Paramount Resources Ltd. Announces Second Quarter 2024 Results
CALGARY, AB, Aug. 1, 2024 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its second quarter 2024 financial and operating results, highlighted by strong adjusted funds flow and well results at Kaybob North that continue to demonstrate the high quality of the Company's Duvernay position.
HIGHLIGHTS
- Second quarter sales volumes averaged 95,609 Boe/d (48% liquids). (1)
- Grande Prairie Region sales volumes averaged 63,480 Boe/d (51% liquids), consistent with Paramount's expectations. Sales volumes were restricted by planned maintenance outages and some unplanned downtime at key facilities.
- Kaybob Region sales volumes increased to 23,946 Boe/d (41% liquids), driven by a new five well Duvernay pad brought onstream at Kaybob North.
- Central Alberta and Other Region sales volumes averaged 8,183 Boe/d (49% liquids).
- The continued strong results from Paramount's drilling program at Kaybob North and Willesden Green grew the Company's total Duvernay production in the quarter to an average of approximately 15,000 Boe/d (63% liquids).
- The Company shut-in a total of 4,600 Boe/d of dry gas production in the quarter due to low natural gas prices.
- First half 2024 sales volumes averaged 98,293 Boe/d (48% liquids), in line with the midpoint of the Company's guidance of 96,000 Boe/d to 100,000 Boe/d (47% liquids).
- Cash from operating activities was $221 million ($1.51 per basic share) in the second quarter. Adjusted funds flow was $266 million ($1.82 per basic share). Free cash flow was $20 million ($0.14 per basic share). (2)
__________________________________________ |
|
(1) |
In this press release, "natural gas" refers to shale gas and conventional natural gas combined, "condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude oil combined, "Other NGLs" refers to ethane, propane and butane and "liquids" refers to condensate and oil and Other NGLs 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, light and medium crude oil, tight oil and heavy crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section. |
(2) |
Adjusted funds flow and free cash flow are capital management measures used by Paramount. Cash from operating activities per basic share, adjusted funds flow per basic share and free cash flow per basic share are supplementary financial measures. Refer to the "Specified Financial Measures" section for more information on these measures. |
- Second quarter capital expenditures totaled $241 million. Significant activities included:
- Grande Prairie Region (Montney) – eleven (11.0 net) wells drilled, four (4.0 net) wells brought on production and the substantial completion of a new compressor node at Wapiti that will support the development of the western portion of the field;
- Kaybob Region (Duvernay) – five (5.0 net) wells drilled and five (5.0 net) wells brought on production; and
- Central Alberta and Other Region (Duvernay) – four (4.0 net) wells drilled and the ongoing construction of the Company's second operated natural gas processing plant at Willesden Green.
- Asset retirement obligations settled in the second quarter totaled $2 million.
- As previously disclosed, Paramount sold 6 million shares of its investment in NuVista Energy Ltd. for cash proceeds of $75 million in the second quarter. The carrying value of the Company's investments in securities at June 30, 2024 was $580 million. Paramount received total cash dividends of $8 million in the second quarter from its investments in securities.
- In June 2024, Paramount realized total cash proceeds of $38 million from the termination and close out of all of its then outstanding NYMEX WTI swaps (14,250 Bbl/d at C$111.67/Bbl for the balance of 2024). Paramount has since hedged 5,000 Bbl/d of liquids sales from July 2024 to the end of 2025 at an average WTI price of C$105.00/Bbl.
- Revenue in the second quarter included $10 million related to an initial payment from insurers for 2023 Alberta wildfire losses. The Company continues to advance its insurance claims process.
- At June 30, 2024, net debt was $29 million and Paramount's $1.0 billion revolving credit facility was undrawn. (1)
_________________________________________ |
|
(1) |
Net (cash) debt is a capital management measure used by Paramount. This capital management measure has been expressed as net debt in this instance for simplicity as the amount referenced is a positive number. Refer to the "Specified Financial Measures" section for more information on this measure. |
GUIDANCE
Paramount is reaffirming its 2024 guidance for sales volumes. The Company currently has approximately 4,600 Boe/d of dry gas production shut-in. The 2024 sales volumes guidance assumes that this production, as well as certain new dry gas production, is brought online in the fourth quarter. If natural gas prices do not improve later in the year, as anticipated, the Company may choose to defer bringing this production online. In such a case, Paramount anticipates that 2024 sales volumes would be at the lower end of the forecast range.
The Company is reaffirming its 2024 guidance for capital expenditures and abandonment and reclamation expenditures.
Paramount is updating its forecast of 2024 free cash flow from $205 million to $100 million to reflect first half results and revised natural gas price assumptions for the second half of 2024 of US$2.50/MMBtu NYMEX and $1.50/GJ AECO (previously US$3.50/MMBtu NYMEX and $2.84/GJ AECO). Assumed WTI pricing for the second half of 2024 remains unchanged at US$80.00/Bbl.
2024 Guidance |
|
Annual average sales volumes (Boe/d) |
100,000 to 106,000 (48% liquids) |
Third quarter 2024 (Boe/d) |
96,000 to 104,000 (49% liquids) |
Fourth quarter 2024 (Boe/d) |
109,000 to 121,000 (48% liquids) |
Capital expenditures |
$830 to $890 million |
Sustaining and Maintenance |
$415 to $445 million |
Growth |
$415 to $445 million |
Abandonment and reclamation expenditures |
$40 million |
Free cash flow (1) |
$100 million |
The Company's midpoint 2024 sustaining and maintenance capital program, abandonment and reclamation expenditures and regular monthly dividend would remain fully funded down to an average WTI price for the second half of 2024 of about US$56/Bbl, assuming no changes to the other forecast assumptions.
AUGUST DIVIDEND
Paramount's Board of Directors has declared a cash dividend of $0.15 per class A common share that will be payable on August 30, 2024 to shareholders of record on August 15, 2024. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.
__________________________________________ |
|
(1) |
Free cash flow is a capital management measure used by Paramount. Refer to the "Specified Financial Measures" section for more information on this measure. The stated free cash flow forecast is based on the following assumptions for 2024: (i) the midpoint of stated capital expenditures and sales volumes, (ii) $40 million in abandonment and reclamation costs, (iii) $10 million in geological and geophysical expenses, (iv) realized pricing of $51.45/Boe; (v) a $US/$CAD exchange rate of $0.736, (vi) royalties of $7.55/Boe, (vii) operating costs of $13.30/Boe and (vii) transportation and NGLs processing costs of $3.55/Boe. The stated amounts have been adjusted to incorporate actual results for the first half of 2024. |
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Sales volumes and netbacks in the Grande Prairie Region are summarized below:
Q2 2024 |
Q1 2024 |
% Change |
|||
Sales Volumes |
|||||
Natural gas (MMcf/d) |
187.3 |
201.8 |
(7) |
||
Condensate and oil (Bbl/d) |
28,083 |
29,202 |
(4) |
||
Other NGLs (Bbl/d) |
4,179 |
4,334 |
(4) |
||
Total (Boe/d) |
63,480 |
67,163 |
(5) |
||
% liquids |
51 % |
50 % |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
28.5 |
1.67 |
53.0 |
2.89 |
(46) |
Condensate and oil revenue |
264.9 |
103.63 |
248.0 |
93.32 |
7 |
Other NGLs revenue |
12.8 |
33.77 |
15.7 |
39.70 |
(18) |
Petroleum and natural gas sales |
306.2 |
53.01 |
316.7 |
51.81 |
(3) |
Royalties |
(56.9) |
(9.86) |
(50.8) |
(8.32) |
12 |
Operating expense |
(82.6) |
(14.29) |
(80.1) |
(13.11) |
3 |
Transportation and NGLs processing |
(21.9) |
(3.80) |
(22.6) |
(3.69) |
(3) |
144.8 |
25.06 |
163.2 |
26.69 |
(11) |
|
(1) |
"Netback" is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the "Specified Financial Measures" section for more information on these measures. |
(2) |
Per unit natural gas revenue presented as $/Mcf. |
Second quarter 2024 sales volumes in the Grande Prairie Region were consistent with Paramount's expectations, averaging 63,480 Boe/d (51% liquids) compared to 67,163 Boe/d (50% liquids) in the first quarter. Although field deliverability has been enhanced as a result of the previously disclosed well optimization program, second quarter sales volumes were restricted by planned maintenance outages at two third-party natural gas processing facilities. Sales volumes were further restricted by start-up issues and unplanned downtime at one of these plants, which have since been largely resolved.
The well optimization program that was initiated in the first quarter is ongoing and has resulted in improved deliverability. There are currently 11 wells that the Company believes could benefit from intervention in the Grande Prairie Region. The magnitude of incremental contribution from these wells is expected to be less as the Company focused on the highest impact wells first.
Development activities in the Grande Prairie Region in the second quarter included the drilling of eleven (11.0 net) Montney wells, the completion of eleven (11.0 net) Montney wells and the bringing onstream of four (4.0 net) Montney wells. The construction of a new compressor node in the western portion of the Wapiti field was concluded and commissioned in July, approximately one month ahead of schedule. This has allowed the Company to bring a new seven (7.0 net) well Montney pad on production earlier than forecast. The pad has been brought on at restricted rates, initially through temporary equipment and more recently through permanent facilities.
Paramount plans to drill a total of 16 (16.0 net) Montney wells and bring on production a total of 27 (27.0 net) Montney wells in the Grande Prairie Region in the second half of 2024. As previously disclosed, third quarter sales volumes will be impacted by a planned 21-day full outage at the Wapiti natural gas processing plant.
KAYBOB REGION
Kaybob Region sales volumes averaged 23,946 Boe/d (41% liquids) in the second quarter of 2024 compared to 22,353 Boe/d (42% liquids) in the first quarter. Sales volumes increased as a result of new well production from a five (5.0 net) well Kaybob North Duvernay pad that came on production part way through the second quarter. The shut-in of certain dry gas wells due to low natural gas prices partially offset production contributions from this pad. In light of low natural gas pricing, Paramount shut-in 1,800 Boe/d of Kaybob Region dry gas production in the second quarter and does not expect to bring this production back on until late 2024 when prices are forecast to improve.
Development activities in the second quarter included the drilling of five (5.0 net) Duvernay wells and the completion and bringing on production of a five (5.0 net) well Duvernay pad at Kaybob North.
Initial production from the five well Duvernay pad brought onstream at Kaybob North in the second quarter averaged gross 30-day peak production per well of 1,028 Boe/d (1.1 MMcf/d of shale gas and 853 Bbl/d of NGLs) with an average CGR of 814 Bbl/MMcf. (1) The wells on this pad have been flowing at restricted rates due to facility constraints.
Paramount plans to drill five (5.0 net) Duvernay wells and bring on production six (6.0 net) Duvernay wells at Kaybob North in the second half of 2024.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 8,183 Boe/d (49% liquids) in the second quarter of 2024 compared to 11,461 Boe/d (44% liquids) in the first quarter. In the second quarter, the Company shut-in approximately 2,800 Boe/d of dry gas production in northeast British Columbia due to low natural gas prices.
Paramount finished the drilling of a new six (6.0 net) well Duvernay pad in Willesden Green in the second quarter. The Company plans to complete and bring onstream three of these wells in the third quarter and the remaining three wells in 2025 when sufficient processing capacity is expected to be available.
The construction of the Company's second operated natural gas processing plant in the Willesden Green area is ongoing. Paramount continues to anticipate start-up of the plant in the fourth quarter of 2025.
The Company plans to drill five (5.0 net) Duvernay wells and bring on production three (3.0 net) Duvernay wells at Willesden Green in the second half of 2024. Third quarter sales volumes will be impacted by the planned shut-in of certain legacy wells on the Willesden Green Duvernay 04-07 pad for two weeks as completion operations are conducted on three new wells on this pad. The Company capitalized on this planned downtime by taking a 9-day full outage of the Company's Leafland natural gas processing plant to conduct preventative maintenance and minor repair work.
________________________________________ |
|
(1) |
30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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. Natural gas sales volumes were lower by approximately 15% and liquids sales volumes were lower by approximately 12% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone. |
HEDGING
The Company's current commodity and foreign exchange contracts are summarized below:
Q3 2024 |
Q4 2024 |
2025 |
Average Price (1) |
- |
||
Oil |
||||||
NYMEX WTI Swaps (Sale) (Bbl/d) |
5,000 |
5,000 |
5,000 |
C$105.00/Bbl |
||
Natural gas |
||||||
AECO – Basis (Physical Sale) (MMBtu/d) |
40,000 |
13,478 |
– |
NYMEX less US$0.93/MMBtu (2) |
||
Malin / Citygate Basis Swap (Sale) (MMBtu/d) |
10,000 |
10,000 |
10,000 |
Citygate less US$1.03/MMBtu (3) |
||
Foreign Currency Exchange |
||||||
Swaps (Sale) (US$ million / month) |
$30 |
$30 |
– |
1.3462 C$ / US$ |
(1) |
Average price is calculated using a weighted average of notional volumes and prices. |
(2) |
"NYMEX" means NYMEX pricing at Henry Hub. The contract has a notional volume of 40,000 MMBtu/d for a term of July 2024 to October 2024. |
(3) |
"Malin" refers to Pacific Gas & Electric at Malin and "Citygate" refers to Pacific Gas & Electric Citygate. The term of this contract is July 2024 to October 2027. |
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-rich natural gas focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas, 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 Common Shares are listed on the Toronto Stock Exchange under the symbol "POU".
Paramount's second quarter 2024 results, including Management's Discussion and Analysis and the Company's Interim Consolidated Financial Statements, can be obtained on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.
A summary of historical financial and operating results is also available on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.
FINANCIAL AND OPERATING RESULTS (1)
($ millions, except as noted) |
Q2 2024 |
Q1 2024 |
Q2 2023 |
|||
Net income |
84.5 |
68.1 |
74.2 |
|||
per share – basic ($/share) |
0.58 |
0.47 |
0.52 |
|||
per share – diluted ($/share) |
0.57 |
0.46 |
0.50 |
|||
Cash from operating activities |
220.5 |
201.3 |
172.2 |
|||
per share – basic ($/share) |
1.51 |
1.39 |
1.20 |
|||
per share – diluted ($/share) |
1.47 |
1.35 |
1.16 |
|||
Adjusted funds flow |
266.2 |
225.6 |
178.7 |
|||
per share – basic ($/share) |
1.82 |
1.56 |
1.25 |
|||
per share – diluted ($/share) |
1.78 |
1.52 |
1.21 |
|||
Free cash flow |
20.3 |
(9.5) |
30.5 |
|||
per share – basic ($/share) |
0.14 |
(0.07) |
0.21 |
|||
per share – diluted ($/share) |
0.14 |
(0.07) |
0.21 |
|||
Total assets |
4,589.2 |
4,458.9 |
4,106.6 |
|||
Investments in securities |
579.5 |
568.6 |
489.9 |
|||
Long-term debt |
– |
– |
– |
|||
Net (cash) debt |
29.3 |
68.4 |
2.3 |
|||
Common shares outstanding (millions) (2) |
146.7 |
145.2 |
143.1 |
|||
Sales volumes (3) |
||||||
Natural gas (MMcf/d) |
296.8 |
318.7 |
290.2 |
|||
Condensate and oil (Bbl/d) |
39,206 |
40,908 |
34,230 |
|||
Other NGLs (Bbl/d) |
6,928 |
6,954 |
5,648 |
|||
Total (Boe/d) |
95,609 |
100,977 |
88,243 |
|||
% liquids |
48 % |
47 % |
45 % |
|||
Grande Prairie Region (Boe/d) |
63,480 |
67,163 |
66,950 |
|||
Kaybob Region (Boe/d) |
23,946 |
22,353 |
13,238 |
|||
Central Alberta & Other Region (Boe/d) |
8,183 |
11,461 |
8,055 |
|||
Total (Boe/d) |
95,609 |
100,977 |
88,243 |
|||
Netback |
($/Boe) (4) |
($/Boe) (4) |
($/Boe) (4) |
|||
Natural gas revenue |
45.6 |
1.69 |
82.4 |
2.84 |
64.1 |
2.43 |
Condensate and oil revenue |
367.7 |
103.07 |
344.8 |
92.64 |
294.1 |
94.42 |
Other NGLs revenue |
20.8 |
33.07 |
23.9 |
37.81 |
15.9 |
30.86 |
Royalty income and other revenue (5) |
9.5 |
– |
1.2 |
– |
0.3 |
– |
Petroleum and natural gas sales |
443.6 |
50.99 |
452.3 |
49.24 |
374.4 |
46.63 |
Royalties |
(66.1) |
(7.60) |
(61.8) |
(6.73) |
(41.2) |
(5.12) |
Operating expense |
(115.7) |
(13.29) |
(118.9) |
(12.94) |
(104.6) |
(13.03) |
Transportation and NGLs processing |
(31.3) |
(3.60) |
(31.9) |
(3.47) |
(33.6) |
(4.19) |
Sales of commodities purchased (6) |
84.4 |
9.70 |
54.7 |
5.95 |
47.7 |
5.94 |
Commodities purchased (6) |
(82.4) |
(9.47) |
(53.4) |
(5.81) |
(49.3) |
(6.15) |
Netback |
232.5 |
26.73 |
241.0 |
26.24 |
193.4 |
24.08 |
Risk management contract settlements |
36.4 |
4.18 |
(0.5) |
(0.05) |
(2.7) |
(0.33) |
Netback including risk management contract |
268.9 |
30.91 |
240.5 |
26.19 |
190.7 |
23.75 |
Capital expenditures |
||||||
Grande Prairie Region |
154.8 |
120.2 |
66.0 |
|||
Kaybob Region |
40.9 |
56.3 |
45.5 |
|||
Central Alberta & Other Region |
45.9 |
39.8 |
17.1 |
|||
Fox Drilling and Cavalier Energy |
0.7 |
4.1 |
7.6 |
|||
Corporate (7) |
(1.5) |
(6.5) |
4.0 |
|||
Total |
240.8 |
213.9 |
140.2 |
|||
Asset retirement obligations settled |
2.3 |
16.5 |
5.9 |
|||
(1) |
Adjusted funds flow, free cash flow and net (cash) debt are capital management measures used by Paramount. Netback and netback including risk management contract settlements are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income, that is presented on a per share, $/Mcf or $/Boe basis is a supplementary financial measure. Refer to "Specified Financial Measures". |
(2) |
Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q2 2024: 0.2 million, Q1 2024: 0.4 million, Q2 2023: 0.4 million. |
(3) |
Refer to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product type. |
(4) |
Natural gas revenue presented as $/Mcf. |
(5) |
Royalty income and other revenue for the three months ended June 30, 2024 includes $10.0 million related to an initial payment from insurers for 2023 Alberta wildfire losses. This amount was not allocated to individual Regions or properties. The Company continues to advance its insurance claims process. |
(6) |
Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties. |
(7) |
Includes transfers between regions. |
PRODUCT TYPE INFORMATION
This press release includes references to sales volumes of "natural gas", "condensate and oil", "NGLs", "Other NGLs" and "liquids". "Natural gas" refers to shale gas and conventional natural gas combined. "Condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude oil combined. "NGLs" refers to condensate and Other NGLs combined. "Other NGLs" refers to ethane, propane and butane. "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, light and medium crude oil, tight oil and heavy crude oil. Numbers may not add due to rounding.
Total Company by Product |
||||||||||||||||||
Q2 2024 |
Q1 2024 |
Q2 2023 |
||||||||||||||||
Shale gas (MMcf/d) |
243.1 |
268.5 |
246.0 |
|||||||||||||||
Conventional natural gas (MMcf/d) |
53.7 |
50.2 |
44.2 |
|||||||||||||||
Natural gas (MMcf/d) |
296.8 |
318.7 |
290.2 |
|||||||||||||||
Condensate (Bbl/d) |
36,825 |
38,332 |
32,341 |
|||||||||||||||
Other NGLs (Bbl/d) |
6,928 |
6,954 |
5,648 |
|||||||||||||||
NGLs (Bbl/d) |
43,753 |
45,286 |
37,989 |
|||||||||||||||
Light and medium crude oil (Bbl/d) |
1,566 |
1,595 |
942 |
|||||||||||||||
Tight oil (Bbl/d) |
466 |
592 |
538 |
|||||||||||||||
Heavy crude oil (Bbl/d) |
349 |
389 |
409 |
|||||||||||||||
Crude oil (Bbl/d) |
2,381 |
2,576 |
1,889 |
|||||||||||||||
Total (Boe/d) |
95,609 |
100,977 |
88,243 |
|||||||||||||||
Grande Prairie Region |
Kaybob Region |
Central Alberta and Other |
||||||||||||||||
Q2 2024 |
Q1 2024 |
Q2 2023 |
Q2 2024 |
Q1 2024 |
Q2 2023 |
Q2 2024 |
Q1 2024 |
Q2 2023 |
||||||||||
Shale gas (MMcf/d) |
187.0 |
201.6 |
196.1 |
35.8 |
30.6 |
21.7 |
20.3 |
36.3 |
28.2 |
|||||||||
Conventional natural gas (MMcf/d) |
0.3 |
0.2 |
0.3 |
48.8 |
47.7 |
38.4 |
4.6 |
2.3 |
5.5 |
|||||||||
Natural gas (MMcf/d) |
187.3 |
201.8 |
196.4 |
84.6 |
78.3 |
60.1 |
24.9 |
38.6 |
33.7 |
|||||||||
Condensate (Bbl/d) |
27,936 |
29,061 |
30,046 |
6,617 |
6,038 |
1,301 |
2,272 |
3,233 |
994 |
|||||||||
Other NGLs (Bbl/d) |
4,179 |
4,334 |
4,012 |
1,599 |
1,480 |
891 |
1,150 |
1,140 |
745 |
|||||||||
NGLs (Bbl/d) |
32,115 |
33,395 |
34,058 |
8,216 |
7,518 |
2,192 |
3,422 |
4,373 |
1,739 |
|||||||||
Light and medium crude oil (Bbl/d) |
– |
– |
– |
1,544 |
1,573 |
914 |
22 |
22 |
28 |
|||||||||
Tight oil (Bbl/d) |
147 |
141 |
159 |
80 |
212 |
115 |
239 |
239 |
264 |
|||||||||
Heavy crude oil (Bbl/d) |
– |
– |
– |
– |
– |
– |
349 |
389 |
409 |
|||||||||
Crude oil (Bbl/d) |
147 |
141 |
159 |
1,624 |
1,785 |
1,029 |
610 |
650 |
701 |
|||||||||
Total (Boe/d) |
63,480 |
67,163 |
66,950 |
23,946 |
22,353 |
13,238 |
8,183 |
11,461 |
8,055 |
|||||||||
The Company forecasts that 2024 annual sales volumes will average between 100,000 Boe/d and 106,000 Boe/d (52% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% Other NGLs). Third quarter 2024 sales volumes are expected to average between 96,000 Boe/d and 104,000 Boe/d (51% shale gas and conventional natural gas combined, 42% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% Other NGLs). Fourth quarter 2024 sales volumes are expected to average between 109,000 Boe/d and 121,000 Boe/d (52% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% Other NGLs).
SPECIFIED FINANCIAL MEASURES
Non-GAAP Financial Measures
Netback and netback including risk management contract settlements are non-GAAP financial measures. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.
Netback equals petroleum and natural gas sales (the most directly comparable measure disclosed in the Company's primary financial statements) plus sales of commodities purchased less royalties, operating expense, transportation and NGLs processing expense and commodities purchased. Sales of commodities purchased and commodities purchased are treated as corporate items and are not allocated to individual regions or properties. Netback is used by investors and management to compare the performance of the Company's producing assets between periods.
Netback including risk management contract settlements equals netback after including (or deducting) risk management contract settlements received (paid). Netback including risk management contract settlements is used by investors and management to assess the performance of the producing assets after incorporating management's risk management strategies.
Refer to the table under the heading "Financial and Operating Results" in this press release for the calculation of netback and netback including risk management contract settlements for the three months ended June 30, 2024, March 31, 2024 and June 30, 2023.
Non-GAAP Ratios
Netback and netback including risk management contract settlements presented on a $/Boe basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.
Netback on a $/Boe basis is calculated by dividing netback (a non-GAAP financial measure) for the applicable period by the total sales volumes during the period in Boe. Netback including risk management contract settlements on a $/Boe basis is calculated by dividing netback including risk management contract settlements (a non-GAAP financial measure) for the applicable period by the total sales volumes during the period in Boe. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of sales volumes basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net (cash) debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 15 in the Interim Consolidated Financial Statements of Paramount as at and for the three and six months ended June 30, 2024 for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three and six months ended June 30, 2024 and 2023 and (iii) a calculation of net (cash) debt as at June 30, 2024 and December 31, 2023.
Supplementary Financial Measures
This press release contains supplementary financial measures expressed as: (i) cash from operating activities, adjusted funds flow and free cash flow on a per share – basic and per share – diluted basis and (ii) petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis.
Cash from operating activities, adjusted funds flow and free cash flow on a per share – basic basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average basic shares outstanding during the period determined under IFRS. Cash from operating activities, adjusted funds flow and free cash flow on a per share – diluted basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average diluted shares outstanding during the period determined under IFRS.
Petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis are calculated by dividing petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased, as applicable, over the referenced period by the aggregate units (Boe or Mcf) of sales volumes during such period.
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 sales volumes for 2024 and certain periods therein;
- planned capital expenditures in 2024 and the allocation thereof between sustaining and maintenance capital and growth capital;
- planned abandonment and reclamation expenditures in 2024;
- forecast free cash flow in 2024;
- planned exploration, development and production activities, including: (i) the expected timing of drilling, completing and bringing new wells on production; (ii) planned well optimizations and the anticipated impact thereof; (iii) the expected timing of completion of planned facilities, including a new natural gas processing facility at Willesden Green, (iv) a planned outage at the Wapiti natural gas processing plant and (iv) the expected timing of bringing shut-in natural gas production back on; and
- the potential payment of future dividends.
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;
- the impact of international conflicts, including in Ukraine and the Middle East;
- royalty rates, taxes and capital, operating, general & administrative and other costs;
- foreign currency exchange rates, interest rates and the rate and impacts of inflation;
- general business, economic and market conditions;
- the performance of wells and facilities;
- the availability to Paramount of the funds required for exploration, development and other operations and the meeting of commitments and financial obligations;
- the ability of Paramount to obtain equipment, materials, services and personnel in a timely manner and at expected and acceptable costs to carry out its activities;
- the ability of Paramount to secure adequate processing, transportation, fractionation, disposal and storage capacity on acceptable terms and the capacity and reliability of facilities;
- the ability of Paramount to obtain the volumes of water required for completion activities;
- the ability of Paramount to market its production successfully;
- the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated sales volumes, reserves additions, product yields and product recoveries) and operational improvements, efficiencies and results consistent with expectations;
- the timely receipt of required governmental and regulatory approvals;
- the application of regulatory requirements respecting abandonment and reclamation; and
- anticipated timelines and budgets being met in respect of: (i) drilling programs and other operations, including well completions and tie-ins, (ii) the construction, commissioning and start-up of new and expanded third-party and Company facilities, including the new natural gas processing facility at Willesden Green, and (iii) facility turnarounds and maintenance.
Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. Forward-looking information is based on expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information. The material risks and uncertainties include, but are not limited to:
- fluctuations in commodity prices;
- changes in capital spending plans and planned exploration and development activities;
- changes in foreign currency exchange rates, interest rates and the rate of inflation;
- the uncertainty of estimates and projections relating to future production, product yields (including condensate to natural gas ratios), revenue, free cash flow, reserves additions, product recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate processing, transportation, fractionation, disposal 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;
- risks associated with wildfires, including the risk of physical loss or damage to wells, facilities, pipelines and other infrastructure, prolonged disruptions in production, restrictions on the ability to access properties, interruption of electrical and other services and significant delays or changes to planned development activities and facilities maintenance;
- the ability to obtain equipment, materials, services and personnel in a timely manner and at expected and acceptable costs, including the potential effects of inflation and supply chain disruptions;
- potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities, including third-party facilities and the new natural gas processing facility at Willesden Green;
- processing, transportation, fractionation, disposal and storage outages, disruptions and constraints;
- potential limitations on access to the volumes of water required for completion activities due to drought, conditions of low river flow, government restrictions or other factors;
- 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 to fund, or to otherwise finance, planned exploration, development and operational activities and meet current and future commitments and obligations (including asset retirement obligations, processing, transportation, fractionation and similar commitments and obligations);
- changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
- the ability to obtain required governmental or regulatory approvals in a timely manner, and to obtain and maintain leases and licenses, including those required for the new natural gas processing facility at Willesden Green;
- the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
- uncertainties as to the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
- uncertainties regarding Indigenous claims and in maintaining relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, 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 its 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 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 section titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2023, which is available on SEDAR+ at www.sedarplus.ca or on the Company's website at www.paramountres.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 2024, 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.
Oil and Gas Measures and Definitions
Liquids |
Natural Gas |
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Bbl |
Barrels |
GJ |
Gigajoules |
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Bbl/d |
Barrels per day |
GJ/d |
Gigajoules per day |
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MBbl |
Thousands of barrels |
MMBtu |
Millions of British Thermal Units |
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NGLs |
Natural gas liquids |
MMBtu/d |
Millions of British Thermal Units per day |
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Condensate |
Pentane and heavier hydrocarbons |
Mcf |
Thousands of cubic feet |
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WTI |
West Texas Intermediate |
MMcf |
Millions of cubic feet |
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MMcf/d |
Millions of cubic feet per day |
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Oil Equivalent |
NYMEX |
New York Mercantile Exchange |
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Boe |
Barrels of oil equivalent |
AECO |
AECO-C reference price |
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MBoe |
Thousands of barrels of oil equivalent |
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MMBoe |
Millions of barrels of oil equivalent |
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Boe/d |
Barrels of oil equivalent per day |
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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 six months ended June 30, 2024, the value ratio between crude oil and natural gas was approximately 61:1. 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, 2023 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.
SOURCE Paramount Resources Ltd.
For further information, please contact: Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Executive Officer and Chairman; Paul R. Kinvig, Chief Financial Officer; Rodrigo (Rod) Sousa, Executive Vice President, Corporate Development and Planning, www.paramountres.com, Phone: (403) 290-3600
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