Paramount Resources Ltd. Reports Second Quarter 2021 Results and Announces August Dividend

CALGARY, AB, Aug. 4, 2021 /CNW/ -

HIGHLIGHTS

Paramount Resources Ltd. Reports Second Quarter 2021 Results and Announces August Dividend (CNW Group/Paramount Resources Ltd.)

• Sales volumes averaged 79,995 Boe/d (43 percent liquids) in the second quarter of 2021, ahead of the Company's guidance of 77,000 Boe/d to 78,000 Boe/d (42 percent liquids), driven by continued outperformance at Karr.⁽¹⁾
  
  
  
• Sales volumes at Karr averaged 38,679 Boe/d (54 percent liquids) in the second quarter, ahead of expectations and approximately 5,500 Boe/d higher than first quarter production, despite a seven-day scheduled curtailment at the third-party 6-18 facility in May. The six-well 3-10 pad continues to outperform and achieved payout in four months after coming onstream in February.
  
  
• Sales volumes at Wapiti averaged 10,604 Boe/d (59 percent liquids) in the second quarter, in line with expectations. The Company expects Wapiti sales volumes to increase in the second half of 2021 as new production is brought onstream.
  
  
• Operating costs averaged $11.23/Boe in the second quarter of 2021, down from $11.63/Boe in the first quarter. Paramount achieved another important milestone at Karr, with second quarter operating costs coming in at $9.40/Boe, beating the Company's target of $10.00/Boe at plateau production of approximately 40,000 Boe/d.
  
  
• Cash from operating activities was $112.1 million in the second quarter. Adjusted funds flow was $86.0 million or $0.65 per share. Free cash flow was ($0.7) million. Full year 2021 free cash flow is now forecast to be $45 million higher at approximately $185 million resulting in anticipated year-end net debt to adjusted funds flow of approximately 1.0x, reflecting stronger commodity prices and year-to-date performance.⁽²⁾
  
  
• Second quarter capital spending, which was focused on drilling and completion activities at Karr, Wapiti and the Willesden Green Duvernay, totaled $83.5 million. Strong execution resulted in faster drilling and completion times on certain projects, translating into lower than budgeted costs and allowing the Company to complete certain activities in the second quarter that were initially planned for the third quarter. The Company remains on track for 2021 annual capital spending to be between $265 million and $285 million.
  
  
  
• Preliminary all-in lease construction, drilling, completion, equip and tie-in (collectively "DCET") costs at the five well Karr 7-18 pad that was brought on production in late July 2021 averaged a pacesetting $6.0 million per well, approximately 11 percent lower than average DCET costs of the last two pads at Karr.
  
  
• DCET costs for the seven well Wapiti 6-4 pad averaged a pacesetting $6.9 million per well, nine percent lower than average Wapiti DCET costs in 2020.
  
  
• Paramount's use of the drilling rigs and crews of its wholly-owned Fox Drilling subsidiary has resulted in consistency of execution and efficiencies that have contributed to well cost reductions at Karr and Wapiti.
  
  
• The Company finished drilling the two well 4-7 pad in the Willesden Green Duvernay during the second quarter. The wells were completed in July and are expected to be brought on production in late August. One of these wells was drilled to a lateral length of approximately 4,000 meters and a total measured depth of approximately 7,400 meters, representing the longest horizontal well ever drilled by the Company.
  
  
• Abandonment and reclamation expenditures in the second quarter totaled $3.2 million, net of $0.8 million in funding under the Alberta Site Rehabilitation Program.
  
  
• The Company's strong financial outlook and operating results enabled it to implement a monthly dividend of $0.02 per class A common share ("Common Share") and a normal course issuer bid ("NCIB") under which up to 7.3 million Common Shares may be purchased for cancellation. The inaugural cash dividend was paid on July 30, 2021.
  
  
• The Company's senior secured revolving bank credit facility (the "Paramount Facility") was amended in the second quarter to extend the maturity date to June 2, 2024 and change its size to $900 million, with an accordion feature providing flexibility to increase the size to $1.0 billion.
  
  
• In the second quarter, Paramount received $67 million cash in settlement of its previously disclosed dissent proceedings respecting Strath Resources Ltd. and for the sale of its remaining securities in Strathcona Resources Ltd.
  
  
• The Company closed the sale of its non-operated Birch assets in July for gross proceeds of approximately $88 million before customary closing adjustments.
  
  
• Subsequent to quarter-end, Paramount entered into several additional hedges to further protect its free cash flow profile. See below under "Hedging".

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^(1)	In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane combined.  See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section.
^(2)	"Adjusted funds flow", "free cash flow" and "net debt to adjusted funds flow" are Non-GAAP financial measures. See "Non-GAAP Financial Measures" in the Advisories section.

GUIDANCE

Paramount is reaffirming its 2021 average sales volumes guidance of between 80,000 Boe/d and 82,000 Boe/d (44 percent liquids). Second half 2021 sales volumes guidance remains unchanged at between 80,000 Boe/d and 84,000 Boe/d (45 percent liquids).

The Company continues to expect 2021 annual capital spending to be between $265 million and $285 million, excluding land acquisitions and abandonment and reclamation activities.

Paramount is updating its forecast of 2021 free cash flow from approximately $140 million to approximately $185 million to reflect year-to-date actual results and revised commodity price and other assumptions for the second half of 2021. This forecast is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $44.00/Boe (US$64.05/Bbl WTI, US$3.41/MMBtu NYMEX, $3.37/GJ AECO), (iv) royalties of $3.90/Boe, (v) operating costs of $11.20/Boe and (vi) transportation and processing costs of $4.00/Boe.

Approximately 53 percent of forecast midpoint production is hedged over the second half of 2021. After taking such hedging into account, 2021 forecast free cash flow would still be approximately $140 million at an average WTI oil price of US$50.00/Bbl over the second half of the year and would rise to $210 million at an average WTI oil price of US$75.00/Bbl over the second half of the year.

The Company currently prioritizes the allocation of free cash flow to: (i) achieving a targeted range of net debt to adjusted funds flow of between 1.0x and 2.0x; (ii) shareholder returns; and (iii) incremental growth. Free cash flow in 2021 is expected to be directed towards debt reduction and the payment of dividends, with the Company maintaining the flexibility to make purchases of Common Shares under the NCIB. Year-end net debt to adjusted funds flow is now anticipated to be approximately 1.0x based on forecast 2021 free cash flow and a monthly dividend of $0.02 per Common Share.

Paramount's previously announced preliminary 2022 capital spending and sales volumes guidance remains unchanged.  The Company continues to anticipate 2022 spending, excluding land acquisitions and abandonment and reclamation activities, to range between $325 million and $385 million.   A capital program in this range would be expected to result in 2022 annual sales volumes of between 84,000 Boe/d and 88,000 Boe/d (45 percent liquids) and free cash flow of approximately $320 million, based on the following updated assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $30 million in abandonment and reclamation costs, (iii) realized pricing of $43.20/Boe (US$62.18/Bbl WTI, US$3.30/MMBtu NYMEX, $3.10/GJ AECO), (iv) royalties of $4.15/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing costs of $3.85/Boe.  If all free cash flow was directed towards debt reduction, year-end 2022 net debt to adjusted funds flow would be less than 0.5x.

AUGUST DIVIDEND

The Board of Directors has declared a cash dividend of $0.02 per Common Share that will be payable on August 31, 2021 to shareholders of record on August 16, 2021. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Grande Prairie Region sales volumes and netbacks are summarized below:⁽¹⁾

	Q2 2021					Q1 2021				% Change
Sales volumes
Natural gas (MMcf/d)	134.3					122.6				10
Condensate and oil (Bbl/d)	24,090					23,974				-
Other NGLs (Bbl/d)	2,874					2,984				(4)
Total (Boe/d)	49,345					47,385				4
% liquids	55%					57%
Netback	($ millions)		($/Boe)			($ millions)	($/Boe)			% Change in $  millions
Petroleum and natural gas sales	217.7		48.47			194.0	45.50			12
Royalties	(15.3)		(3.40)			(11.6)	(2.72)			32
Operating expense	(48.8)		(10.88)			(49.0)	(11.49)			-
Transportation and NGLs processing	(21.4)		(4.76)			(20.0)	(4.69)			7
	132.2		29.43			113.4	26.60			17

^(1)	"Netback" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section.

KARR AREA

Karr sales volumes and netbacks are summarized below:

	Q2 2021		Q1 2021		% Change
Sales volumes
Natural gas (MMcf/d)	107.6		90.2		19
Condensate and oil (Bbl/d)	18,458		16,095		15
Other NGLs (Bbl/d)	2,281		2,108		8
Total (Boe/d)	38,679		33,230		16
% liquids	54%		55%
Netback	($ millions)	($/Boe)	($ millions)	($/Boe)	% Change in $  millions
Petroleum and natural gas sales	168.0	47.72	132.5	44.31	27
Royalties	(13.1)	(3.72)	(8.6)	(2.89)	52
Operating expense	(33.1)	(9.40)	(31.9)	(10.67)	4
Transportation and NGLs processing	(16.0)	(4.52)	(14.0)	(4.68)	14
	105.8	30.08	78.0	26.07	36

Second quarter sales volumes at Karr averaged 38,679 Boe/d (54 percent liquids) compared to 33,230 Boe/d (55 percent liquids) in the first quarter.  The increase in sales volumes was driven by strong performance from the six well 3-10 pad that was brought onstream in February and continues to outperform internal type well projections as well as production contributions from the three well 4-28 pad that was brought onstream in late April.  Sales volumes also benefitted from additional gas lift compression installed in the first quarter that became fully operational in April.  Combined, these more than offset the impact of scheduled curtailments at the third-party Karr 6-18 facility related to inlet separation and liquids handling optimization that reduced sales volumes by approximately 50 percent for seven days in May. 

The 4-28 pad has performed in line with internal type well projections, averaging gross peak 30-day production per well of 1,295 Boe/d (3.4 MMcf/d of shale gas and 728 Bbl/d of NGLs) with an average CGR of 214 Bbl/MMcf.⁽¹⁾  

Paramount continues to focus on driving DCET costs lower while maintaining well performance and has realized cost improvements relative to previous pacesetting results.  Preliminary all-in DCET costs at the five well Karr 7-18 pad, which was brought on production in late July 2021, averaged a pacesetting $6.0 million per well.  This represents an approximate 11 percent reduction relative to average DCET costs of the last two pads at Karr.  Continued outperformance from the 3-10 pad coupled with strong commodity prices has resulted in all wells on the 3-10 pad paying out in June, four months after coming onstream.

Drilling operations on the five well 5-16 East pad were completed in the second quarter.  The average spud to rig release time for this pad came in at just under 24 days, 12 percent faster than on the 5-16 West pad drilled last year from the same surface location.  The Company plans to complete the pad late in the third quarter and equip and tie-in the wells in the fourth quarter. The Company recently started drilling operations on the ten well 16-17 pad and expects that seven of the ten wells will be drilled by year-end.

Karr unit operating costs trended lower in the second quarter as a result of higher production volumes combined with a continued focus on capturing efficiencies and streamlining operations.  Paramount achieved operating costs at Karr of $9.40/Boe in the second quarter of 2021, lower than targeted operating costs of $10.00/Boe at plateau production of approximately 40,000 Boe/d.

Royalties at Karr increased in the second quarter of 2021 compared to the first quarter as a result of higher volumes and prices as well as a number of wells having fully utilized their new well royalty incentives.

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^(1)	Production measured at the wellhead. Natural gas sales volumes are lower by approximately 7% and liquids sales volumes are lower by approximately 6% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

WAPITI AREA

Wapiti sales volumes and netbacks are summarized below: 

	Q2 2021		Q1 2021		% Change
Sales volumes
Natural gas (MMcf/d)	26.4		32.1		(18)
Condensate and oil (Bbl/d)	5,629		7,884		(29)
Other NGLs (Bbl/d)	582		867		(33)
Total (Boe/d)	10,604		14,107		(25)
% liquids	59%		62%
Netback	($ millions)	($/Boe)	($ millions)	($/Boe)	% Change in $ millions
Petroleum and natural gas sales	49.6	51.41	61.4	48.42	(19)
Royalties	(2.1)	(2.24)	(2.9)	(2.32)	(30)
Operating expense	(15.4)	(16.00)	(16.8)	(13.25)	(8)
Transportation and NGLs processing	(5.5)	(5.65)	(6.0)	(4.73)	(9)
	26.6	27.52	35.7	28.12	(26)

Second quarter sales volumes at Wapiti averaged 10,604 Boe/d (59 percent liquids) compared to 14,107 Boe/d (62 percent liquids) in the first quarter due to natural declines, the temporary shut-in of certain offsetting wells due to completion activities at the 6-4 pad and production curtailments at the third-party Wapiti natural gas processing facility caused by high ambient temperatures in June. 

Production in July 2021 was impacted by the previously disclosed scheduled ten-day outage at the third-party Wapiti natural gas processing facility.  This outage, which was undertaken to permanently address the source of the unscheduled outage that occurred at the facility in the third quarter of 2020, was completed as planned and the Company has restored production.

The seven well 6-4 pad was brought onstream in early July with encouraging initial results.  DCET costs averaged a pacesetting $6.9 million per well, representing a nine percent reduction compared to average Wapiti DCET costs in 2020. 

The Company has commenced drilling the seven well 9-22 pad, which is scheduled to be brought onstream in December 2021 along with the previously drilled and completed 10-22 well.  The Company has also commenced the installation of infrastructure that will be operational later in 2021 and will accommodate production growth at Wapiti.

KAYBOB REGION

Kaybob Region sales volumes averaged 22,688 Boe/d (28 percent liquids) in the second quarter of 2021 compared to 24,938 Boe/d (28 percent liquids) in the first quarter.  The decrease in production was due to natural declines and non-core asset dispositions completed in the first quarter.

Paramount holds material positions in the Duvernay and Montney resource plays in the Kaybob Region that will compete for capital in the medium term.  In 2022, the Company has preliminary plans to drill, complete and tie-in a four well Duvernay pad at Kaybob Smoky and a three well Duvernay pad at Kaybob North on an existing pad where one of the three wells was previously drilled in 2019.  The Company expects to realize capital cost efficiencies in its Kaybob Duvernay plays, similar to the gains achieved over the past 18 months at Karr and Wapiti, as it commences pad development and captures economies of scale.  These lower costs are expected to materially improve Duvernay economics.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 7,962 Boe/d (13 percent liquids) in the second quarter of 2021 compared to 8,217 Boe/d (14 percent liquids) in the first quarter.

The Company holds a material, contiguous Duvernay position at Willesden Green and continues to actively evaluate longer-term full field development plans for this asset.  Drilling, completion and equipping of a two well, liquids rich Duvernay pad in the Willesden Green area was recently completed and Paramount plans to tie-in and bring both wells on production in late August.    

HEDGING

Subsequent to June 30, 2021, the Company entered into the following oil and natural gas hedges:

• Oil:
  
  October 2021 – March 2022         6,000 Bbl/d at $87.18/Bbl (WTI)
  
  
• Natural Gas:
  
  October 2021 – March 2022         20,000 MMBtu/d at US$4.10/MMBtu (NYMEX)
  
  October 2021 – March 2022         20,000 GJ/d at $4.01/GJ (AECO)

Further details of Paramount's commodity hedging position are provided in its second quarter 2021 Management's Discussion and Analysis and Consolidated Financial Statements. 

ABOUT PARAMOUNT

Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's class A common shares are listed on the Toronto Stock Exchange under the symbol "POU".

Paramount's second quarter 2021 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at: https://mma.prnewswire.com/media/1587964/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_Second.pdf

A summary of historical financial and operating results is also available on Paramount's website at http://www.paramountres.com/investor-relations/financial-reports#2021.

This information will also be made available through Paramount's website at www.paramountres.com and on SEDAR at www.sedar.com.

FINANCIAL AND OPERATING RESULTS ^(1) ($ millions, except as noted)
					Q2 2021		Q1 2021
Net loss					(74.3)		(82.5)
per share – basic and diluted ($/share)					(0.56)		(0.62)
Cash from operating activities					112.1		81.3
per share – basic and diluted ($/share)					0.84		0.61
Adjusted funds flow					86.0		90.9
per share – basic and diluted ($/share)					0.65		0.69
Total assets					3,655.6		3,583.1
Long-term debt					608.4		712.7
Net debt					724.5		761.7
Common shares outstanding (thousands) ^(2)					133,314		132,754
Sales volumes
Natural gas (MMcf/d)					273.1		273.1
Condensate and oil (Bbl/d)					29,543		29,854
Other NGLs (Bbl/d) ^(3)					4,938		5,170
Total (Boe/d)					79,995		80,540
% liquids					43%		43%
Grande Prairie Region (Boe/d)					49,345		47,385
Kaybob Region (Boe/d)					22,688		24,938
Central Alberta and Other Region (Boe/d)					7,962		8,217
Total (Boe/d)					79,995		80,540
Netback						$/Boe ^(4)		$/Boe ^(4)
Natural gas revenue					74.8	3.01	77.3	3.14
Condensate and oil revenue					209.6	77.96	185.9	69.20
Other NGLs revenue ^(3)					14.4	32.11	15.0	32.29
Royalty and other revenue					0.9	─	1.7	─
Petroleum and natural gas sales					299.7	41.17	279.9	38.61
Royalties					(24.9)	(3.43)	(18.6)	(2.57)
Operating expense					(81.8)	(11.23)	(84.3)	(11.63)
Transportation and NGLs processing ^(5)					(30.3)	(4.16)	(27.9)	(3.84)
Netback					162.7	22.35	149.1	20.57
Financial commodity contract settlements					(54.1)	(7.44)	(32.7)	(4.51)
Netback including financial commodity contract settlements					108.6	14.91	116.4	16.06
Total Capital Expenditures
Grande Prairie Region					66.5		51.3
Kaybob Region					3.9		5.0
Central Alberta and Other Region					11.8		1.2
Corporate ^(6)					1.2		1.8
Land acquisitions					0.1		─
Total capital expenditures					83.5		59.3
Asset retirement obligation settlements					3.2		8.4

^(1)	Readers are referred to the advisories concerning Non-GAAP Financial Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP financial measures:  Adjusted funds flow, Net debt, Netback and Total capital expenditures.  Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by the specific product types.
^(2)	Common shares are presented net of shares held in trust under the Company's restricted share unit plan (000's of common shares): Q2 2021: 1,538 and Q1 2021: 1,914.
^(3)	Other NGLs means ethane, propane and butane.
^(4)	Natural gas revenue presented as $/Mcf.
^(5)	Includes downstream transportation costs and NGLs fractionation costs.
^(6)	Includes transfers between regions.

PRODUCT TYPE INFORMATION

This press release refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". "Liquids" means NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane combined.  Below is a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil.  Numbers may not add due to rounding.

	Total		Grande Prairie Region		Kaybob Region		Central Alberta and Other Region
	Q2 2021	Q1 2021	Q2 2021	Q1 2021	Q2 2021	Q1 2021	Q2 2021	Q1 2021
Shale gas (MMcf/d)	205.8	197.8	132.2	120.6	39.3	42.1	34.3	35.1
Conventional natural gas (MMcf/d)	67.3	75.3	2.1	2.0	58.0	65.8	7.2	7.5
Natural gas (MMcf/d)	273.1	273.1	134.3	122.6	97.3	107.9	41.5	42.6
Condensate (Bbl/d)	26,784	27,017	24,086	23,974	2,319	2,611	379	433
Other NGLs (Bbl/d)	4,938	5,170	2,874	2,984	1,569	1,677	495	509
NGLs (Bbl/d)	31,722	32,187	26,960	26,958	3,888	4,288	874	942
Tight oil (Bbl/d)	494	479	–	–	354	342	140	136
Light and medium crude oil (Bbl/d)	2,265	2,358	4	–	2,224	2,321	37	37
Crude oil (Bbl/d)	2,759	2,837	4	–	2,578	2,663	177	173
Total (Boe/d)	79,995	80,540	49,345	47,385	22,688	24,938	7,962	8,217

	Karr		Wapiti
	Q2 2021	Q1 2021	Q2 2021	Q1 2021
Shale gas (MMcf/d)	106.3	89.1	25.9	31.5
Conventional natural gas (MMcf/d)	1.3	1.1	0.5	0.6
Natural gas (MMcf/d)	107.6	90.2	26.4	32.1
NGLs (Bbl/d)	20,739	18,203	6,211	8,751
Total (Boe/d)	38,679	33,230	10,604	14,107

The Company forecasts that 2021 sales volumes will average between 80,000 Boe/d and 82,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).  Second half 2021 sales volumes are expected to average between 80,000 Boe/d and 84,000 Boe/d (55% shale gas and conventional natural gas combined, 39% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). 

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:

• the expectation that sales volumes at Wapiti will increase in the second half of 2021;
• preliminary estimated drilling, completion and equipping costs;
• forecast free cash flow in 2021;
• forecast 2021 year-end net debt to annual adjusted funds flow;
• planned capital expenditures in 2021;
• forecast sales volumes for 2021 and certain periods therein;
• the Company's expectation that 2021 free cash flow will be directed towards debt reduction and the payment of dividends;
• preliminary anticipated capital expenditures in 2022 and the resulting expected 2022 average sales volumes, free cash flow and year-end net debt to adjusted funds flow;
• the payment of future dividends under the Company's monthly dividend program;
• planned exploration, development and production activities, including the expected timing of completing and bringing new wells on production; and
• the expectation that the Company will realize capital cost efficiencies in its Kaybob Duvernay plays and the expectation that lower costs will materially improve Duvernay economics.

Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:

• future commodity prices and the potential impact of the COVID-19 pandemic thereon;
• the likely impact of the COVID-19 pandemic on operations;
• the ability to realize expected cost savings;
• royalty rates, taxes and capital, operating, processing, transportation, general & administrative and other costs;
• foreign currency exchange rates and interest rates;
• general business, economic and market conditions;
• the ability of Paramount to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations;
• the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities;
• the ability of Paramount to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
• the ability of Paramount to market its production successfully to current and new customers;
• the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
• the timely receipt of required governmental and regulatory approvals;
• the receipt of benefits under government programs;
• the application of regulatory requirements respecting abandonment and reclamation; 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, including in relation to the impact of the COVID-19 pandemic;
• changes in capital spending plans and planned exploration and development activities;
• the potential for changes to preliminary anticipated 2022 capital expenditures prior to finalization and changes to the resulting expected 2022 average sales volumes and free cash flow;
• changes in foreign currency exchange rates and interest rates;
• the uncertainty of estimates and projections relating to future revenue, free cash flow, production, 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, services, supplies and personnel in a timely manner and at an acceptable cost;
• potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);
• processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
• risks and uncertainties involving the geology of oil and gas deposits;
• the uncertainty of reserves estimates;
• general business, economic and market conditions;
• the ability to generate sufficient cash from operating activities and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations);
• changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
• the ability to obtain required governmental or regulatory approvals in a timely manner, and to enter into and maintain leases and licenses;
• the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
• the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
• uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders;
• the outcome of existing and potential lawsuits, insurance claims, regulatory actions, audits and assessments; and
• other risks and uncertainties described elsewhere in this document and in Paramount's other filings with Canadian securities authorities.

There are risks that may result in the Company changing, suspending or discontinuing its monthly dividend program, including changes to free cash flow, operating results, capital requirements, financial position, market conditions or corporate strategy and the need to comply with requirements under debt agreements and applicable laws respecting the declaration and payment of dividends.  There are no assurances as to the continuing declaration and payment of future dividends under the Company's monthly dividend program or the amount or timing of any such dividends. 

The foregoing list of risks is not exhaustive. For more information relating to risks, see the sections titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2020, which is available on SEDAR at www.sedar.com.  The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Certain forward-looking information in this press release, including forecast free cash flow in 2021 and forecast 2021 year-end net debt to annual adjusted funds flow, may also constitute a "financial outlook" within the meaning of applicable securities laws.  A financial outlook involves statements about Paramount's prospective financial performance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any other specific assumptions and risk factors in relation to such financial outlook noted in this press release.  Such assumptions are based on management's assessment of the relevant information currently available and any financial outlook included in this press release is provided for the purpose of helping readers understand Paramount's current expectations and plans for the future.  Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially from any financial outlook.

Non-GAAP Financial Measures

In this press release, "adjusted funds flow", "free cash flow", "netback", "net debt", "net debt to adjusted funds flow" and "total capital expenditures", together the "Non-GAAP financial measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards.  Certain comparative figures have been reclassified to conform to the current years' presentation.

"Adjusted funds flow" refers to cash from (used in) operating activities before net changes in non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements, closure costs, provisions and other, dispute settlements and transaction and reorganization costs.  Adjusted funds flow is used to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations.  Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company.  Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary significantly from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as being an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS.  The following are the calculations of adjusted funds flow from the nearest GAAP measure for the three months ended June 30, 2021 and March 31, 2021:

Three months ended			Jun 30, 2021  (MM$)	Mar 31, 2021 (MM$)
Cash from operating activities			112.1	81.3
Change in non-cash working capital			(47.6)	(7.9)
Geological and geophysical expenses			1.8	1.6
Asset retirement obligations settled			3.2	8.4
Closure costs			–	–
Provisions and other			16.5	7.5
Dispute settlements			–	–
Transaction and reorganization costs			–	–
Adjusted funds flow			86.0	90.9

"Free cash flow" refers to adjusted funds flow less total capital expenditures and asset retirement obligation settlements.  Free cash flow is used by management and investors to assess the amount of internally generated cash available to repay debt, reinvest in the business or return to shareholders. The following is the calculation of free cash flow from the nearest GAAP measure for the three months ended June 30, 2021 and March 31, 2021:

Three months ended			Jun 30, 2021  (MM$)	Mar 31, 2021 (MM$)
Cash from operating activities			112.1	81.3
Change in non-cash working capital			(47.6)	(7.9)
Geological and geophysical expenses			1.8	1.6
Asset retirement obligations settled			3.2	8.4
Closure costs			–	–
Provisions and other			16.5	7.5
Dispute settlements			–	–
Transaction and reorganization costs			–	–
Adjusted funds flow			86.0	90.9
Total capital expenditures			(83.5)	(59.3)
Asset retirement obligation settlements			(3.2)	(8.4)
Free cash flow			(0.7)	23.2

"Netback" equals petroleum and natural gas sales less royalties, operating expense and transportation and NGLs processing costs.  Netback is commonly used by management and investors to compare the results of the Company's oil and gas operations between periods. Refer to the tables under the headings "Review of Operations" and "Financial and Operating Results" for the calculation thereof.

"Net debt" is a measure of the Company's overall debt position after adjusting for certain working capital and other amounts and is used by management to assess the Company's overall leverage position.  Refer to the Liquidity and Capital Resources section of the Company's Management's Discussion and Analysis for the three months and six months ended June 30, 2021 (the "MD&A") for the calculation of net debt.

"Net debt to adjusted funds flow" is a ratio calculated as the period end net debt divided by adjusted funds flow for the trailing four quarters. The ratio of net debt to adjusted funds flow is commonly used by management and investors to assess the Company's overall debt position and to measure the strength of the Company's balance sheet.

"Total capital expenditures" refers to the Company's property, plant and equipment and exploration expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures section of the MD&A for the calculation thereof.

Non-GAAP financial measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP financial measures are unlikely to be comparable to similar measures presented by other issuers.

Oil and Gas Measures and Definitions

Abbreviations

Liquids			Natural Gas
Bbl	Barrels		GJ	Gigajoules
Bbl/d	Barrels per day		GJ/d	Gigajoules per day
MBbl	Thousands of barrels		Mcf	Thousands of cubic feet
NGLs	Natural gas liquids		MMcf	Millions of cubic feet
Condensate	Pentane and heavier hydrocarbons		MMcf/d	Millions of cubic feet per day
WTI	West Texas Intermediate		AECO	AECO-C reference price
			NYMEX	New York Mercantile Exchange
			MMbtu	Millions of British thermal units
			MMbtu/d	Millions of British thermal units per day

Oil Equivalent
Boe	Barrels of oil equivalent
MBoe	Thousands of barrels of oil equivalent
MMBoe	Millions of barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day

This press release contains disclosures expressed as "Boe", "$/Boe" and "Boe/d".  Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe.  Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the six months ended June 30, 2021, the value ratio between crude oil and natural gas was approximately 26:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes.   This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended December 31, 2020 which is available on SEDAR at www.sedar.com.

SOURCE Paramount Resources Ltd.

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: [phone]

Related Links

http://www.paramountres.com