Paramount Resources Ltd. Announces First Quarter 2023 Results

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May 03, 2023, 07:00 ET

CALGARY, AB, May 3, 2023 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce first quarter 2023 financial and operating results highlighted by record production in the Grande Prairie Region, an active capital program that will drive second half 2023 production growth and continued strong free cash flow generation.

HIGHLIGHTS

First quarter sales volumes averaged 97,269 Boe/d (45% liquids), similar to the fourth quarter of 2022 even with the impact of 4,700 Boe/d in property dispositions in January 2023. Grande Prairie Region sales volumes averaged a record 69,507 Boe/d (51% liquids). ⁽¹⁾
Cash from operating activities was $271 million ($1.91 per basic share) in the first quarter. Adjusted funds flow was $268 million ($1.89 per basic share). ⁽²⁾
Free cash flow was $60 million ($0.42 per basic share) in the first quarter. ⁽²⁾ In addition, Paramount closed the sale of its Kaybob Smoky and Kaybob South Duvernay properties and certain other minor interests in the Kaybob Region (the "Kaybob Disposition") for cash proceeds of $371 million in January 2023.
Capital expenditures in the quarter totaled $184 million. Activities were focused on development in the Grande Prairie Region where Paramount drilled six (6.0 net) Montney wells and completed 14 (14.0 net) Montney wells and in the Kaybob Region where it drilled four (3.4 net) wells, including the longest well by measured depth in the Company's history of approximately 7,800 meters at its Kaybob North Duvernay property. Abandonment and reclamation expenditures in the first quarter totaled $22 million.
The Company's infrastructure debottlenecking project in the Grande Prairie Region is now complete. This will facilitate production growth in the region to between 77,000 Boe/d and 82,000 Boe/d in the second half of 2023 as additional wells are brought onstream. Paramount began bringing new Montney wells from the ten well Karr 4-2 pad on production in mid-April.

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(1)	In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "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 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, 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.

Following the Kaybob Disposition, the Company repaid all remaining drawings under its $1.0 billion revolving credit facility and paid a special cash dividend of $1.00 per class A common share ("Common Share").
At March 31, 2023, Paramount held $82 million in cash and cash equivalents and its revolving credit facility remained undrawn.
The carrying value of the Company's investments in securities at March 31, 2023 was $498 million.

GUIDANCE

Paramount is reaffirming its 2023 and preliminary 2024 annual average sales volumes and capital expenditure guidance. Capital expenditures in 2023 and 2024 are expected to be evenly split between: (i) sustaining and maintenance capital; and (ii) growth capital. Paramount is revising its free cash flow expectations to reflect higher operating and transportation expenses due to inflationary cost pressures and to incorporate updated NGLs pricing following the execution of new propane contracts in April 2023. If inflationary cost pressures persist into 2024, Paramount expects capital expenditures to be on the higher end of the guided range in 2024.

Paramount remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices, inflationary cost pressures and other factors.

2023 Guidance
Annual average sales volumes (Boe/d)	100,000 to 105,000 (46% liquids)
First half average sales volumes (Boe/d)	96,000 to 101,000 (45% liquids)
Second half average sales volumes (Boe/d)	104,000 to 109,000 (47% liquids)
Capital expenditures	$700 to $750 million (~50% to growth)
Abandonment and reclamation expenditures	$55 million
Free cash flow⁽¹⁾	$335 million ($375 million prior guidance)

The Company's midpoint 2023 sustaining and maintenance capital program and regular monthly dividend would remain fully funded down to an average WTI price of about US$50/Bbl over the last three quarters of 2023. ⁽²⁾ The Company's total midpoint 2023 capital program and regular monthly dividend would remain fully funded down to an average WTI price of about US$71/Bbl over the last three quarters of 2023.⁽²⁾

Preliminary 2024 Guidance⁽³⁾
Annual average sales volumes (Boe/d)	110,000 to 120,000 (48% liquids)
Capital expenditures	$700 to $800 million (~50% to growth)
Abandonment and reclamation expenditures	$40 million
Free cash flow⁽⁴⁾	$445 million ($465 million prior guidance)

Planning for the second phase of development at Willesden Green is ongoing, including the design of a new processing facility and the advancement of commercial arrangements for sales volumes egress. Paramount intends to update its five-year outlook later this year.

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(1)	Free cash flow is a capital management measure used by Paramount. Refer to "Advisories - Specified Financial Measures" for more information on this measure. The stated free cash flow forecast is based on the following assumptions for 2023: (i) the midpoint of stated capital expenditures and sales volumes, (ii) $55 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $55.50/Boe (US$79.04/Bbl WTI, US$3.48/MMBtu NYMEX, $3.33/GJ AECO), (v) a $US/$CAD exchange rate of $0.751, (vi) royalties of $8.40/Boe, (vii) operating costs of $12.00/Boe and (vii) transportation and NGLs processing costs of $3.85/Boe. Assumed pricing of US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX and $3.08/GJ AECO and an assumed $US/$CAD exchange rate of $0.755 for the remaining three quarters of 2023 is unchanged from previous guidance provided on March 7, 2023 but the stated amounts have been adjusted to incorporate actual results for the first quarter of 2023.
(2)	Assuming no changes to the other forecast assumptions for 2023.
(3)	All 2024 guidance is based on preliminary planning and current market conditions and is subject to change.
(4)	The stated free cash flow estimate 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) $7 million in geological and geophysical expenses, (iv) realized pricing of $53.60/Boe (US$75.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO), (v) a $US/$CAD exchange rate of $0.755, (vi) royalties of $8.15/Boe, (vii) operating costs of $11.25/Boe and (vii) transportation and NGLs processing costs of $3.65/Boe.

MAY DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.125 per Common Share that will be payable on May 31, 2023 to shareholders of record on May 15, 2023. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Sales volumes and netbacks in the Grande Prairie Region are summarized below:

		Q1 2023			Q4 2022		% Change
Sales volumes
Natural gas (MMcf/d)		204.4			189.9		8
Condensate and oil (Bbl/d)		31,367			29,146		8
Other NGLs (Bbl/d)		4,074			3,631		12
Total (Boe/d)		69,507			64,434		8
*% liquids*		51 %			51 %
Netback ⁽¹⁾	($ millions)		($/Boe)	($ millions)		($/Boe)	Change in $ millions (%)
Natural gas revenue ⁽²⁾	79.4		4.31	125.4		7.18	(37)
Condensate and oil revenue	286.9		101.64	293.9		109.60	(2)
Other NGLs revenue	16.9		46.21	17.1		51.22	(1)
Petroleum and natural gas sales	383.2		61.26	436.4		73.62	(12)
Royalties	(56.7)		(9.07)	(66.4)		(11.21)	(15)
Operating expense	(70.3)		(11.24)	(69.9)		(11.80)	1
Transportation and NGLs processing	(28.7)		(4.58)	(22.1)		(3.70)	30
	227.5		36.37	278.0		46.91	(18)

(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.

First quarter 2023 sales volumes in the Grande Prairie Region averaged a record 69,507 Boe/d (51% liquids) compared to 64,434 Boe/d (51% liquids) in the fourth quarter of 2022. The Company brought a total of six (6.0 net) new Montney wells at Karr and Wapiti on production in the first quarter.

Development activities in the Grande Prairie Region in the first quarter included the drilling of six (6.0 net) Montney wells and the completion of 14 (14.0 net) Montney wells.

At Karr, all four (4.0 net) wells at the 1-2 North pad were brought on production in the first quarter. The pad included a well with one of the longest lateral lengths in corporate history and a total measured depth of 7,060 metres. All-in drilling, completion, equipping and tie-in ("DCET") costs for the pad averaged $10.5 million per well. Production results from these four wells are consistent with expectations, averaging gross peak 30-day production per well of 1,904 Boe/d (6.3 MMcf/d of shale gas and 846 Bbl/d of NGLs) with an average CGR of 133 Bbl/MMcf. ⁽¹⁾

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(1)

Production measured at the wellhead. Natural gas sales volumes were lower by approximately 10% and liquids sales volumes were lower by approximately 6% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section.

The Company completed all ten (10.0 net) wells on the Karr 4-2 pad during the quarter and began bringing the wells on production in mid-April. Paramount also commenced drilling at the five (5.0 net) well 7-33 South pad at Karr in the first quarter, with the wells expected to be on production in the third quarter.

At Wapiti, the remaining two wells on the eight (8.0 net) well 16-15 pad were brought onstream in the first quarter. Paramount began drilling the eight (8.0 net) well 8-15 pad in the first quarter, with the wells expected to come on production in the third quarter.

The Company's Grande Prairie Region infrastructure debottlenecking project is now complete. This will facilitate sales volumes growth in the region to between 77,000 Boe/d and 82,000 Boe/d in the second half of 2023 as additional wells are brought onstream.

As previously disclosed, a planned 11 day outage in the second quarter and a planned four day outage in the fourth quarter at the third-party Wapiti natural gas processing plant will impact Grande Prairie Region sales volumes.

KAYBOB REGION

Kaybob Region sales volumes averaged 19,201 Boe/d (29% liquids) in the first quarter of 2023 compared to fourth quarter 2022 sales volumes of 24,477 Boe/d (34% liquids) (which included approximately 4,700 Boe/d from properties sold in the January 2023 Kaybob Disposition).

Development activities at the Company's Kaybob North Duvernay property are ongoing with Paramount recently completing the drilling of the three (3.0 net) well 4-13 pad that is expected to be brought onstream in the third quarter. The wells on this pad have the longest average well length by total measured depth in the Company's history and include the single longest well at approximately 7,800 meters of total measured depth. The Company is applying its learnings from the drilling of long reach wells, achieving another record by drilling 1,130 meters of lateral length in a 24-hour period on one of the wells.

The drilling of the five (5.0 net) well 15-7 pad at Kaybob North Duvernay commenced in the second quarter, with all five wells expected to be onstream in the fourth quarter. As a result of the optimization of existing infrastructure and improved surface facility design, the 4-13 and 15-7 pads are not expected to be subject to the production restrictions that impacted the three-well 12-21 pad brought on production in 2022.

Development activities in the Kaybob Region also included the drilling and completion of two (1.4 net) Montney gas wells. Paramount is deferring bringing these wells onstream until the winter when natural gas prices are expected to strengthen.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 8,561 Boe/d (32% liquids) in the first quarter of 2023 compared to 8,459 Boe/d (31% liquids) in the fourth quarter of 2022.

The Company plans to commence the drilling of four (4.0 net) Duvernay wells at Willesden Green late in the second quarter with first production anticipated in early 2024 to coincide with the start-up of the liquids handling expansion at the Leafland natural gas processing plant. Drilling operations at a second four (4.0 net) Duvernay well pad at Willesden Green will commence in late 2023.

Planning for the second phase of development at Willesden Green is ongoing, including the design of a new processing facility ("New Facility") and the advancement of commercial arrangements for sales volumes egress. It is currently anticipated that the New Facility will be capable of handling approximately 150 MMcf/d of raw gas and 30,000 Bbl/d of raw liquids upon completion. Additional gathering, compression and associated infrastructure will also be required. Paramount now expects that the New Facility will be constructed in three phases of approximately 50 MMcf/d of raw gas handling and 10,000 Bbl/d of raw liquids handling each, with the first train to start up in late 2025, approximately six months later than previously estimated.

Paramount controls approximately 240,000 net acres of contiguous land at Willesden Green with over 700 internally estimated Duvernay drilling locations, which supports targeted full field development plateau production of over 50,000 Boe/d that can be sustained for over 20 years. ⁽¹⁾

HEDGING

The Company's current commodity and foreign exchange contracts are summarized below:

	Q2 2023	Q3 2023	Q4 2023	2024	Average Price ⁽²⁾
Oil
Sweet Crude Oil – Basis (Physical Sale) (Bbl/d)	3,112	3,078	3,078	–	WTI – US$3.73/Bbl
Natural Gas
AECO – Basis (Physical Sale) (MMBtu/d)	35,000	35,000	11,793	–	NYMEX – US$0.94/MMBtu
Dawn – Basis (Physical Sale) (MMBtu/d)	25,000	25,000	8,424	–	NYMEX – US$0.20/MMBtu
Foreign Currency Exchange
Forward Sales / Swaps (US$MM/Month)	$60	–	–	–	1.3293 CAD$ / US$
Swaps (US$MM/Month)	–	$40	$40	–	1.3427 CAD$ / US$
Swaps (US$MM/Month)	–	–	–	$20	1.3425 CAD$ / US$

(2) Average price is calculated on a volume weighted average basis.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders on Wednesday, May 3, 2023 at 10:30 a.m. (Calgary time) in the McMurray Room of the Calgary Petroleum Club, located at 319 – 5^th Avenue S.W., Calgary Alberta. A webcast of the meeting will be available on the Company's website at www.paramountres.com/investors/presentations.

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(1)	See "Oil and Gas Measures and Definitions" in the Advisories section for additional information respecting internally estimated drilling locations.

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 first quarter 2023 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 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)

Q1 2023

Q4 2022

Q1 2022

Net income

197.0

259.9

16.6

per share – basic ($/share)

1.39

1.83

0.12

per share – diluted ($/share)

1.33

1.76

0.11

Cash from operating activities

271.4

306.9

174.9

per share – basic ($/share)

1.91

2.17

1.25

per share – diluted ($/share)

1.84

2.08

1.20

Adjusted funds flow

268.2

340.7

237.8

per share – basic ($/share)

1.89

2.40

1.70

per share – diluted ($/share)

1.81

2.31

1.63

Free cash flow

59.8

162.0

103.4

per share – basic ($/share)

0.42

1.14

0.74

per share – diluted ($/share)

0.40

1.10

0.71

Total assets

4,114.6

4,337.3

4,095.5

Investments in securities

498.3

557.1

479.2

Net (cash) debt

(43.6)

161.2

361.2

Long-term debt

–

159.4

302.6

Common shares outstanding (millions) ⁽²⁾

142.4

142.0

140.0

Sales volumes ⁽³⁾

Natural gas (MMcf/d)

320.6

321.9

272.9

Condensate and oil (Bbl/d)

37,916

37,580

31,375

Other NGLs (Bbl/d)

5,916

6,143

5,276

Total (Boe/d)

97,269

97,370

82,137

% liquids

45 %

45 %

45 %

Grande Prairie Region (Boe/d)

69,507

64,434

54,737

Kaybob Region (Boe/d)

19,201

24,477

20,726

Central Alberta & Other Region (Boe/d)

8,561

8,459

6,674

Total (Boe/d)

97,269

97,370

82,137

Netback

$/Boe ⁽⁴⁾

Natural gas revenue

122.0

4.23

194.2

6.56

127.1

5.18

Condensate and oil revenue

343.5

100.66

375.1

108.50

331.9

117.53

Other NGLs revenue

23.4

43.93

27.3

48.25

29.3

61.64

Royalty and other revenue

0.8

─

1.1

─

11.3

─

Petroleum and natural gas sales

489.7

55.94

597.7

66.72

499.6

67.59

Royalties

(69.1)

(7.90)

(84.4)

(9.43)

(76.2)

(10.31)

Operating expense

(108.8)

(12.43)

(119.2)

(13.31)

(89.2)

(12.07)

Transportation and NGLs processing

(36.3)

(4.15)

(27.2)

(3.03)

(31.3)

(4.24)

Sales of commodities purchased ⁽⁵⁾

115.1

13.15

102.7

11.47

48.8

6.59

Commodities purchased ⁽⁵⁾

(114.3)

(13.05)

(100.4)

(11.21)

(49.1)

(6.64)

Netback

276.3

31.56

369.2

41.21

302.6

40.92

Risk management contract settlements

6.1

0.70

(23.0)

(2.57)

(49.7)

(6.72)

Netback including risk management contract
settlements

282.4

32.26

364.2

38.64

252.9

34.20

Capital expenditures

Grande Prairie Region

121.1

135.8

76.8

Kaybob Region

39.0

11.4

31.1

Central Alberta & Other Region

5.6

1.0

0.1

Fox Drilling and Cavalier Energy

12.7

12.1

1.1

Corporate

5.7

9.3

7.9

Total

184.1

169.6

117.0

Asset retirement obligations settled

21.8

7.0

14.8

(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 the "Specified Financial Measures" section for more information on these measures.
(2)	Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q1 2023: 0.8 million, Q4 2022: 0.8 million, Q1 2022: 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 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
	Q1 2023	Q4 2022	Q1 2022
Shale gas (MMcf/d)	265.2	260.0	213.1
Conventional natural gas (MMcf/d)	55.4	61.9	59.8
Natural gas (MMcf/d)	320.6	321.9	272.9
Condensate (Bbl/d)	34,706	34,616	29,064
Other NGLs (Bbl/d)	5,916	6,143	5,276
NGLs (Bbl/d)	40,622	40,759	34,340
Light and medium crude oil (Bbl/d)	2,151	2,335	1,874
Tight oil (Bbl/d)	599	629	437
Heavy crude oil (Bbl/d)	460	-	-
Crude oil (Bbl/d)	3,210	2,964	2,311
Total (Boe/d)	97,269	97,370	82,137

	Grande Prairie Region			Kaybob Region			Central Alberta and Other Region
	Q1 2023	Q4 2022	Q1 2022	Q1 2023	Q4 2022	Q1 2022	Q1 2023	Q4 2022	Q1 2022
Shale gas (MMcf/d)	204.0	188.4	151.4	31.8	41.9	35.7	29.4	29.7	26.0
Conventional natural gas (MMcf/d)	0.4	1.5	1.1	49.6	55.0	53.6	5.4	5.4	5.1
Natural gas (MMcf/d)	204.4	189.9	152.5	81.4	96.9	89.3	34.8	35.1	31.1
Condensate (Bbl/d)	31,367	29,146	26,042	2,315	4,354	2,130	1,024	1,116	892
Other NGLs (Bbl/d)	4,074	3,631	3,267	988	1,671	1,558	854	841	451
NGLs (Bbl/d)	35,441	32,777	29,309	3,303	6,025	3,688	1,878	1,957	1,343
Light and medium crude oil (Bbl/d)	–	–	6	2,121	2,045	1,832	30	290	36
Tight oil (Bbl/d)	–	–	–	206	262	322	393	367	115
Heavy crude oil (Bbl/d)	–	–	–	–	–	–	460	–	–
Crude oil (Bbl/d)	–	–	6	2,327	2,307	2,154	883	657	151
Total (Boe/d)	69,507	64,434	54,737	19,201	24,477	20,726	8,561	8,459	6,674

The Company forecasts that 2023 annual sales volumes will average between 100,000 Boe/d and 105,000 Boe/d (54% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% other NGLs). First half 2023 sales volumes are expected to average between 96,000 Boe/d and 101,000 Boe/d (55% shale gas and conventional natural gas combined, 39% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% other NGLs). Second half 2023 sales volumes are expected to average between 104,000 Boe/d and 109,000 Boe/d (53% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% other NGLs). The Company's preliminary 2024 guidance provides for annual sales volumes that will average between 110,000 Boe/d and 120,000 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 not are 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 March 31, 2023, December 31, 2022 and March 31, 2022.

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 (a non-GAAP financial measure) 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 (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 – Capital Structure in the unaudited Interim Condensed Consolidated Financial Statements of Paramount as at and for the three months ended March 31, 2023 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 March 31, 2023 and 2022 and (iii) a calculation of net (cash) debt as at March 31, 2023 and December 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 $/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 expense, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf 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 (Boe or Mcf) 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:

expected growth in sales volumes in the Grande Prairie Region in the second half of 2023;
forecast sales volumes for 2023 and certain periods therein;
planned capital expenditures in 2023;
planned abandonment and reclamation expenditures in 2023;
forecast free cash flow in 2023;
preliminary 2024 sales volumes, capital expenditures, abandonment and reclamation expenditures and free cash flow guidance;
the expectation that capital expenditures in 2023 and 2024 will be evenly split between sustaining and maintenance capital and growth capital;
Paramount's expectation that capital expenditures in 2024 will be on the higher end of the guided range in the event inflationary cost pressures persist into 2024;
Paramount's intention to update its five-year outlook later this year;
planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production and the expected timing of completion and capacity of planned facilities;
the expectation that planned outages at the third-party Wapiti natural gas processing plant will impact Grande Prairie sales volumes;
the expectation that the 4-13 and 15-7 pads at Kaybob North Duvernay will not be subject to the production restrictions that impacted the 12-21 pad;
the anticipated capacity and timing of completion of the planned New Facility at Willesden Green;
the number of internally estimated drilling locations at Willesden Green and the plateau production that can be sustained by such locations; 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 Russian invasion of the Ukraine;
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 required capital to fund 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 expected and acceptable costs to carry out its activities;
the ability of Paramount to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
the ability of Paramount to market its production successfully;
the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
the timely receipt of required governmental and regulatory approvals, including approvals required for the construction of the New Facility at Willesden Green;
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 the New Facility at Willesden Green and 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 2024 sales volumes, capital expenditures, abandonment and reclamation expenditures and free cash flow guidance prior to finalization;
changes in foreign currency exchange rates, interest rates and the rate of inflation;
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 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 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);
processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
risks and uncertainties that may result in changes to the planned construction of the New Facility at Willesden Green, including the potential for changes to facility design or the timelines for construction prior to finalization or the failure to obtain required governmental and regulatory approvals;
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 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 by the Company 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, 2022, which is available on SEDAR at www.sedar.com 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 2023 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" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2023, the value ratio between crude oil and natural gas was approximately 24:1. 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 document 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, 2022 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, 2022 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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