HIGHLIGHTS
_________________________ |
|
(1) |
In this press release, “liquids” refers to NGLs (including condensate) and oil combined, “natural gas” refers to conventional natural gas and shale gas combined, “condensate and oil” refers to condensate, light and medium crude oil and tight oil combined and “other NGLs” refers to ethane, propane and butane combined. See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. See also “Oil and Gas Measures and Definitions” in the Advisories section. |
(2) |
“Adjusted funds flow”, “free cash flow” and “net debt to adjusted funds flow” are Non-GAAP financial measures. See “Non-GAAP Financial Measures” in the Advisories section. |
GUIDANCE
Paramount is reaffirming its 2021 average sales volumes guidance of between 80,000 Boe/d and 82,000 Boe/d (44 percent liquids). Second half 2021 sales volumes guidance remains unchanged at between 80,000 Boe/d and 84,000 Boe/d (45 percent liquids).
The Company continues to expect 2021 annual capital spending to be between $265 million and $285 million, excluding land acquisitions and abandonment and reclamation activities.
Paramount is updating its forecast of 2021 free cash flow from approximately $140 million to approximately $185 million to reflect year-to-date actual results and revised commodity price and other assumptions for the second half of 2021. This forecast is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $44.00/Boe (US$64.05/Bbl WTI, US$3.41/MMBtu NYMEX, $3.37/GJ AECO), (iv) royalties of $3.90/Boe, (v) operating costs of $11.20/Boe and (vi) transportation and processing costs of $4.00/Boe.
Approximately 53 percent of forecast midpoint production is hedged over the second half of 2021. After taking such hedging into account, 2021 forecast free cash flow would still be approximately $140 million at an average WTI oil price of US$50.00/Bbl over the second half of the year and would rise to $210 million at an average WTI oil price of US$75.00/Bbl over the second half of the year.
The Company currently prioritizes the allocation of free cash flow to: (i) achieving a targeted range of net debt to adjusted funds flow of between 1.0x and 2.0x; (ii) shareholder returns; and (iii) incremental growth. Free cash flow in 2021 is expected to be directed towards debt reduction and the payment of dividends, with the Company maintaining the flexibility to make purchases of Common Shares under the NCIB. Year-end net debt to adjusted funds flow is now anticipated to be approximately 1.0x based on forecast 2021 free cash flow and a monthly dividend of $0.02 per Common Share.
Paramount’s previously announced preliminary 2022 capital spending and sales volumes guidance remains unchanged. The Company continues to anticipate 2022 spending, excluding land acquisitions and abandonment and reclamation activities, to range between $325 million and $385 million. A capital program in this range would be expected to result in 2022 annual sales volumes of between 84,000 Boe/d and 88,000 Boe/d (45 percent liquids) and free cash flow of approximately $320 million, based on the following updated assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $30 million in abandonment and reclamation costs, (iii) realized pricing of $43.20/Boe (US$62.18/Bbl WTI, US$3.30/MMBtu NYMEX, $3.10/GJ AECO), (iv) royalties of $4.15/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing costs of $3.85/Boe. If all free cash flow was directed towards debt reduction, year-end 2022 net debt to adjusted funds flow would be less than 0.5x.
AUGUST DIVIDEND
The Board of Directors has declared a cash dividend of $0.02 per Common Share that will be payable on August 31, 2021 to shareholders of record on August 16, 2021. The dividend will be designated as an “eligible dividend” for Canadian income tax purposes.
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Grande Prairie Region sales volumes and netbacks are summarized below:(1)
Q2 2021 |
Q1 2021 |
% Change |
||||||||
Sales volumes |
||||||||||
Natural gas (MMcf/d) |
134.3 |
122.6 |
10 |
|||||||
Condensate and oil (Bbl/d) |
24,090 |
23,974 |
– |
|||||||
Other NGLs (Bbl/d) |
2,874 |
2,984 |
(4) |
|||||||
Total (Boe/d) |
49,345 |
47,385 |
4 |
|||||||
% liquids |
55% |
57% |
||||||||
Netback |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
% Change in $ |
|||||
Petroleum and natural gas sales |
217.7 |
48.47 |
194.0 |
45.50 |
12 |
|||||
Royalties |
(15.3) |
(3.40) |
(11.6) |
(2.72) |
32 |
|||||
Operating expense |
(48.8) |
(10.88) |
(49.0) |
(11.49) |
– |
|||||
Transportation and NGLs processing |
(21.4) |
(4.76) |
(20.0) |
(4.69) |
7 |
|||||
132.2 |
29.43 |
113.4 |
26.60 |
17 |
||||||
(1) |
“Netback” is a Non-GAAP financial measure. See “Non-GAAP Financial Measures” in the Advisories section. |
KARR AREA
Karr sales volumes and netbacks are summarized below:
Q2 2021 |
Q1 2021 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
107.6 |
90.2 |
19 |
||
Condensate and oil (Bbl/d) |
18,458 |
16,095 |
15 |
||
Other NGLs (Bbl/d) |
2,281 |
2,108 |
8 |
||
Total (Boe/d) |
38,679 |
33,230 |
16 |
||
% liquids |
54% |
55% |
|||
Netback |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
% Change in $ |
Petroleum and natural gas sales |
168.0 |
47.72 |
132.5 |
44.31 |
27 |
Royalties |
(13.1) |
(3.72) |
(8.6) |
(2.89) |
52 |
Operating expense |
(33.1) |
(9.40) |
(31.9) |
(10.67) |
4 |
Transportation and NGLs processing |
(16.0) |
(4.52) |
(14.0) |
(4.68) |
14 |
105.8 |
30.08 |
78.0 |
26.07 |
36 |
Second quarter sales volumes at Karr averaged 38,679 Boe/d (54 percent liquids) compared to 33,230 Boe/d (55 percent liquids) in the first quarter. The increase in sales volumes was driven by strong performance from the six well 3-10 pad that was brought onstream in February and continues to outperform internal type well projections as well as production contributions from the three well 4-28 pad that was brought onstream in late April. Sales volumes also benefitted from additional gas lift compression installed in the first quarter that became fully operational in April. Combined, these more than offset the impact of scheduled curtailments at the third-party Karr 6-18 facility related to inlet separation and liquids handling optimization that reduced sales volumes by approximately 50 percent for seven days in May.
The 4-28 pad has performed in line with internal type well projections, averaging gross peak 30-day production per well of 1,295 Boe/d (3.4 MMcf/d of shale gas and 728 Bbl/d of NGLs) with an average CGR of 214 Bbl/MMcf.(1)
Paramount continues to focus on driving DCET costs lower while maintaining well performance and has realized cost improvements relative to previous pacesetting results. Preliminary all-in DCET costs at the five well Karr 7-18 pad, which was brought on production in late July 2021, averaged a pacesetting $6.0 million per well. This represents an approximate 11 percent reduction relative to average DCET costs of the last two pads at Karr. Continued outperformance from the 3-10 pad coupled with strong commodity prices has resulted in all wells on the 3-10 pad paying out in June, four months after coming onstream.
Drilling operations on the five well 5-16 East pad were completed in the second quarter. The average spud to rig release time for this pad came in at just under 24 days, 12 percent faster than on the 5-16 West pad drilled last year from the same surface location. The Company plans to complete the pad late in the third quarter and equip and tie-in the wells in the fourth quarter. The Company recently started drilling operations on the ten well 16-17 pad and expects that seven of the ten wells will be drilled by year-end.
Karr unit operating costs trended lower in the second quarter as a result of higher production volumes combined with a continued focus on capturing efficiencies and streamlining operations. Paramount achieved operating costs at Karr of $9.40/Boe in the second quarter of 2021, lower than targeted operating costs of $10.00/Boe at plateau production of approximately 40,000 Boe/d.
Royalties at Karr increased in the second quarter of 2021 compared to the first quarter as a result of higher volumes and prices as well as a number of wells having fully utilized their new well royalty incentives.
_____________________________ |
|
(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 7% and liquids sales volumes are lower by approximately 6% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section. |
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
Q2 2021 |
Q1 2021 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
26.4 |
32.1 |
(18) |
||
Condensate and oil (Bbl/d) |
5,629 |
7,884 |
(29) |
||
Other NGLs (Bbl/d) |
582 |
867 |
(33) |
||
Total (Boe/d) |
10,604 |
14,107 |
(25) |
||
% liquids |
59% |
62% |
|||
Netback |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
% Change in $ |
Petroleum and natural gas sales |
49.6 |
51.41 |
61.4 |
48.42 |
(19) |
Royalties |
(2.1) |
(2.24) |
(2.9) |
(2.32) |
(30) |
Operating expense |
(15.4) |
(16.00) |
(16.8) |
(13.25) |
(8) |
Transportation and NGLs processing |
(5.5) |
(5.65) |
(6.0) |
(4.73) |
(9) |
26.6 |
27.52 |
35.7 |
28.12 |
(26) |
Second quarter sales volumes at Wapiti averaged 10,604 Boe/d (59 percent liquids) compared to 14,107 Boe/d (62 percent liquids) in the first quarter due to natural declines, the temporary shut-in of certain offsetting wells due to completion activities at the 6-4 pad and production curtailments at the third-party Wapiti natural gas processing facility caused by high ambient temperatures in June.
Production in July 2021 was impacted by the previously disclosed scheduled ten-day outage at the third-party Wapiti natural gas processing facility. This outage, which was undertaken to permanently address the source of the unscheduled outage that occurred at the facility in the third quarter of 2020, was completed as planned and the Company has restored production.
The seven well 6-4 pad was brought onstream in early July with encouraging initial results. DCET costs averaged a pacesetting $6.9 million per well, representing a nine percent reduction compared to average Wapiti DCET costs in 2020.
The Company has commenced drilling the seven well 9-22 pad, which is scheduled to be brought onstream in December 2021 along with the previously drilled and completed 10-22 well. The Company has also commenced the installation of infrastructure that will be operational later in 2021 and will accommodate production growth at Wapiti.
KAYBOB REGION
Kaybob Region sales volumes averaged 22,688 Boe/d (28 percent liquids) in the second quarter of 2021 compared to 24,938 Boe/d (28 percent liquids) in the first quarter. The decrease in production was due to natural declines and non-core asset dispositions completed in the first quarter.
Paramount holds material positions in the Duvernay and Montney resource plays in the Kaybob Region that will compete for capital in the medium term. In 2022, the Company has preliminary plans to drill, complete and tie-in a four well Duvernay pad at Kaybob Smoky and a three well Duvernay pad at Kaybob North on an existing pad where one of the three wells was previously drilled in 2019. The Company expects to realize capital cost efficiencies in its Kaybob Duvernay plays, similar to the gains achieved over the past 18 months at Karr and Wapiti, as it commences pad development and captures economies of scale. These lower costs are expected to materially improve Duvernay economics.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 7,962 Boe/d (13 percent liquids) in the second quarter of 2021 compared to 8,217 Boe/d (14 percent liquids) in the first quarter.
The Company holds a material, contiguous Duvernay position at Willesden Green and continues to actively evaluate longer-term full field development plans for this asset. Drilling, completion and equipping of a two well, liquids rich Duvernay pad in the Willesden Green area was recently completed and Paramount plans to tie-in and bring both wells on production in late August.
HEDGING
Subsequent to June 30, 2021, the Company entered into the following oil and natural gas hedges:
Further details of Paramount’s commodity hedging position are provided in its second quarter 2021 Management’s Discussion and Analysis and Consolidated Financial Statements.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company’s principal properties are located in Alberta and British Columbia. Paramount’s class A common shares are listed on the Toronto Stock Exchange under the symbol “POU”.
Paramount’s second quarter 2021 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at: https://mma.prnewswire.com/media/1587964/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_Second.pdf
A summary of historical financial and operating results is also available on Paramount’s website at http://www.paramountres.com/investor-relations/financial-reports#2021.
This information will also be made available through Paramount’s website at www.paramountres.com and on SEDAR at www.sedar.com.
FINANCIAL AND OPERATING RESULTS (1) ($ millions, except as noted) |
||||||||
Q2 2021 |
Q1 2021 |
|||||||
Net loss |
(74.3) |
(82.5) |
||||||
per share – basic and diluted ($/share) |
(0.56) |
(0.62) |
||||||
Cash from operating activities |
112.1 |
81.3 |
||||||
per share – basic and diluted ($/share) |
0.84 |
0.61 |
||||||
Adjusted funds flow |
86.0 |
90.9 |
||||||
per share – basic and diluted ($/share) |
0.65 |
0.69 |
||||||
Total assets |
3,655.6 |
3,583.1 |
||||||
Long-term debt |
608.4 |
712.7 |
||||||
Net debt |
724.5 |
761.7 |
||||||
Common shares outstanding (thousands) (2) |
133,314 |
132,754 |
||||||
Sales volumes |
||||||||
Natural gas (MMcf/d) |
273.1 |
273.1 |
||||||
Condensate and oil (Bbl/d) |
29,543 |
29,854 |
||||||
Other NGLs (Bbl/d) (3) |
4,938 |
5,170 |
||||||
Total (Boe/d) |
79,995 |
80,540 |
||||||
% liquids |
43% |
43% |
||||||
Grande Prairie Region (Boe/d) |
49,345 |
47,385 |
||||||
Kaybob Region (Boe/d) |
22,688 |
24,938 |
||||||
Central Alberta and Other Region (Boe/d) |
7,962 |
8,217 |
||||||
Total (Boe/d) |
79,995 |
80,540 |
||||||
Netback |
$/Boe (4) |
$/Boe (4) |
||||||
Natural gas revenue |
74.8 |
3.01 |
77.3 |
3.14 |
||||
Condensate and oil revenue |
209.6 |
77.96 |
185.9 |
69.20 |
||||
Other NGLs revenue (3) |
14.4 |
32.11 |
15.0 |
32.29 |
||||
Royalty and other revenue |
0.9 |
─ |
1.7 |
─ |
||||
Petroleum and natural gas sales |
299.7 |
41.17 |
279.9 |
38.61 |
||||
Royalties |
(24.9) |
(3.43) |
(18.6) |
(2.57) |
||||
Operating expense |
(81.8) |
(11.23) |
(84.3) |
(11.63) |
||||
Transportation and NGLs processing (5) |
(30.3) |
(4.16) |
(27.9) |
(3.84) |
||||
Netback |
162.7 |
22.35 |
149.1 |
20.57 |
||||
Financial commodity contract settlements |
(54.1) |
(7.44) |
(32.7) |
(4.51) |
||||
Netback including financial commodity contract settlements |
108.6 |
14.91 |
116.4 |
16.06 |
||||
|
||||||||
Grande Prairie Region |
66.5 |
51.3 |
||||||
Kaybob Region |
3.9 |
5.0 |
||||||
Central Alberta and Other Region |
11.8 |
1.2 |
||||||
Corporate (6) |
1.2 |
1.8 |
||||||
Land acquisitions |
0.1 |
─ |
||||||
Total capital expenditures |
83.5 |
59.3 |
||||||
|
3.2 |
8.4 |
(1) |
Readers are referred to the advisories concerning Non-GAAP Financial Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP financial measures: Adjusted funds flow, Net debt, Netback and Total capital expenditures. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by the specific product types. |
(2) |
Common shares are presented net of shares held in trust under the Company’s restricted share unit plan (000’s of common shares): Q2 2021: 1,538 and Q1 2021: 1,914. |
(3) |
Other NGLs means ethane, propane and butane. |
(4) |
Natural gas revenue presented as $/Mcf. |
(5) |
Includes downstream transportation costs and NGLs fractionation costs. |
(6) |
Includes transfers between regions. |
PRODUCT TYPE INFORMATION
This press release refers to sales volumes of “liquids”, “natural gas”, “condensate and oil” and “other NGLs”. “Liquids” means NGLs (including condensate) and oil combined, “natural gas” refers to conventional natural gas and shale gas combined, “condensate and oil” refers to condensate, light and medium crude oil and tight oil combined and “other NGLs” refers to ethane, propane and butane combined. Below is a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. Numbers may not add due to rounding.
Total |
Grande Prairie Region |
Kaybob Region |
Central Alberta and |
|||||
Q2 2021 |
Q1 2021 |
Q2 2021 |
Q1 2021 |
Q2 2021 |
Q1 2021 |
Q2 2021 |
Q1 2021 |
|
Shale gas (MMcf/d) |
205.8 |
197.8 |
132.2 |
120.6 |
39.3 |
42.1 |
34.3 |
35.1 |
Conventional natural gas (MMcf/d) |
67.3 |
75.3 |
2.1 |
2.0 |
58.0 |
65.8 |
7.2 |
7.5 |
Natural gas (MMcf/d) |
273.1 |
273.1 |
134.3 |
122.6 |
97.3 |
107.9 |
41.5 |
42.6 |
Condensate (Bbl/d) |
26,784 |
27,017 |
24,086 |
23,974 |
2,319 |
2,611 |
379 |
433 |
Other NGLs (Bbl/d) |
4,938 |
5,170 |
2,874 |
2,984 |
1,569 |
1,677 |
495 |
509 |
NGLs (Bbl/d) |
31,722 |
32,187 |
26,960 |
26,958 |
3,888 |
4,288 |
874 |
942 |
Tight oil (Bbl/d) |
494 |
479 |
– |
– |
354 |
342 |
140 |
136 |
Light and medium crude oil (Bbl/d) |
2,265 |
2,358 |
4 |
– |
2,224 |
2,321 |
37 |
37 |
Crude oil (Bbl/d) |
2,759 |
2,837 |
4 |
– |
2,578 |
2,663 |
177 |
173 |
Total (Boe/d) |
79,995 |
80,540 |
49,345 |
47,385 |
22,688 |
24,938 |
7,962 |
8,217 |
Karr |
Wapiti |
|||
Q2 2021 |
Q1 2021 |
Q2 2021 |
Q1 2021 |
|
Shale gas (MMcf/d) |
106.3 |
89.1 |
25.9 |
31.5 |
Conventional natural gas (MMcf/d) |
1.3 |
1.1 |
0.5 |
0.6 |
Natural gas (MMcf/d) |
107.6 |
90.2 |
26.4 |
32.1 |
NGLs (Bbl/d) |
20,739 |
18,203 |
6,211 |
8,751 |
Total (Boe/d) |
38,679 |
33,230 |
10,604 |
14,107 |
The Company forecasts that 2021 sales volumes will average between 80,000 Boe/d and 82,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2021 sales volumes are expected to average between 80,000 Boe/d and 84,000 Boe/d (55% shale gas and conventional natural gas combined, 39% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).
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