day
production per well was 1,498 Boe/d (3.3 MMcf/d of shale gas and
948 Bbl/d of NGLs) with an average CGR of 287
Bbl/MMcf.(3)
- Cash from operating activities was $97.0
million in the third quarter. Adjusted funds flow was
$148.4 million or $1.12 per basic share.(4) Free cash
flow was $72.6 million.
- Third quarter capital spending totaled $68.9 million and was focused on drilling and
completion activities at Karr, Wapiti and the Willesden Green
Duvernay.
-
- Preliminary all-in lease construction, drilling, completion,
equip and tie-in (collectively "DCET") costs at the five-well Karr
5-16 East pad that was brought on production in late October 2021 averaged $6.3
million per well, approximately 15 percent lower than
average DCET costs at the 5-16 West pad that was brought onstream
in the fourth quarter of 2020.
- The Company continues to achieve lower costs in its Karr and
Wapiti drilling and completion programs despite emerging industry
cost inflation by utilizing its wholly-owned Fox Drilling rigs and
crews and securing fixed rates with certain service providers.
- Per unit operating costs continue to decrease and averaged
$11.02/Boe in the third quarter of
2021, down from $11.23/Boe in the
second quarter and $11.63/Boe in the
first quarter. Karr operating costs averaged $9.03/Boe in the third quarter of 2021.
- Abandonment and reclamation expenditures in the third quarter
totaled $6.9 million, net of
$0.9 million in funding under the
Alberta Site Rehabilitation Program ("ASRP").
- The Company implemented a regular monthly dividend in July and
repurchased 197,500 Common Shares under its normal course issuer
bid ("NCIB") in the third quarter at an average price of
$13.66 per share.
- Paramount closed the sale of its non-operated Birch asset for
proceeds of approximately $85
million.
- The carrying value of the Company's investments in securities
at September 30, 2021 was
approximately $300 million,
approximately $75 million higher on a
quarter over quarter basis.
___________________________________
|
(1)
|
"Free cash flow" is a
Non-GAAP financial measure. See "Non-GAAP Financial Measures" in
the Advisories section. See the "2022 Budget and Guidance"
section for a description of the assumptions upon which the free
cash flow forecast is based.
|
(2)
|
In this press
release, "liquids" refers to NGLs (including condensate) and oil
combined, "natural gas" refers to conventional natural gas and
shale gas combined, "condensate and oil" refers to condensate,
light and medium crude oil and tight oil combined and "other NGLs"
refers to ethane, propane and butane 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.
|
(3)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 4% and liquids sales volumes are lower by
approximately 9% due to shrinkage. Excludes days when the wells did
not produce. The production rates and volumes stated are over a
short period of time and, therefore, are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells. CGR means condensate to gas ratio and is
calculated by dividing raw wellhead liquids volumes by raw wellhead
natural gas volumes. See "Oil and Gas Measures and Definitions" in
the Advisories section.
|
(4)
|
"Adjusted funds flow"
is a Non-GAAP financial measure. See "Non-GAAP Financial Measures"
in the Advisories section.
|
UPDATED 2021 GUIDANCE
- Paramount expects fourth quarter sales volumes to range between
85,000 Boe/d and 86,500 Boe/d (45 percent liquids). As a
result, full year 2021 sales volumes are expected to average
approximately 82,000 Boe/d (44 percent liquids), achieving the high
end of the previous guidance range of 80,000 Boe/d to 82,000 Boe/d,
1,000 Boe/d higher than the mid-point.
- The Company has added approximately $15
million of capital expenditures in the second half of 2021,
which include additional activities at Wapiti to accelerate the
achievement of targeted plateau production of 30,000 Boe/d into
2023 and further debottlenecking initiatives at Karr. Full year
2021 capital spending is now expected to be between $285 and $295
million.
- Paramount is forecasting 2021 free cash flow of approximately
$215 million, an increase of
$30 million from previous guidance.
The increase reflects year-to-date actual results, updated sales
volumes guidance and revised commodity price and other assumptions
for the fourth quarter of 2021.(1)
- Year-end net debt to adjusted funds flow is forecast to be
approximately 0.8x, below the Company's previously targeted range
of 1.0x to 2.0x.(2)
_______________________________
|
(1)
|
The stated forecast
is based on the following assumptions for 2021: (i) the midpoint of
forecast capital spending and production, (ii) $25 million in net
abandonment and reclamation costs, (iii) realized pricing of
$47.55/Boe (US$67.63/Bbl WTI, US$3.94/MMBtu NYMEX, $3.59/GJ AECO),
(iv) royalties of $4.60/Boe, (v) operating costs of $11.15/Boe and
(vi) transportation and processing costs of
$4.00/Boe.
|
(2)
|
"Net debt" and "Net
debt to adjusted funds flow" are Non-GAAP financial measures. See
"Non-GAAP Financial Measures" in the Advisories section. The
forecast of year end net debt to adjusted funds flow assumes the
payment of a regular monthly dividend of $0.06 per Common Share
commencing in November 2021 and the conversion of the Company's $35
million of convertible debentures into Common Shares in the fourth
quarter of 2021.
|
2022 BUDGET AND GUIDANCE
The Company's 2022 capital budget is expected to range between
$500 million and $540 million, excluding land acquisitions and
abandonment and reclamation activities, an increase of $165 million at midpoint from preliminary
guidance. The budget includes the acceleration of approximately
$70 million in activities at Wapiti,
$60 million to advance a number of
high return opportunities in the Kaybob and Central Alberta & Other Regions and
additional growth capital that will primarily benefit 2023
production. Paramount remains committed to prudently managing
its capital resources and has the flexibility to adjust its capital
expenditure plans depending on commodity prices and other
factors.
Annual average sales volumes in 2022 are now expected to be
between 90,000 Boe/d and 94,000 Boe/d (46 percent liquids), an
increase of 6,000 Boe/d from previous preliminary guidance.
- First half 2022 sales volumes are expected to average between
81,000 Boe/d and 85,000 Boe/d (44 percent liquids) after accounting
for a planned 16-day full field outage at Karr for turnaround
activities at third-party midstream facilities.
- Second half 2022 sales volumes are expected to average between
99,000 Boe/d and 103,000 Boe/d (47 percent liquids) as numerous
wells are brought onstream related to capital activities initiated
earlier in 2022.
Paramount is forecasting approximately $455 million of free cash flow in 2022,
$135 million higher than the
Company's prior preliminary guidance.(1)
The 2022 capital budget is broken down as follows at
midpoint:
- $290 million of sustaining
capital and maintenance activities;
- $160 million of growth capital
associated with production benefits in 2022; and
- $70 million of growth capital
associated with production benefits largely in 2023.
The breakdown by region is as follows at midpoint:
- Grande Prairie − $365 million;
- Kaybob − $130 million;
- Central Alberta & Other −
$10 million; and
- Corporate − $15 million
The Company has budgeted approximately $41 million for abandonment and reclamation
activities in 2022. Approximately $8
million is to be funded directly through the ASRP, resulting
in approximately $33 million net to
Paramount. The majority of these funds will be directed to the
Zama area.
______________________
|
(1)
|
The stated free cash
flow forecast is based on the following assumptions for 2022: (i)
the midpoint of forecast capital spending and production, (ii) $33
million in net abandonment and reclamation costs, (iii) realized
pricing of $53.70/Boe (US$74.44/Bbl WTI, US$4.35/MMBtu NYMEX,
$3.95/GJ AECO), (iv) royalties of $6.65/Boe, (v) operating costs of
$11.00/Boe and (vi) transportation and processing costs of
$3.85/Boe.
|
FREE CASH FLOW PRIORITIES
Paramount's free cash flow priorities continue to be (i) the
achievement of targeted leverage levels, (ii) shareholder returns
and (iii) incremental growth.
- With strong 2021 performance and commodity prices, the Company
expects year-end 2021 net debt to adjusted funds flow will be
approximately 0.8x, below the previously targeted range of 1.0x to
2.0x.
- The Company is reducing its targeted long-term leverage level
to approximately $300 million in net
debt. This target is expected to be achieved in the third quarter
of 2022, implying a net debt to trailing 12-month adjusted funds
flow ratio of less than 0.5x at the end of that
quarter.(1)
- Paramount implemented a regular monthly dividend of
$0.02 per share in July 2021 and is tripling its monthly dividend
beginning in November 2021 to
$0.06 per share, implying a 10
percent payout ratio for 2022 and a 3.5 percent current dividend
yield.(2)
- Remaining 2022 free cash flow will be available to:
-
- further augment shareholder returns through increases in the
regular monthly dividend, special dividends or opportunistic
repurchases of Common Shares under the NCIB; and
- reinvest in incremental organic growth or strategic
acquisitions.
Paramount has hedged approximately 23 percent of its 2022
midpoint forecast production to provide greater free cash flow
certainty. With these hedges, the Company's 2022 capital
program, targeted net debt reduction and $0.06 per share regular monthly dividend would
remain fully funded down to an annual average WTI price in 2022 of
approximately US$52.50/Bbl with no
changes to the Company's natural gas pricing assumptions.
PRELIMINARY 2023 GUIDANCE
Based on preliminary planning and current market conditions,
Paramount anticipates 2023 capital spending, excluding land
acquisitions and abandonment and reclamation activities, to range
between $475 million and $525 million, broken down as follows at
midpoint:
- $330 million of sustaining
capital and maintenance activities; and
- $170 million of growth
capital.
The breakdown by region is as follows at midpoint:
- Grande Prairie − $295 million;
- Kaybob − $170 million;
- Central Alberta & Other −
$25 million; and
- Corporate − $10 million.
______________________________
|
(1)
|
The forecasted timing
of achieving the targeted net debt level and net debt to adjusted
funds flow assumes the payment of a regular monthly dividend of
$0.06 per Common Share commencing in November 2021 and the
conversion of the Company's $35 million of convertible debentures
into Common Shares in the fourth quarter of 2021.
|
(2)
|
Payout ratio is
calculated as total annual dividends assuming a $0.06 per Common
Share regular monthly dividend divided by forecast 2022 midpoint
adjusted funds flow.
|
A capital program in this range would be expected to result in
2023 annual average sales volumes of between 97,500 Boe/d and
102,500 Boe/d (48 percent liquids) and free cash flow of
approximately $450
million.(1)
FIVE-YEAR OUTLOOK
To highlight Paramount's free cash flow and production growth
potential, the Company is providing an initial five-year outlook
through to the end of 2026. At current strip prices and
subject to change as conditions evolve, the Company
anticipates:
- annual capital spending, excluding land acquisitions and
abandonment and reclamation activities, of approximately
$500 million;
- a compound annual production growth rate of approximately 5
percent; and
- cumulative free cash flow of over $2.7
billion.(2)
Paramount had total tax pools of approximately $4.7 billion as of September 30, 2021, including approximately
$3.5 billion of immediately
deductible non-capital loss and SR&ED pools. At current
strip prices, the Company does not expect to pay Canadian income
taxes within the next five years.
INCREASED DIVIDEND
Paramount's Board of Directors has approved an increase in the
Company's regular monthly dividend from $0.02 to $0.06 per
Common Share. The first increased dividend will be payable on
November 30, 2021 to shareholders of
record on November 15, 2021.
The dividend will be designated as an "eligible dividend" for
Canadian income tax purposes.
REDEMPTION OF CONVERTIBLE DEBENTURES
The Company has delivered notices to redeem all $35 million of its 7.5% senior unsecured
convertible debentures, effective December
3, 2021. It is expected that all holders will exercise
their right to convert their debentures into Common Shares prior to
the redemption date, resulting in approximately 5.3 million Common
Shares being issued.
_____________________________________
|
(1)
|
The free cash flow
estimate is based on the following assumptions for 2023: (i) the
midpoint of expected capital spending and production, (ii) $40
million in abandonment and reclamation costs, (iii) realized
pricing of $48.55/Boe (US$67.39/Bbl WTI, US$3.56/MMBtu NYMEX,
$3.28/GJ AECO), (iv) royalties of $5.95/Boe, (v) operating costs of
$10.50/Boe and (vi) transportation and processing costs of
$3.70/Boe.
|
(2)
|
The stated
anticipated cumulative free cash flow is based on the following
assumptions: (i) the stated annual capital expenditures and
compound annual production growth; (ii) approximately $40 million
in average annual abandonment and reclamation costs, (iii) strip
commodity prices and foreign exchange rates as at October 22, 2021,
and (iv) internal management estimates of future royalties,
operating costs and transportation and processing costs.
|
HEDGING
The Company's current hedging position is summarized
below.
|
Type
(1)
|
Q4
2021
|
Q1
2022
|
Q2
2022
|
Q3
2022
|
Q4
2022
|
Average Price (2)
|
Oil – WTI Swaps
(Sale) (Bbl/d)
|
Financial
|
10,000
|
–
|
–
|
–
|
–
|
US$45.82/Bbl
|
Oil – WTI Swaps
(Sale) (Bbl/d)
|
Financial
|
–
|
3,500
|
3,500
|
3,500
|
3,500
|
US$75.79/Bbl
|
Oil – WTI Swaps
(Sale) (Bbl/d)
|
Financial
|
6,000
|
–
|
–
|
–
|
–
|
CDN$88.45/Bbl
|
Oil – WTI Swaps
(Sale) (Bbl/d)
|
Financial
|
–
|
9,500
|
–
|
–
|
–
|
CDN$87.90/Bbl
|
Oil – WTI Swaps
(Sale) (Bbl/d)
|
Financial
|
–
|
–
|
3,500
|
3,500
|
3,500
|
CDN$91.38/Bbl
|
Oil – WTI Costless
Collars (Bbl/d)
|
Financial
|
–
|
7,000
|
7,000
|
7,000
|
7,000
|
CDN$82.50/Bbl
(Floor)
|
|
|
|
|
|
|
|
CDN$100.47/Bbl
(Ceiling)
|
Condensate – Basis
(Sale) (Bbl/d)
|
Physical
|
855
|
2,098
|
–
|
–
|
–
|
WTI +
US$3.13/Bbl
|
Gas – NYMEX Swaps
(Sale) (MMbtu/d)
|
Financial
|
110,000
|
–
|
–
|
–
|
–
|
US$3.37/MMbtu
|
Gas – NYMEX Swaps
(Sale) (MMbtu/d)
|
Financial
|
–
|
40,000
|
–
|
–
|
–
|
US$4.15/MMbtu
|
Gas – AECO fixed
price (GJ/d)
|
Physical
|
116,848
|
–
|
–
|
–
|
–
|
CDN$3.16/GJ
|
Gas – AECO fixed
price (GJ/d)
|
Physical
|
–
|
40,000
|
–
|
–
|
–
|
CDN$4.06/GJ
|
Gas – AECO fixed
price (GJ/d)
|
Physical
|
–
|
–
|
30,000
|
30,000
|
10,109
|
CDN$3.54/GJ
|
(1) Financial,
refers to financial commodity contracts. Physical, refers to
fixed-priced and basis physical contracts.
(2) Average price is
calculated using a weighted average of notional volumes and
prices.
|
REVIEW OF OPERATIONS
GRANDE PRAIRIE
REGION
Grande Prairie Region sales volumes and netbacks are summarized
below:(1)
|
Q3 2021
|
Q2 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
148.0
|
134.3
|
10
|
Condensate and oil
(Bbl/d)
|
26,648
|
24,090
|
11
|
Other NGLs
(Bbl/d)
|
3,274
|
2,874
|
14
|
Total
(Boe/d)
|
54,586
|
49,345
|
11
|
%
liquids
|
55%
|
55%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
275.8
|
54.92
|
217.7
|
48.47
|
27
|
Royalties
|
(20.5)
|
(4.08)
|
(15.3)
|
(3.40)
|
34
|
Operating
expense
|
(52.6)
|
(10.47)
|
(48.8)
|
(10.88)
|
8
|
Transportation
and NGLs processing
|
(22.5)
|
(4.48)
|
(21.4)
|
(4.76)
|
5
|
|
180.2
|
35.89
|
132.2
|
29.43
|
36
|
|
______________________________________
|
(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:
|
Q3 2021
|
Q2 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
114.4
|
107.6
|
6
|
Condensate and oil
(Bbl/d)
|
18,328
|
18,458
|
(1)
|
Other NGLs
(Bbl/d)
|
2,477
|
2,281
|
9
|
Total
(Boe/d)
|
39,878
|
38,679
|
3
|
%
liquids
|
52%
|
54%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
195.3
|
53.23
|
168.0
|
47.72
|
16
|
Royalties
|
(17.1)
|
(4.66)
|
(13.1)
|
(3.72)
|
31
|
Operating
expense
|
(33.1)
|
(9.03)
|
(33.1)
|
(9.40)
|
-
|
Transportation
and NGLs processing
|
(15.7)
|
(4.27)
|
(16.0)
|
(4.52)
|
(2)
|
|
129.4
|
35.27
|
105.8
|
30.08
|
22
|
Third quarter sales volumes at Karr averaged 39,878 Boe/d (52
percent liquids) compared to 38,679 Boe/d (54 percent liquids) in
the second quarter. Plateau production of approximately
40,000 Boe/d that was first achieved in March has been sustained
through efficient and reliable operations, continued strong
performance from the six-well 3-10 pad that first produced in
February and new well production from the five-well 7-18 pad that
came onstream in late-July. The Company continues to seek
efficiencies in its operations while maintaining its focus on
safety, asset integrity, reliability and environmental
performance.
The 7-18 pad has outperformed internal type well projections,
averaging gross peak 30-day production per well of 2,137 Boe/d (6.4
MMcf/d of shale gas and 1,076 Bbl/d of NGLs) with an average CGR of
169 Bbl/MMcf.(1) The Company projects that this
pad will achieve payout approximately five months after coming
onstream.
While remaining sharply focused on maintaining well performance,
Paramount continues to realize lower than historical DCET costs
despite experiencing certain inflationary pressures.
Preliminary DCET costs at the five-well Karr 5-16 East pad that was
brought on production in late-October
2021 averaged $6.3 million per
well, approximately 15 percent lower than average DCET costs of the
5-16 West pad that was brought onstream in the fourth quarter of
2020. Drilling operations are ongoing at the twelve-well
16-17 pad and the Company expects that seven of the twelve wells
will be drilled by year-end. The 16-17 pad was initially
planned as a ten well pad, but two additional wells were added
prior to the commencement of drilling.
Karr unit operating costs trended lower in the third quarter as
a result of higher production volumes and the Company's continued
focus on capturing efficiencies and streamlining operations.
Paramount achieved operating costs at Karr of $9.03/Boe in the third quarter of 2021, lower
than targeted operating costs of $10.00/Boe at plateau production of approximately
40,000 Boe/d. The Company also achieved a record netback of
$35.27/Boe at Karr in the third
quarter.
In 2022, Paramount plans to maintain plateau production at Karr
of 40,000 Boe/d by drilling 14 Montney wells and bringing onstream
16 wells, consistent with the Company's expectation that a total of
12 to 16 new wells per year are needed to maintain plateau
production. The twelve-well 16-17 pad is currently being
drilled and will be brought on production in two phases, with the
first seven wells scheduled to come onstream in the second quarter
of 2022 and the remaining five wells to come onstream in the second
half of the year. Drilling of the four-well 1-2 North pad is
scheduled to commence in the second quarter and the Company plans
to bring all four wells onstream in late-2022. The Company
also plans to bring onstream additional gas lift compression in the
year to support liquids production as well as build out certain
infrastructure to debottleneck future production.
___________________________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 6% and liquids sales volumes are lower by
approximately 6% due to shrinkage. Excludes days when the wells did
not produce. The production rates and volumes stated are over a
short period of time and, therefore, are not necessarily indicative
of average daily production, long-term performance or of ultimate
recovery from the wells. CGR means condensate to gas ratio and is
calculated by dividing raw wellhead liquids volumes by raw wellhead
natural gas volumes. See "Oil and Gas Measures and Definitions" in
the Advisories section.
|
WAPITI AREA
Wapiti sales volumes and netbacks are summarized
below:
|
Q3 2021
|
Q2 2021
|
%
Change
|
Sales
volumes
|
|
|
|
Natural gas
(MMcf/d)
|
33.3
|
26.4
|
26
|
Condensate and oil
(Bbl/d)
|
8,310
|
5,629
|
48
|
Other NGLs
(Bbl/d)
|
790
|
582
|
36
|
Total
(Boe/d)
|
14,651
|
10,604
|
38
|
%
liquids
|
62%
|
59%
|
|
Netback
|
($
millions)
|
($/Boe)
|
($
millions)
|
($/Boe)
|
% Change in $
millions
|
Petroleum and natural
gas sales
|
80.4
|
59.62
|
49.6
|
51.41
|
62
|
Royalties
|
(3.4)
|
(2.49)
|
(2.1)
|
(2.24)
|
62
|
Operating
expense
|
(19.2)
|
(14.25)
|
(15.4)
|
(16.00)
|
25
|
Transportation
and NGLs processing
|
(6.9)
|
(5.09)
|
(5.5)
|
(5.65)
|
25
|
|
50.9
|
37.79
|
26.6
|
27.52
|
91
|
Third quarter sales volumes at Wapiti averaged 14,651 Boe/d (62
percent liquids) compared to 10,604 Boe/d (59 percent liquids) in
the second quarter due to new well production from the seven-well
6-4 pad that was brought onstream in July. Gross peak 30-day
production per well from the 6-4 pad averaged 1,292 Boe/d (3.0
MMcf/d of shale gas and 794 Bbl/d of NGLs) with an average CGR of
266 Bbl/MMcf.(1) Third quarter production was impacted
by the previously disclosed scheduled ten-day outage at the
third-party Wapiti natural gas processing facility.
Drilling operations at the seven-well 9-22 pad are now complete,
with four of the seven wells having been configured as
monobores. Compared with conventional multiple casing
wellbores, monobore wells require less steel in the form of casing
and less time on lease installing and cementing the additional
casing, resulting in lower capital costs. Additional cost and
well productivity benefits are also anticipated due to higher
pumping rates afforded by the larger diameter wellbore. The
Company plans to complete, tie-in and bring onstream four wells in
December with the remaining three wells to be brought onstream in
the first quarter of 2022.
As a result of capital cost savings achieved to date in 2021 and
in support of reaching plateau production of 30,000 Boe/d at Wapiti
in 2023, Paramount is accelerating the commencement of drilling
operations of the eight-well 8-22 pad into 2021.
In 2022, the Company plans to grow Wapiti production to
approximately 27,000 Boe/d by year end by drilling 32 wells and
bringing onstream a total of 22 wells. Drilling, completion
and tie-in activities at the eight-well 8-22 pad are scheduled to
commence in late-2021 and continue through the first half of 2022,
with the majority of the wells to be brought onstream in the second
quarter of 2022. Paramount plans to drill, complete and
tie-in two additional eight-well pads, at 6-32 and 16-15, with
drilling scheduled for the second and third quarters of 2022
respectively. The 6-32 pad is expected to be onstream in the
second half of 2022 while the majority of the 16-15 pad wells will
be brought onstream in early 2023. Drilling of the eight-well
8-15 pad is scheduled for late 2022. The Company also plans
to complete a tenure well in 2022.
______________________________________
|
(1)
|
Production measured
at the wellhead. Natural gas sales volumes are lower by
approximately 13% and liquids sales volumes are lower by
approximately 1% 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.
|
KAYBOB REGION
Kaybob Region sales volumes averaged 21,054 Boe/d (28
percent liquids) in the third quarter of 2021 compared to 22,688
Boe/d (28 percent liquids) in the second quarter. The
decrease in production is largely attributable to natural
declines.
In 2022, Paramount plans to pursue the development of its
Duvernay assets at Kaybob North
and Kaybob Smoky. At Kaybob North, the Company plans to drill
the remaining two wells at the three-well 12-21 pad and bring all
three wells onstream in the second half of 2022. At Kaybob
Smoky, plans include the expansion of the Company's 100% owned and
operated 6-16 facility and the drilling, completion, tie-in and
bringing onstream of the four-well 10-35 pad, also in the second
half of 2022.
The Company expects to realize capital cost efficiencies in its
Kaybob Duvernay plays, similar to those achieved over the past two
years at Karr and Wapiti, as it commences pad development and
captures economies of scale.
The Company plans to pursue other high return opportunities at
Kaybob in 2022, including bringing onstream four Montney gas wells, two Montney oil wells and two Gething oil wells,
seven of which will be drilled in 2022. Other activities
include an expansion of the enhanced oil recovery scheme at the
Company's Kaybob Montney Oil property.
CENTRAL ALBERTA & OTHER
REGION
Central Alberta & Other
Region sales volumes averaged 6,510 Boe/d (22 percent liquids) in
the third quarter of 2021 compared to 7,962 Boe/d (13 percent
liquids) in the second quarter. Sales volumes in the third
quarter decreased primarily due to the sale of the non-operated
Birch assets in July and, to a lesser extent, a third-party
pipeline outage and natural declines. New well production
from the two-well Willesden Green Duvernay 4-7 pad that was brought
on production in July partially offset these decreases. Despite
being restricted by facility constraints, average gross peak 30-day
production per well at the 4-7 pad was 1,498 Boe/d (3.3 MMcf/d of
shale gas and 948 Bbl/d of NGLs) with an average CGR of 287
Bbl/MMcf.
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. Material learnings from the drilling of
the two wells at the 4-7 pad, particularly in drilling long reach
laterals in the Duvernay
formation, have resulted in further optimization to pad layouts in
the full field development plans across the Company's Duvernay lands, improving economics. DCET
costs at the 4-7 pad averaged $11.3
million per well. The Company anticipates reductions
in average well costs once commercial scale development commences
and critical infrastructure is in place.
In 2022, planned activities include the addition of water
infrastructure and FEED studies for future facility expansion that
will benefit Duvernay development
in the Willesden Green area.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused
Canadian energy company that explores for and develops both
conventional and unconventional petroleum and natural gas reserves
and resources, including longer-term strategic exploration and
pre-development plays, and holds a portfolio of investments in
other entities. The Company's principal properties are located in
Alberta and British Columbia. Paramount's class A common
shares are listed on the Toronto Stock Exchange under the symbol
"POU".
Paramount's third quarter 2021 results, including Management's
Discussion and Analysis and the Company's Consolidated Financial
Statements can be obtained at:
https://mma.prnewswire.com/media/1678630/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Announces_Thir.pdf
A summary of historical financial and operating results is also
available on Paramount's website at
https://www.paramountres.com/investors/financial-shareholder-reports.
This information will also be made available through Paramount's
website at www.paramountres.com and on SEDAR at
www.sedar.com.
FINANCIAL AND
OPERATING RESULTS(1)
|
($ millions, except
as noted)
|
|
|
Q3
2021
|
Q2
2021
|
Net income
(loss)
|
|
|
|
|
292.7
|
(74.3)
|
per share – basic
($/share)
|
|
|
|
|
2.20
|
(0.56)
|
per share – diluted
($/share)
|
|
|
|
|
2.06
|
(0.56)
|
Cash from
operating activities
|
|
|
|
|
97.0
|
112.1
|
per share – basic
($/share)
|
|
|
|
|
0.73
|
0.84
|
per share – diluted
($/share)
|
|
|
|
|
0.68
|
0.84
|
Adjusted funds
flow
|
|
|
|
|
148.4
|
86.0
|
per share – basic
($/share)
|
|
|
|
|
1.12
|
0.65
|
per share – diluted
($/share)
|
|
|
|
|
1.04
|
0.65
|
Total
assets
|
|
|
|
|
3,882.9
|
3,655.6
|
Long-term
debt
|
|
|
|
|
522.4
|
608.4
|
Net
debt
|
|
|
|
|
576.8
|
724.5
|
Common shares
outstanding (thousands) (2)
|
|
|
|
|
133,207
|
133,314
|
Sales
volumes
|
|
|
|
|
Natural gas
(MMcf/d)
|
|
|
269.7
|
273.1
|
Condensate and oil
(Bbl/d)
|
|
|
32,177
|
29,543
|
Other NGLs (Bbl/d)
(3)
|
|
|
5,017
|
4,938
|
Total
(Boe/d)
|
|
|
82,150
|
79,995
|
%
liquids
|
|
|
45%
|
43%
|
Grande Prairie Region
(Boe/d)
|
|
|
54,586
|
49,345
|
Kaybob Region
(Boe/d)
|
|
|
21,054
|
22,688
|
Central Alberta &
Other Region (Boe/d)
|
|
|
6,510
|
7,962
|
Total
(Boe/d)
|
|
|
82,150
|
79,995
|
Netback
|
|
|
|
|
|
$/Boe
(3)
|
|
$/Boe
(3)
|
Natural gas
revenue
|
|
|
|
|
96.5
|
3.89
|
74.8
|
3.01
|
Condensate and
oil revenue
|
|
|
|
|
249.9
|
84.42
|
209.6
|
77.96
|
Other NGLs
revenue
|
|
|
|
|
21.7
|
47.05
|
14.4
|
32.11
|
Royalty and
other revenue
|
|
|
|
|
1.0
|
─
|
0.9
|
─
|
Petroleum and
natural gas sales
|
|
|
|
|
369.1
|
48.84
|
299.7
|
41.17
|
Royalties
|
|
|
|
|
(30.9)
|
(4.09)
|
(24.9)
|
(3.43)
|
Operating
expense
|
|
|
|
|
(83.3)
|
(11.02)
|
(81.8)
|
(11.23)
|
Transportation
and NGLs processing (4)
|
|
|
|
|
(30.3)
|
(4.01)
|
(30.3)
|
(4.16)
|
Netback
|
|
|
|
|
224.6
|
29.72
|
162.7
|
22.35
|
Financial commodity
contract settlements
|
|
|
|
|
(59.0)
|
(7.81)
|
(54.1)
|
(7.44)
|
Netback including
financial commodity contract settlements
|
165.6
|
21.91
|
108.6
|
14.91
|
Total Capital
Expenditures
|
|
|
|
|
Grande Prairie
Region
|
|
|
53.1
|
66.5
|
Kaybob
Region
|
|
|
1.7
|
3.9
|
Central Alberta &
Other Region
|
|
|
9.7
|
11.8
|
Corporate
(5)
|
|
|
1.6
|
1.2
|
Land
acquisitions
|
|
|
2.8
|
0.1
|
Total capital
expenditures
|
|
|
68.9
|
83.5
|
Asset retirement
obligation settlements
|
|
|
6.9
|
3.2
|
(1) Readers
are referred to the advisories concerning Non-GAAP Financial
Measures and Oil and Gas Measures and Definitions in the Advisories
section of this document. This table contains the following
Non-GAAP financial measures: Adjusted funds flow, Net debt,
Netback and Total capital expenditures. Readers are referred
to the Product Type Information section of this document for a
complete breakdown of sales volumes for applicable periods by the
specific product types.
(2)
Presented net of shares held in trust under the Company's
restricted share unit plan (000's of common shares): Q3 2021: 1,536
and Q2 2021: 1,538.
(3) Natural
gas revenue presented as $/Mcf.
(4)
Includes downstream transportation costs and NGLs fractionation
costs.
(5)
Includes transfers between regions.
|
PRODUCT TYPE INFORMATION
This press release refers to sales volumes of "natural gas",
"condensate and oil", "NGLs", "Other NGLs" and
"Liquids". "Natural gas" refers to conventional natural gas
and shale gas combined. "Condensate and oil" refers to condensate,
light and medium crude oil and tight oil combined. "NGLs"
refers to condensate and Other NGLs combined. "Other NGLs" refers
to ethane, propane and butane combined. "Liquids" refers to
condensate and oil and Other NGLs combined. Below is a
complete breakdown of sales volumes for applicable periods by the
specific product types of shale gas, conventional natural gas,
NGLs, tight oil and light and medium crude oil. Numbers may
not add due to rounding.
|
|
|
Total
|
Grande Prairie
Region
|
Kaybob
Region
|
Central Alberta
& Other Region
|
|
Q3
2021
|
Q2
2021
|
Q3
2021
|
Q2
2021
|
Q3
2021
|
Q2
2021
|
Q3
2021
|
Q2
2021
|
Shale gas
(MMcf/d)
|
207.1
|
205.8
|
145.8
|
132.2
|
36.9
|
39.3
|
24.4
|
34.3
|
Conventional natural
gas (MMcf/d)
|
62.6
|
67.3
|
2.2
|
2.1
|
54.4
|
58.0
|
6.0
|
7.2
|
Natural gas
(MMcf/d)
|
269.7
|
273.1
|
148.0
|
134.3
|
91.3
|
97.3
|
30.4
|
41.5
|
Condensate
(Bbl/d)
|
29,670
|
26,784
|
26,639
|
24,086
|
2,072
|
2,319
|
959
|
379
|
Other NGLs
(Bbl/d)
|
5,017
|
4,938
|
3,274
|
2,874
|
1,415
|
1,569
|
328
|
495
|
NGLs
(Bbl/d)
|
34,687
|
31,722
|
29,913
|
26,960
|
3,487
|
3,888
|
1,287
|
874
|
Tight oil
(Bbl/d)
|
475
|
494
|
–
|
–
|
368
|
354
|
107
|
140
|
Light and medium crude
oil (Bbl/d)
|
2,032
|
2,265
|
9
|
4
|
1,979
|
2,224
|
44
|
37
|
Crude oil
(Bbl/d)
|
2,507
|
2,759
|
9
|
4
|
2,347
|
2,578
|
151
|
177
|
Total
(Boe/d)
|
82,150
|
79,995
|
54,586
|
49,345
|
21,054
|
22,688
|
6,510
|
7,962
|
|
Karr
|
Wapiti
|
|
Q3 2021
|
Q2
2021
|
Q3
2021
|
Q2
2021
|
Shale gas
(MMcf/d)
|
113.0
|
106.3
|
32.7
|
25.9
|
Conventional natural
gas (MMcf/d)
|
1.4
|
1.3
|
0.6
|
0.5
|
Natural gas
(MMcf/d)
|
114.4
|
107.6
|
33.3
|
26.4
|
NGLs
(Bbl/d)
|
20,805
|
20,739
|
9,100
|
6,211
|
Total
(Boe/d)
|
39,878
|
38,679
|
14,651
|
10,604
|
The Company forecasts that fourth quarter 2021 sales volumes
will average between 85,000 Boe/d and 86,500 Boe/d (55 percent
shale gas and conventional natural gas combined, 39 percent light
and medium crude oil, tight oil and condensate combined and 6
percent other NGLs).
The Company forecasts that 2021 annual sales volumes will
average approximately 82,000 Boe/d (56 percent shale gas and
conventional natural gas combined, 38 percent light and medium
crude oil, tight oil and condensate combined and 6 percent other
NGLs).
The Company forecasts that 2022 sales volumes will average
between 90,000 Boe/d and 94,000 Boe/d (54 percent shale gas
and conventional natural gas combined, 40 percent light and medium
crude oil, tight oil and condensate combined and 6 percent other
NGLs). First half 2022 sales volumes are expected to average
between 81,000 Boe/d and 85,000 Boe/d (56 percent shale gas and
conventional natural gas combined, 38 percent light and medium
crude oil, tight oil and condensate combined and 6 percent other
NGLs). Second half 2022 sales volumes are expected to average
between 99,000 Boe/d and 103,000 Boe/d (53 percent shale gas and
conventional natural gas combined, 41 percent light and medium
crude oil, tight oil and condensate combined and 6 percent 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:
- forecast free cash flow in 2021 and 2022;
- forecast 2021 year-end net debt to annual adjusted funds
flow;
- planned capital expenditures in 2021 and 2022;
- forecast sales volumes for 2021 and 2022 and certain periods
therein;
- the expectation that plateau production will be reached at
Wapiti in 2023;
- the anticipated meeting by the Company of its $300 million net debt target by the end of the
third quarter of 2022 and the implied net debt to adjusted funds
flow ratio at the end of the third quarter of 2022;
- the Company's priorities and expectations respecting the
allocation of free cash flow;
- planned abandonment and reclamation expenditures and activities
in 2022;
- preliminary anticipated capital expenditures in 2023 and the
resulting expected 2023 average sales volumes and free cash
flow;
- the Company's five-year outlook for capital spending, annual
production growth rate and cumulative free cash flow;
- the Company's expectation that it will not be required to pay
Canadian income taxes within the next five years;
- the expectation that all holders will exercise their right to
convert their debentures into Common Shares prior to the redemption
date;
- planned exploration, development and production activities,
including the expected timing of completing and bringing new wells
on production;
- the expectation that a total of 12 to 16 wells per year are
needed to maintain plateau production at Karr;
- preliminary estimated drilling, completion and equipping
costs;
- the payment of future dividends under the Company's monthly
dividend program; and
- expected capital cost efficiencies at the Company's Kaybob
Duvernay properties and the expectation that average well costs at
the Company's Duvernay properties
will be reduced once commercial scale development commences.
Such forward-looking information is based on a number of
assumptions which may prove to be incorrect. Assumptions have been
made with respect to the following matters, in addition to any
other assumptions identified in this press release:
- future commodity prices and the potential impact of the
COVID-19 pandemic thereon;
- the likely impact of the COVID-19 pandemic on operations;
- the ability to realize expected cost savings;
- royalty rates, taxes and capital, operating, processing,
transportation, general & administrative and other costs;
- foreign currency exchange rates and interest rates;
- general business, economic and market conditions;
- the performance of wells and facilities;
- 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;
- in the case of the expectation that all holders will exercise
their right to convert their debentures into Common Shares prior to
the redemption date, the assumption that the trading price of the
Common Shares will continue to remain substantially above the
conversion price of the debentures; 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).
In addition to the above, the Company's expectation to not pay
Canadian income taxes within the next five years is based on the
current tax regime, the Company's tax pools and the assumptions
with respect to production, expenditures, commodity prices,
royalties and costs in the five years ended 2026 set forth
herein. Taxable income varies depending on total income and
expenses and Paramount's estimate is sensitive to assumptions
regarding commodity prices, production, cash from operating
activities, capital spending levels and acquisition and disposition
transactions. Changes in these factors could result in the Company
paying income taxes earlier than expected.
Although Paramount believes that the expectations reflected in
such forward-looking information are reasonable based on the
information available at the time of this press release, undue
reliance should not be placed on the forward-looking information as
Paramount can give no assurance that such expectations will prove
to be correct. Forward-looking information is based on
expectations, estimates and projections that involve a number of
risks and uncertainties which could cause actual results to differ
materially from those anticipated by Paramount and described in the
forward-looking information. The material risks and
uncertainties include, but are not limited to:
- fluctuations in commodity prices, including in relation to the
impact of the COVID-19 pandemic;
- changes in capital spending plans and planned exploration and
development activities;
- the potential for changes to preliminary anticipated 2023
capital expenditures prior to finalization and changes to the
resulting expected 2023 average sales volumes and free cash
flow;
- the potential for changes to the Company's five-year outlook
for capital spending, annual production growth rate and cumulative
free cash flow;
- changes in foreign currency exchange rates and interest
rates;
- the uncertainty of estimates and projections relating to future
revenue, free cash flow, production, reserves additions, product
yields (including condensate to natural gas ratios), resource
recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate product processing,
transportation, fractionation, and storage capacity on acceptable
terms;
- operational risks in exploring for, developing, producing and
transporting natural gas and liquids, including the risk of spills,
leaks or blowouts;
- the ability to obtain equipment, services, supplies and
personnel in a timely manner and at an acceptable cost;
- potential disruptions, delays or unexpected technical or other
difficulties in designing, developing, expanding or operating new,
expanded or existing facilities (including third-party
facilities);
- processing, pipeline, and fractionation infrastructure outages,
disruptions and constraints;
- risks and uncertainties involving the geology of oil and gas
deposits;
- the uncertainty of reserves estimates;
- general business, economic and market conditions;
- the ability to generate sufficient cash from operating
activities and obtain financing to fund planned exploration,
development and operational activities and meet current and future
commitments and obligations (including product processing,
transportation, fractionation and similar commitments and
obligations);
- changes in, or in the interpretation of, laws, regulations or
policies (including environmental laws);
- the ability to obtain required governmental or regulatory
approvals in a timely manner, and to enter into and maintain leases
and licenses;
- the effects of weather and other factors including wildlife and
environmental restrictions which affect field operations and
access;
- the timing and cost of future abandonment and reclamation
obligations and potential liabilities for environmental damage and
contamination;
- uncertainties regarding aboriginal claims and in maintaining
relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, insurance
claims, regulatory actions, audits and assessments; and
- other risks and uncertainties described elsewhere in this
document and in Paramount's other filings with Canadian securities
authorities.
There are risks that may result in the Company changing,
suspending or discontinuing its monthly dividend program, including
changes to free cash flow, operating results, capital requirements,
financial position, market conditions or corporate strategy and the
need to comply with requirements under debt agreements and
applicable laws respecting the declaration and payment of
dividends. There are no assurances as to the continuing
declaration and payment of future dividends under the Company's
monthly dividend program or the amount or timing of any such
dividends.
The foregoing list of risks is not exhaustive. For more
information relating to risks, see the sections titled "Risk
Factors" in Paramount's annual information form for the year
ended December 31, 2020, which is
available on SEDAR at www.sedar.com. The forward-looking
information contained in this press release is made as of the date
hereof and, except as required by applicable securities law,
Paramount undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of
new information, future events or otherwise.
Certain forward-looking information in this press release,
including forecast free cash flow in 2021, 2022 and future periods
and forecast 2021 and 2022 net debt to annual adjusted funds flow
ratios, may also constitute a "financial outlook" within the
meaning of applicable securities laws. A financial outlook
involves statements about Paramount's prospective financial
performance or position and is based on and subject to the
assumptions and risk factors described above in respect of
forward-looking information generally as well as any other specific
assumptions and risk factors in relation to such financial outlook
noted in this press release. Such assumptions are based on
management's assessment of the relevant information currently
available and any financial outlook included in this press release
is provided for the purpose of helping readers understand
Paramount's current expectations and plans for the future.
Readers are cautioned that reliance on any financial outlook may
not be appropriate for other purposes or in other circumstances and
that the risk factors described above or other factors may cause
actual results to differ materially from any financial outlook.
Non-GAAP Financial Measures
In this press release, "adjusted funds flow", "free cash flow",
"netback", "net debt", "net debt to adjusted funds flow" and "total
capital expenditures", together the "Non-GAAP financial measures",
are used and do not have any standardized meanings as prescribed by
International Financial Reporting Standards.
"Adjusted funds flow" refers to cash from (used in) operating
activities before net changes in non-cash working capital,
geological and geophysical expenses, asset retirement obligation
settlements, closure costs, provisions and other, dispute
settlements and transaction and reorganization costs.
Adjusted funds flow is used to assist management and investors in
measuring the Company's ability to fund capital programs and meet
financial obligations, including the settlement of asset retirement
obligations. Asset retirement obligation settlements are
excluded from the calculation of adjusted funds flow because such
expenditures are not directly linked to the revenue generating
activities of the Company. Paramount manages the timing of
expenditures related to asset retirement obligation settlements in
accordance with regulatory requirements and its overall approach to
managing its asset retirement obligations and, as a result, amounts
incurred may vary significantly from period to period. Adjusted
funds flow is not intended to represent cash from operating
activities, net loss or any other GAAP measure and should not be
construed as being an alternative to, or more meaningful than, cash
flow from operating activities as determined in accordance with
IFRS. The following are the calculations of adjusted funds
flow from the nearest GAAP measure for the three months ended
September 30, 2021 and June 30, 2021:
Three months
ended
|
Sept 30,
2021
(MM$)
|
Jun 30,
2021
(MM$)
|
Cash from
operating activities
|
97.0
|
112.1
|
Change in non-cash
working capital
|
42.9
|
(47.6)
|
Geological and
geophysical expenses
|
1.6
|
1.8
|
Asset retirement
obligations settled
|
6.9
|
3.2
|
Closure
costs
|
–
|
–
|
Provisions and
other
|
–
|
16.5
|
Dispute
settlements
|
–
|
–
|
Transaction and
reorganization costs
|
–
|
–
|
Adjusted funds
flow
|
148.4
|
86.0
|
"Free cash flow" refers to adjusted funds flow less total
capital expenditures and asset retirement obligation
settlements. Free cash flow is used by management and
investors to assess the amount of internally generated cash
available to repay debt, reinvest in the business or return to
shareholders. The following is the calculation of free cash
flow from the nearest GAAP measure for the three months ended
September 30, 2021 and June 30, 2021:
Three months
ended
|
Sept 30,
2021
(MM$)
|
Jun 30,
2021
(MM$)
|
Adjusted funds
flow
|
148.4
|
86.0
|
Total capital
expenditures
|
(68.9)
|
(83.5)
|
Asset retirement
obligation settlements
|
(6.9)
|
(3.2)
|
Free cash
flow
|
72.6
|
(0.7)
|
"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 tables under the headings "Review of
Operations" and "Financial and Operating Results" for the
calculation thereof.
"Net debt" is a measure of the Company's overall debt
position after adjusting for certain working capital and other
amounts and is used by management to assess the Company's overall
leverage position. Refer to the Liquidity and Capital
Resources section of the Company's Management's Discussion and
Analysis for the three months and nine months ended September 30, 2021 (the "MD&A") for the
calculation of net debt.
"Net debt to adjusted funds flow" is a ratio calculated as
the period end net debt divided by adjusted funds flow for the
trailing four quarters. The ratio of net debt to adjusted funds
flow is commonly used by management and investors to assess the
Company's overall debt position.
"Total capital expenditures" refers to the Company's
property, plant and equipment and exploration expenditures. Refer
to the Total Capital Expenditures section of the MD&A for the
calculation thereof.
Non-GAAP financial measures should not be considered in
isolation or construed as alternatives to their most directly
comparable measure calculated in accordance with GAAP, or other
measures of financial performance calculated in accordance with
GAAP. The Non-GAAP financial measures are unlikely to be comparable
to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
Abbreviations
Liquids
|
|
Natural
Gas
|
Bbl
|
Barrels
|
|
GJ
|
Gigajoules
|
Bbl/d
|
Barrels per
day
|
|
GJ/d
|
Gigajoules per
day
|
MBbl
|
Thousands of
barrels
|
|
Mcf
|
Thousands of cubic
feet
|
NGLs
|
Natural gas
liquids
|
|
MMcf
|
Millions of cubic
feet
|
Condensate
|
Pentane and heavier
hydrocarbons
|
MMcf/d
|
Millions of cubic
feet per day
|
WTI
|
West Texas
Intermediate
|
|
AECO
|
AECO-C reference
price
|
|
|
|
NYMEX
|
New York Mercantile
Exchange
|
|
|
|
MMbtu
|
Millions of British
thermal units
|
|
|
|
MMbtu/d
|
Millions of British
thermal units per day
|
Oil
Equivalent
|
Boe
|
Barrels of oil
equivalent
|
MBoe
|
Thousands of barrels
of oil equivalent
|
MMBoe
|
Millions of barrels
of oil equivalent
|
Boe/d
|
Barrels of oil
equivalent per day
|
This press release contains disclosures expressed as "Boe",
"$/Boe" and "Boe/d". Natural gas equivalency volumes
have been derived using the ratio of six thousand cubic feet of
natural gas to one barrel of oil when converting natural gas to
Boe. Equivalency measures may be misleading, particularly if
used in isolation. A conversion ratio of six thousand cubic feet of
natural gas to one barrel of oil is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the well head. For the nine
months ended September 30, 2021, the
value ratio between crude oil and natural gas was approximately
26:1. This value ratio is significantly different from the energy
equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as
an indication of value.
This press release refers to "CGR", a metric commonly used in
the oil and natural gas industry. "CGR" means condensate to
gas ratio and is calculated by dividing wellhead raw liquids
volumes by wellhead raw natural gas volumes. This
metric does not have a standardized meaning and may not be
comparable to similar measures presented by other companies. As
such, it should not be used to make comparisons. Management uses
oil and gas metrics for its own performance measurements and to
provide shareholders with measures to compare the Company's
performance over time; however, such measures are not reliable
indicators of the Company's future performance and future
performance may not compare to the performance in previous periods
and therefore should not be unduly relied upon.
Additional information respecting the Company's oil and gas
properties and operations is provided in the Company's annual
information form for the year ended December
31, 2020 which is available on SEDAR at www.sedar.com.
SOURCE Paramount Resources Ltd.