Paramount Resources Ltd. Announces Second Quarter 2022 Results, Updated Guidance, Complementary Asset Acquisition and Non-Core Infrastructure Disposition
CALGARY, AB, Aug. 3, 2022 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its second quarter 2022 financial and operating results, updated guidance, a highly complementary $68.5 million Duvernay acquisition in its Willesden Green core area and a $63.0 million non-core infrastructure disposition.
HIGHLIGHTS
- Sales volumes in July 2022 averaged an estimated 92,000 Boe/d (45% liquids) as production ramped-up following major turnarounds at third-party processing facilities affecting Karr and Wapiti in the second quarter, with July exit sales volumes exceeding 100,000 Boe/d .(1)
- The Company now expects second half 2022 sales volumes to average between 102,000 Boe/d and 106,000 Boe/d (46% liquids), 1,000 Boe/d higher than previous guidance.
- Second quarter 2022 sales volumes averaged 77,312 Boe/d (42% liquids) and were impacted by a longer-than-planned turnaround at a third-party facility affecting Karr and unplanned outages and curtailments at Wapiti.
- Karr sales volumes averaged 31,295 Boe/d (50% liquids). Production at Karr was shut-in for approximately three weeks during the second quarter for turnarounds at two third-party midstream facilities, eight days longer than planned.
- Sales volumes at Wapiti averaged 17,441 Boe/d (57% liquids). Wapiti production was impacted by unplanned outages and curtailments totaling approximately eleven days at the third-party Wapiti natural gas processing plant (the "Wapiti Plant") and associated infrastructure.
- This unplanned downtime impacted average second quarter sales volumes by approximately 6,000 Boe/d.
_______________________ |
|
(1) |
In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane. See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil and tight oil. See also "Oil and Gas Measures and Definitions" in the Advisories section. |
- Cash from operating activities was $318.9 million ($2.26 per basic share) in the second quarter. Adjusted funds flow was $258.3 million ($1.83 per basic share). Free cash flow was $68.3 million ($0.48 per basic share).(1)
- Second quarter capital expenditures totaled $184.1 million and were predominantly focused on development activities at Karr and Wapiti and in the Kaybob region.
- Net debt was $374.0 million at June 30, 2022, including drawings under the Company's credit facility of $231 million. Net debt does not account for the $469 million carrying value of the Company's investments in securities at June 30, 2022.(2)
- Abandonment and reclamation expenditures in the second quarter totaled $4.0 million, net of $1.3 million in funding under the Alberta Site Rehabilitation Program ("ASRP").
- Following the Company's second quarter Willesden Green Duvernay acquisition, Paramount entered into a definitive agreement in July to acquire additional Duvernay lands and production directly offsetting its existing 150,000+ net acre position in the Willesden Green area of Alberta for $68.5 million in cash prior to adjustments. The acquisition will add approximately 90,000 net acres, over 200 internally estimated drilling locations and approximately 1,700 Boe/d (55% liquids) of current production to the Willesden Green core area.(3) Implied transaction metrics are approximately $39,000 / Boe/d and 3.0x cash flow. The acquisition is expected to close in the third quarter subject to customary closing conditions.
- Also in July, Paramount entered into a definitive agreement for the sale of certain non-core infrastructure assets for approximately $63 million in cash prior to adjustments. The disposition is expected to close in the third quarter subject to customary closing conditions. Following closing, annual operating expenses are expected to increase by approximately $7.8 million (approximately $0.20/Boe).(4)
UPDATED 2022 GUIDANCE AND PRELIMINARY 2023 BUDGET
The Company's planned 2022 capital expenditures have been upwardly revised by $80 million at the midpoint to a range of between $600 million and $640 million. Most of the increase reflects the impact of higher than anticipated inflation. Paramount, through its Fox Drilling subsidiary, is also now budgeting $20 million in 2022 for the majority of the costs to construct a fifth super-spec walking rig that will be deployed in the Company's 2023 drilling program. The increase also reflects the pre-ordering of certain materials, particularly casing, required for the 2023 development program to ensure continued availability. 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. The Company continues to budget $33 million of abandonment and reclamation expenditures in 2022, net of approximately $8 million in funding under the ASRP.
The Company is increasing its second half 2022 average sales volume guidance by 1,000 Boe/d to between 102,000 Boe/d and 106,000 Boe/d (46% liquids), resulting in expected annual average sale volumes of between approximately 91,000 Boe/d and 93,000 Boe/d (45% liquids). Higher forecast production at Wapiti due to well out-performance and the acquisition of production through the pending Willesden Green acquisition is anticipated to more than offset lower than previously expected production at Karr resulting from changes to the timing of bringing new wells on production. Production volumes at Wapiti are now anticipated to reach the targeted plateau of 30,000 Boe/d by the end of 2022.
______________________ |
|
(1) |
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. |
(2) |
Net debt is a capital management measure used by Paramount. Refer to the "Specified Financial Measures" section for more information on this measure. |
(3) |
See also "Oil and Gas Measures and Definitions" in the Advisories section for additional information respecting internally estimated drilling locations. |
(4) |
Based on the midpoint of forecast 2023 sales volumes of 107,500 Boe/d. |
Paramount is updating its forecast of 2022 free cash flow to approximately $600 million from $710 million to reflect updated capital spending, commodity prices, production and other assumptions.(1)
The Company's 2022 capital program, targeted net debt reduction and regular monthly dividend would remain fully funded down to an average WTI price of about US$50/Bbl over the last two quarters of 2022.(2)
Paramount's anticipated 2023 capital expenditure budget, based on preliminary planning and current market conditions, has been upwardly revised by $115 million at the midpoint to a range of between $650 million and $700 million. The additional capital expenditures largely reflect the impact of higher inflation.
The Company continues to expect that a capital program in this range will result in 2023 average sales volumes of 105,000 Boe/d to 110,000 Boe/d (47% liquids).
Paramount is updating its estimate of 2023 free cash flow that would be expected from such a capital program to approximately $725 million from $820 million to reflect updated capital spending, commodity price and other assumptions.(3)
UPDATED FIVE-YEAR OUTLOOK
The Company is updating its five-year outlook to reflect updated capital expenditure expectations, recent commodity prices and other assumptions. Paramount now anticipates cumulative free cash flow through to the end of 2026 of approximately $3.9 billion (approximately $28 per basic share(4)), down from $4.1 billion. The Company now anticipates annual average capital expenditures of approximately $650 million (up from $550 million) and a compound annual production growth rate of approximately 7% (unchanged) through the period.(5)
DELIVERING ON FREE CASH FLOW PRIORITIES
Paramount's free cash flow priorities continue to be: (i) the achievement of its net debt target of about $300 million and the maintenance of conservative leverage levels thereafter, (ii) shareholder returns and (iii) incremental growth.
- The Company expects to achieve its net debt target of about $300 million in the fall. At this level, year-end 2022 net debt to adjusted funds flow would be less than 0.3x(6). Unallocated free cash flows may be directed at times to reduce net debt below the $300 million target to provide further financial flexibility.
- Paramount has increased shareholder returns by implementing a regular monthly dividend in July 2021 of $0.02 per share and increasing it three times to $0.10 per share beginning in May 2022. The Company also retains the flexibility to make repurchases of up to 7.6 million Common Shares under its normal course issuer bid, which was renewed in June 2022.
_________________ |
|
(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) $7 million in geological and geophysical expenses, (iv) realized pricing of $72.85/Boe (US$95.89/Bbl WTI, US$6.89/MMBtu NYMEX, $5.81/GJ AECO), (v) a $US/$CAD exchange rate of $0.781, (vi) royalties of $12.25/Boe, (vii) operating costs of $11.65/Boe and (viii) transportation and processing costs of $4.05/Boe. |
(2) |
Assuming no changes to the other forecast assumptions for 2022. |
(3) |
The revised free cash flow estimate is based on the following assumptions for 2023: (i) the midpoint of stated capital spending and production, (ii) $40 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $64.45/Boe (US$84.41/Bbl WTI, US$5.68/MMBtu NYMEX, $5.06/GJ AECO), (v) a $US/$CAD exchange rate of $0.777, (vi) royalties of $11.40/Boe, (vii) operating costs of $11.20/Boe and (vii) transportation and processing costs of $3.85/Boe. |
(4) |
Based on 141.2 million class A common shares ("Common Shares") outstanding at June 30, 2022. |
(5) |
The five-year outlook is based on preliminary planning and current market conditions and is subject to change. 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) approximately $7 million in annual geological and geophysical expenses, (iv) strip commodity prices and foreign exchange rates as at July 20, 2022, and (v) internal management estimates of future royalties, operating costs, transportation and processing costs and, in 2026, cash taxes. |
(6) |
Assuming 2022 adjusted funds flow in excess of $1 billion. |
- Incremental capital has been allocated to internal growth opportunities with the highest risk-adjusted rates of return and to accretive acquisitions in the Willesden Green Duvernay and Karr/Wapiti Montney.
AUGUST DIVIDEND
The Board of Directors has declared a cash dividend of $0.10 per Common Share that will be payable on August 31, 2022 to shareholders of record on August 15, 2022. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Grande Prairie Region sales volumes and netbacks are summarized below:
Q2 2022 |
Q1 2022 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
139.8 |
152.5 |
(8) |
||
Condensate and oil (Bbl/d) |
22,516 |
26,048 |
(14) |
||
Other NGLs (Bbl/d) |
2,914 |
3,267 |
(11) |
||
Total (Boe/d) |
48,736 |
54,737 |
(11) |
||
% liquids |
52 % |
54 % |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
85.1 |
6.69 |
72.1 |
5.25 |
18 |
Condensate and oil revenue |
276.4 |
134.91 |
277.1 |
118.21 |
– |
Other NGLs revenue |
17.1 |
64.31 |
18.1 |
61.47 |
(6) |
Royalty and other revenue (3) |
1.3 |
– |
10.7 |
– |
NM |
Petroleum and natural gas sales |
379.9 |
85.65 |
378.0 |
76.74 |
1 |
Royalties |
(62.9) |
(14.17) |
(61.4) |
(12.46) |
2 |
Operating expense |
(55.9) |
(12.61) |
(53.7) |
(10.89) |
4 |
Transportation and NGLs processing |
(22.1) |
(4.99) |
(23.2) |
(4.73) |
(5) |
239.0 |
53.88 |
239.7 |
48.66 |
– |
|
(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) |
Natural gas revenue presented as $/Mcf. |
|||||
(3) |
Second quarter royalty and other revenue includes $1.3 million (first quarter 2022: $10.6 million) in respect of a business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three and six months ended June 30, 2022. |
|||||
NM means not meaningful. |
||||||
KARR AREA
Karr sales volumes and netbacks are summarized below:
Q2 2022 |
Q1 2022 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
94.6 |
113.3 |
(17) |
||
Condensate and oil (Bbl/d) |
13,551 |
17,246 |
(21) |
||
Other NGLs (Bbl/d) |
1,978 |
2,475 |
(20) |
||
Total (Boe/d) |
31,295 |
38,611 |
(19) |
||
% liquids |
50 % |
51 % |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
56.3 |
6.54 |
53.1 |
5.21 |
6 |
Condensate and oil revenue |
166.0 |
134.60 |
182.4 |
117.56 |
(9) |
Other NGLs revenue |
11.6 |
64.31 |
14.4 |
64.60 |
(19) |
Royalty and other revenue |
– |
– |
0.1 |
– |
NM |
Petroleum and natural gas sales |
233.9 |
82.14 |
250.0 |
71.95 |
(6) |
Royalties |
(45.8) |
(16.09) |
(54.0) |
(15.52) |
(15) |
Operating expense |
(36.0) |
(12.65) |
(35.2) |
(10.14) |
2 |
Transportation and NGLs processing |
(15.2) |
(5.34) |
(16.1) |
(4.65) |
(6) |
136.9 |
48.06 |
144.7 |
41.64 |
(5) |
|
(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) |
Natural gas revenue presented as $/Mcf. |
NM means not meaningful. |
|
Second quarter 2022 sales volumes at Karr averaged 31,295 Boe/d (50% liquids) compared to 38,611 Boe/d (51% liquids) in the first quarter. Karr production was shut-in for approximately three weeks in the second quarter due to planned turnarounds at two third-party midstream facilities, impacting quarterly average production by an estimated 10,300 Boe/d. Approximately 3,500 Boe/d of this impact was due to one of the turnarounds extending eight days beyond schedule.
Drilling of the remaining five wells at the twelve-well 16-17 pad were recently completed. The Company plans to complete, tie-in and bring all five wells on production late in the third quarter, one month later than previously planned.
Drilling operations at the four-well 1-2 North pad are set to commence in the third quarter. Paramount plans to complete all four wells in the fourth quarter and tie-in and bring the wells on production early in 2023, two months later than previously planned.
The Company also plans to commence the drilling of ten wells on two five-well pads (4-2 North and 4-2 South), seven of which are anticipated to be drilled by year-end.
Paramount is bringing onstream additional gas lift compression later this year to support liquids production and continues to build out infrastructure to debottleneck future production.
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
Q2 2022 |
Q1 2022 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
45.2 |
39.2 |
15 |
||
Condensate and oil (Bbl/d) |
8,965 |
8,802 |
2 |
||
Other NGLs (Bbl/d) |
936 |
792 |
18 |
||
Total (Boe/d) |
17,441 |
16,126 |
8 |
||
% liquids |
57 % |
59 % |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
28.8 |
6.98 |
19.0 |
5.39 |
52 |
Condensate and oil revenue |
110.4 |
135.36 |
94.7 |
119.49 |
17 |
Other NGLs revenue |
5.5 |
64.30 |
3.7 |
51.67 |
49 |
Royalty and other revenue (3) |
1.3 |
– |
10.6 |
– |
NM |
Petroleum and natural gas sales |
146.0 |
91.94 |
128.0 |
88.20 |
14 |
Royalties |
(17.1) |
(10.72) |
(7.4) |
(5.13) |
131 |
Operating expense |
(19.9) |
(12.56) |
(18.5) |
(12.69) |
8 |
Transportation and NGLs processing |
(6.9) |
(4.35) |
(7.1) |
(4.92) |
(3) |
102.1 |
64.31 |
95.0 |
65.46 |
7 |
|
(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) |
Natural gas revenue presented as $/Mcf. |
|||||
(3) |
Second quarter royalty and other revenue includes $1.3 million (first quarter 2022: $10.6 million) in respect of a business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three and six months ended June 30, 2022. |
|||||
NM means not meaningful. |
||||||
Second quarter 2022 sales volumes at Wapiti averaged 17,441 Boe/d (57% liquids) compared to 16,126 Boe/d (59% liquids) in the first quarter, with the increase in sales volumes reflecting new production from the eight-well 8-22 pad that came onstream in early June. Wapiti was shut-in or curtailed for the equivalent of approximately 16 days in the second quarter due to a planned turnaround as well as unplanned outages and curtailments at the Wapiti Plant and associated infrastructure, impacting quarterly average production by an estimated 3,800 Boe/d. Approximately 2,500 Boe/d of this impact was due to the unplanned outages and curtailments.
All eight wells on the 8-22 pad came on production in the quarter. The 8-22 pad is the Company's first where all wells were configured as monobores. All-in drilling, completion, equipping and tie-in ("DCET") costs averaged $7.3 million. Initial production results have been encouraging, averaging gross peak 30-day production per well of 1,472 Boe/d (4.2 MMcf/d of shale gas and 778 Bbl/d of NGLs) with an average CGR of 187 Bbl/MMcf.(1)
The drilling of the eight-well 6-32 pad was completed in the second quarter. With completion operations recently finished, equip and tie-in activities have commenced and are expected to run through the third quarter with four wells anticipated to come onstream in September and the remaining four wells to come onstream in the fourth quarter.
______________________ |
|
(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 12% and liquids sales volumes are lower by approximately 2% 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. |
Drilling operations at the eight-well 16-15 pad commenced in the second quarter. The Company plans to complete, tie-in and bring on production two wells by year-end 2022 with the remaining six wells to come onstream in early 2023.
Paramount also plans to commence the drilling of the eight well 8-15 pad in the fourth quarter, with the drilling of the first four wells to be completed by the end of the year.
The performance of the 9-22 pad that was brought on production in late 2021 and early 2022, as well as a number of legacy wells, is contributing to the Company's higher production expectations at Wapiti in the second half of 2022.
Paramount now anticipates achieving targeted plateau production of 30,000 Boe/d at Wapiti by the end of the year.
KAYBOB REGION
Kaybob Region sales volumes averaged 21,642 Boe/d (27% liquids) in the second quarter of 2022 compared to 20,726 Boe/d (28% liquids) in the first quarter, with the increase resulting from three (2.5 net) new Montney wells and one (1.0 net) Gething oil well brought on production in the first half of 2022.
Development activities at the Company's Duvernay assets at Smoky and Kaybob North are ongoing. Completions operations at the four-well Smoky 10-35 pad that commenced in the second quarter are now complete and all four wells have recently been brought on production. Preliminary all-in DCET costs averaged $9.3 million per well. Work to expand the Company's 100% owned and operated 6-16 facility was also recently completed. Drilling of the two remaining wells at the three-well Kaybob North 12-21 pad was completed in the second quarter, completion operations were recently concluded and flow-testing is underway. Two of the wells on the 12-21 pad were drilled to a total lateral length of approximately 4,200 meters each, representing the longest laterals drilled by Paramount in the Kaybob Region. The Company anticipates all three wells on the pad will be brought onstream in the fourth quarter.
Paramount continues to advance a number of other high return opportunities in the Kaybob Region. In the second quarter the Company brought on production one (1.0 net) Montney oil well in the Kaybob Montney Oil field, one (0.5 net) Montney gas well in the Kaybob Presley field and one (1.0 net) Gething oil well in the Kaybob field. Two (1.0 net) additional Montney gas wells are anticipated to be drilled, completed and brought onstream by the fourth quarter. Recently, one (1.0 net) Gething oil well was brought on production.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 6,934 Boe/d (21% liquids) in the second quarter of 2022 compared to 6,674 Boe/d (22% liquids) in the first quarter, with the Duvernay acquisition that closed in April being the primary reason for the increase.
In July, the Company entered into a definitive agreement to acquire Duvernay lands and production directly offsetting its existing 150,000+ net acre position in the Willesden Green area of Alberta for $68.5 million in cash prior to adjustments. The acquisition will add approximately 90,000 net acres (after deducting near-term expiries), over 200 internally estimated drilling locations and approximately 1,700 Boe/d (55% liquids) of current production to the Willesden Green core area. Implied transaction metrics are approximately $39,000 / Boe/d and 3.0x cash flow. The acquisition is expected to close in the third quarter of 2022, subject to customary closing conditions.
This complimentary acquisition cements Paramount as the dominant operator in the emerging Willesden Green Duvernay play, allowing it to capture operational synergies across its asset base. On closing, Paramount will control approximately 250,000 net acres of contiguous land with over 600 internally high-graded drilling locations.(1) While work is ongoing on the full field development for the combined position, the high-graded drilling inventory supports preliminary targeted plateau production of over 50,000 Boe/d that can be sustained for over 20 years. Paramount continues to review its plans for Willesden Green and is incorporating this acquisition into its engineering design study for the expansion of its majority owned Leafland gas plant in the area while also investigating other midstream alternatives.
2022 ESG REPORT
Paramount has published its 2022 ESG report as part of its ongoing commitment to sustainable resource development, environmental stewardship and the well being of its employees and the communities in which we operate. The 2022 ESG report can be viewed on Paramount's website at https://www.paramountres.com/corporate-responsibility/esg-report/.
_______________________ |
|
(1) |
See also "Oil and Gas Measures and Definitions" in the Advisories section for additional information respecting internally estimated drilling locations. |
HEDGING
Paramount has hedged approximately 28% of its remaining 2022 forecast production to provide greater free cash flow certainty. The Company's current hedging position is summarized below:
Type (1) |
Q3 2022 |
Q4 2022 |
Q1 2023 |
Average Price (2) |
||
Oil |
||||||
WTI Swaps (Sale) (Bbl/d) |
Financial |
3,500 |
3,500 |
– |
US$75.79/Bbl |
|
WTI Swaps (Sale) (Bbl/d) |
Financial |
3,500 |
3,500 |
– |
CAD$91.38/Bbl |
|
WTI Collars (Bbl/d) |
Financial |
7,000 |
7,000 |
– |
CAD$82.50/Bbl (Floor) |
|
CAD$100.47/Bbl (Ceiling) |
||||||
Natural Gas |
||||||
NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
30,000 |
– |
– |
US$4.67/MMBtu |
|
NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
– |
3,370 |
– |
US$4.91/MMBtu |
|
AECO Fixed Price (GJ/d) |
Physical |
80,000 |
26,957 |
– |
CAD$3.78/GJ |
|
Dawn Fixed Price (MMBtu/d) |
Physical |
20,000 |
6,739 |
– |
US$4.03/MMBtu |
|
NYMEX Collars (MMBtu/d) |
Financial |
– |
13,261 |
20,000 |
US$7.50/MMBtu (Floor) |
|
US$12.13/MMBtu (Ceiling) |
||||||
AECO Collars (GJ/d) |
Financial |
– |
13,261 |
20,000 |
CAD$7.25/GJ (Floor) |
|
CAD$9.60/GJ (Ceiling) |
||||||
Foreign Currency Exchange |
||||||
CAD/USD Forwards (US$MM/Month) |
Forwards |
$20 |
$20 |
$10 |
1.2810 CAD$ / US$ |
|
CAD/USD Collars (US$MM/Month) |
Financial |
$5 |
$3.3 |
– |
1.25 CAD$ / US$ (Floor) |
|
1.30 CAD$ / US$ (Ceiling) |
||||||
CAD/USD Swaps (US$MM/Month) |
Financial |
$10 |
$10 |
$10 |
1.2888 CAD$ / US$ |
(1) |
Financial, refers to financial commodity and foreign currency exchange contracts. Physical, refers to fixed-priced physical contracts. Forwards, refers to foreign currency exchange forwards contracts. |
(2) |
Average price is calculated using a weighted average of notional volumes and prices. |
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, 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 2022 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements, can be obtained on SEDAR at www.sedar.com or on Paramount's website at https://www.paramountres.com/investors/financial-shareholder-reports.
A summary of historical financial and operating results is also available on Paramount's website at https://www.paramountres.com/investors/financial-shareholder-reports.
FINANCIAL AND OPERATING RESULTS(1)
($ millions, except as noted) |
Q2 2022 |
Q1 2022 |
Q2 2021 |
|||||
Net income (loss) |
182.2 |
16.6 |
(74.3) |
|||||
per share – basic ($/share) |
1.29 |
0.12 |
(0.56) |
|||||
per share – diluted ($/share) |
1.24 |
0.11 |
(0.56) |
|||||
Cash from operating activities |
318.9 |
174.9 |
112.1 |
|||||
per share – basic ($/share) |
2.26 |
1.25 |
0.84 |
|||||
per share – diluted ($/share) |
2.16 |
1.20 |
0.84 |
|||||
Adjusted funds flow |
258.3 |
237.8 |
86.0 |
|||||
per share – basic ($/share) |
1.83 |
1.70 |
0.65 |
|||||
per share – diluted ($/share) |
1.75 |
1.63 |
0.65 |
|||||
Free cash flow |
68.3 |
103.4 |
(2.4) |
|||||
per share – basic ($/share) |
0.48 |
0.74 |
(0.02) |
|||||
per share – diluted ($/share) |
0.46 |
0.71 |
(0.02) |
|||||
Total assets |
4,076.2 |
4,095.5 |
3,655.6 |
|||||
Investments in securities |
468.8 |
479.2 |
228.2 |
|||||
Long-term debt |
227.7 |
302.6 |
608.4 |
|||||
Net debt |
374.0 |
361.2 |
724.5 |
|||||
Common shares outstanding (millions) (2) |
141.2 |
140.0 |
133.3 |
|||||
Sales volumes (3) |
||||||||
Natural gas (MMcf/d) |
267.2 |
272.9 |
273.1 |
|||||
Condensate and oil (Bbl/d) |
27,750 |
31,375 |
29,543 |
|||||
Other NGLs (Bbl/d) |
5,021 |
5,276 |
4,938 |
|||||
Total (Boe/d) |
77,312 |
82,137 |
79,995 |
|||||
% liquids |
42 % |
45 % |
43 % |
|||||
Grande Prairie Region (Boe/d) |
48,736 |
54,737 |
49,345 |
|||||
Kaybob Region (Boe/d) |
21,642 |
20,726 |
22,688 |
|||||
Central Alberta & Other Region (Boe/d) |
6,934 |
6,674 |
7,962 |
|||||
Total (Boe/d) |
77,312 |
82,137 |
79,995 |
|||||
Netback |
$/Boe (4) |
$/Boe (4) |
$/Boe (4) |
|||||
Natural gas revenue |
164.0 |
6.75 |
127.1 |
5.18 |
74.8 |
3.01 |
||
Condensate and oil revenue |
340.0 |
134.65 |
331.9 |
117.53 |
209.6 |
77.96 |
||
Other NGLs revenue |
28.7 |
62.80 |
29.3 |
61.64 |
14.4 |
32.11 |
||
Royalty and other revenue |
3.5 |
─ |
11.3 |
─ |
1.0 |
─ |
||
Petroleum and natural gas sales |
536.2 |
76.22 |
499.6 |
67.59 |
299.8 |
41.18 |
||
Royalties |
(85.2) |
(12.11) |
(76.2) |
(10.31) |
(24.9) |
(3.43) |
||
Operating expense |
(88.7) |
(12.61) |
(89.2) |
(12.07) |
(81.8) |
(11.23) |
||
Transportation and NGLs processing |
(30.8) |
(4.37) |
(31.3) |
(4.24) |
(30.3) |
(4.16) |
||
Sales of commodities purchased (5) |
42.7 |
6.06 |
48.8 |
6.59 |
13.5 |
1.85 |
||
Commodities purchased (5) |
(41.1) |
(5.84) |
(49.1) |
(6.64) |
(13.6) |
(1.86) |
||
Netback |
333.1 |
47.35 |
302.6 |
40.92 |
162.7 |
22.35 |
||
Risk management contract settlements |
(61.9) |
(8.79) |
(49.7) |
(6.72) |
(54.1) |
(7.44) |
||
Netback including risk management contract settlements |
271.2 |
38.56 |
252.9 |
34.20 |
108.6 |
14.91 |
||
Capital expenditures |
||||||||
Grande Prairie Region |
107.2 |
76.8 |
66.5 |
|||||
Kaybob Region |
57.9 |
31.1 |
3.9 |
|||||
Central Alberta & Other Region |
0.8 |
0.1 |
11.8 |
|||||
Fox Drilling and Cavalier Energy |
3.7 |
1.1 |
1.1 |
|||||
Corporate |
14.5 |
7.9 |
0.1 |
|||||
Total |
184.1 |
117.0 |
83.4 |
|||||
Asset retirement obligations settled |
4.0 |
14.8 |
3.2 |
|||||
(1) |
Adjusted funds flow, free cash flow and net 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 the "Specified Financial Measures" section for more information on these measures. Prior period free cash flow has been reclassified to conform with the current year's presentation. |
(2) |
Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q2 2022: 0.8 million; Q1 2022: 1.5 million; Q2 2021: 1.5 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) |
Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties. |
PRODUCT TYPE INFORMATION
This press release refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". "Liquids" means NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane. Below is a complete breakdown of sales volumes for applicable periods by 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 |
|||||||
Q2 2022 |
Q1 2022 |
Q2 2021 |
Q2 2022 |
Q1 2022 |
Q2 2021 |
Q2 2022 |
Q1 2022 |
Q2 2021 |
|
Shale gas (MMcf/d) |
203.7 |
213.1 |
205.8 |
138.8 |
151.4 |
132.2 |
37.9 |
35.7 |
39.3 |
Conventional natural gas (MMcf/d) |
63.5 |
59.8 |
67.3 |
1.0 |
1.1 |
2.1 |
56.7 |
53.6 |
58.0 |
Natural gas (MMcf/d) |
267.2 |
272.9 |
273.1 |
139.8 |
152.5 |
134.3 |
94.6 |
89.3 |
97.3 |
Condensate (Bbl/d) |
25,374 |
29,064 |
26,784 |
22,511 |
26,042 |
24,086 |
2,092 |
2,130 |
2,319 |
Other NGLs (Bbl/d) |
5,021 |
5,276 |
4,938 |
2,914 |
3,267 |
2,874 |
1,585 |
1,558 |
1,569 |
NGLs (Bbl/d) |
30,395 |
34,340 |
31,722 |
25,425 |
29,309 |
26,960 |
3,677 |
3,688 |
3,888 |
Tight oil (Bbl/d) |
402 |
437 |
494 |
- |
- |
- |
253 |
322 |
354 |
Light and medium crude oil (Bbl/d) |
1,974 |
1,874 |
2,265 |
5 |
6 |
4 |
1,946 |
1,832 |
2,224 |
Crude oil (Bbl/d) |
2,376 |
2,311 |
2,759 |
5 |
6 |
4 |
2,199 |
2,154 |
2,578 |
Total (Boe/d) |
77,312 |
82,137 |
79,995 |
48,736 |
54,737 |
49,345 |
21,642 |
20,726 |
22,688 |
Central and Other Region |
Karr |
Wapiti |
|||||||
Q2 2022 |
Q1 2022 |
Q2 2021 |
Q2 2022 |
Q1 2022 |
Q2 2021 |
Q2 2022 |
Q1 2022 |
Q2 2021 |
|
Shale gas (MMcf/d) |
27.0 |
26.0 |
34.3 |
94.2 |
112.8 |
106.3 |
44.6 |
38.6 |
25.9 |
Conventional natural gas (MMcf/d) |
5.8 |
5.1 |
7.2 |
0.4 |
0.5 |
1.3 |
0.6 |
0.6 |
0.8 |
Natural gas (MMcf/d) |
32.8 |
31.1 |
41.5 |
94.6 |
113.3 |
107.6 |
45.2 |
39.2 |
26.7 |
Condensate (Bbl/d) |
771 |
892 |
379 |
13,551 |
17,246 |
18,458 |
8,960 |
8,796 |
5,628 |
Other NGLs (Bbl/d) |
522 |
451 |
495 |
1,978 |
2,475 |
2,281 |
936 |
792 |
593 |
NGLs (Bbl/d) |
1,293 |
1,343 |
874 |
15,529 |
19,721 |
20,739 |
9,896 |
9,588 |
6,221 |
Tight oil (Bbl/d) |
149 |
115 |
140 |
- |
- |
- |
- |
- |
- |
Light and medium crude oil (Bbl/d) |
23 |
36 |
37 |
- |
- |
- |
5 |
6 |
4 |
Crude oil (Bbl/d) |
172 |
151 |
177 |
- |
- |
- |
5 |
6 |
4 |
Total (Boe/d) |
6,934 |
6,674 |
7,962 |
31,295 |
38,611 |
38,679 |
17,441 |
16,126 |
10,666 |
July 2022 sales volumes of 92,000 Boe/d were comprised of 55% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 7% other NGLs.
Second half 2022 sales volumes are expected to average between 102,000 Boe/d and 106,000 Boe/d (54% shale gas and conventional natural gas combined, 40% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).
2022 annual sales volumes are expected to average between 91,000 Boe/d and 93,000 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).
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. 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, 2022 and 2021.
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 (netback and netback including risk management contract settlements, respectively) 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 for the applicable period by the total production 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 for the applicable period by the total production 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 production basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net 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 – Capital Structure in the unaudited Interim Condensed Consolidated Financial Statements of Paramount as at and for the three and six months ended June 30, 2022 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 months ended June 30, 2022 and 2021 and (iii) a calculation of net debt as at June 30, 2022 and March 31, 2022.
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 $/Bbl, $/Mcf or $/Boe 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 expense, sales of commodities purchased and commodities purchased on a $/Bbl, $/Mcf or $/Boe basis are calculated by dividing the petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased or commodities purchased, as applicable, over the referenced period by the aggregate units (Bbl, Mcf or Boe) produced 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 2022 and certain periods therein;
- the expected closing of the Willesden Green acquisition and the expected timing thereof;
- the expected closing of the non-core asset disposition, the expected timing thereof and the expected impact of the disposition on annual operating expenses;
- planned capital expenditures in 2022;
- planned abandonment and reclamation expenditures and activities in 2022;
- the expectation that production volumes at Wapiti will reach the targeted plateau of 30,000 Boe/d by the end of 2022;
- forecast free cash flow 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 expectation that the Company will achieve its net debt target of about $300 million in the fall and potential net debt to adjusted funds flow at year-end;
- planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production;
- internally estimated drilling locations and potential plateau production volumes at Willesden Green and the time period over which plateau production volumes may be maintained; and
- the payment of future dividends under the Company's monthly dividend program.
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 the COVID-19 pandemic on the Company;
- the impact of the Russian invasion of the Ukraine on the Company;
- the ability to realize expected cost savings;
- 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 satisfaction of all closing conditions to the Willesden Green acquisition and the closing of the acquisition as anticipated;
- the satisfaction of all closing conditions to the non-core asset disposition and the closing of the disposition as anticipated;
- 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, materials, services and personnel in a timely manner and at an acceptable cost to carry out its activities;
- the ability of Paramount to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
- the ability of Paramount to market its natural gas and liquids successfully to current and new customers;
- the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
- the timely receipt of required governmental and regulatory approvals;
- the receipt of benefits under government programs;
- the application of regulatory requirements respecting abandonment and reclamation; and
- anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance).
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;
- 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, interest rates and the rate of inflation;
- the possibility of the Willesden Green acquisition not being completed on the terms anticipated or at all, including due to a closing condition not being satisfied;
- the possibility of the non-core asset disposition not being completed on the terms anticipated or at all, including due to a closing condition not being satisfied;
- the uncertainty of estimates and projections relating to production, future revenue, free cash flow, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms;
- operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
- the ability to obtain equipment, materials, services and personnel in a timely manner and at an acceptable cost, 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);
- 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 obtain and maintain leases and licenses;
- 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, 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, 2021, 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 2022 and future periods, 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 |
||||||
Bbl |
Barrels |
GJ |
Gigajoules |
||||
Bbl/d |
Barrels per day |
GJ/d |
Gigajoules per day |
||||
MBbl |
Thousands of barrels |
MMBtu |
Millions of British Thermal Units |
||||
NGLs |
Natural gas liquids |
MMBtu/d |
Millions of British Thermal Units per day |
||||
Condensate |
Pentane and heavier hydrocarbons |
Mcf |
Thousands of cubic feet |
||||
MMcf |
Millions of cubic feet |
||||||
Oil Equivalent |
MMcf/d |
Millions of cubic feet per day |
|||||
Boe |
Barrels of oil equivalent |
AECO |
AECO-C reference price |
||||
MBoe |
Thousands of barrels of oil equivalent |
WTI |
West Texas Intermediate |
||||
MMBoe |
Millions of barrels of oil equivalent |
||||||
Boe/d |
Barrels of oil equivalent per day |
||||||
This press release contains disclosures expressed as "Boe", "$/Boe", "MBoe", "MMBoe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the six months ended June 30, 2022, the value ratio between crude oil and natural gas was approximately 25:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.
This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.
This press release contains information respecting Paramount's internal estimate of Duvernay drilling locations at Willesden Green. The referenced drilling locations represent future potential undeveloped gross locations as estimated effective December 31, 2021 by internal qualified reserves evaluators from Paramount. The referenced drilling locations were determined by Paramount's internal evaluators based on, among other matters, their assessment of available reservoir, geological and technical information, the economic thresholds necessary for development and potential future development plans. There is no certainty that the Company will drill any of the identified future potential undeveloped locations and there is no certainty that such locations will result in any reserves or production. The locations on which the Company will actually drill wells, including the number and timing thereof, will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil, NGLs and natural gas prices, costs, actual drilling results, additional reservoir, geological and technical information that is obtained and other factors. While certain of the estimated undeveloped locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of the locations are further away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty as to whether wells will be drilled in such locations, and if wells are drilled in such locations there is more uncertainty that such wells will result in any reserves or production. There is no guarantee that any internally estimated future potential development locations will be included and assigned reserves in any future reserves report prepared for the Company.
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, 2021 which is available on SEDAR at www.sedar.com.
SOURCE Paramount Resources Ltd.
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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