Management's Discussion and Analysis For the year ended December 31, 2020

This Management's Discussion and Analysis ("MD&A"), dated March 2, 2021 should be read in conjunction with the audited consolidated financial statements of Paramount Resources Ltd. ("Paramount" or the "Company") as at and for the year ended December 31, 2020 (the "Consolidated Financial Statements"). Financial data included in this MD&A has been prepared in accordance with International Financial Reporting Standards ("IFRS" or "GAAP") and is stated in millions of Canadian dollars, unless otherwise noted. The Company's accounting policies have been applied consistently to all periods presented.

The disclosures in this document include forward-looking information, non-GAAP financial measures and certain oil and gas measures. Readers are referred to the Advisories section of this document concerning such matters. Certain comparative figures have been reclassified to conform to the current years' presentation. Additional information concerning Paramount, including its Annual Information Form, can be found on the SEDAR website at www.sedar.com.

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. Paramount's principal properties are located in Alberta and British Columbia. Paramount commenced operations as a public company in 1978 and has adapted to a multitude of operating and economic climates over the years. The Company's Class A common shares ("Common Shares") are listed on the Toronto Stock Exchange under the symbol "POU".

Paramount's operations are organized into the following three regions:

the Grande Prairie Region, located in the Peace River Arch area of Alberta, which is focused on Montney developments at Karr and Wapiti;
the Kaybob Region, located in west-central Alberta, which includes the Kaybob North and Ante Creek Montney oil developments, Duvernay developments at Kaybob Smoky, Kaybob North and Kaybob South and other shale gas and conventional natural gas producing properties; and
the Central Alberta and Other Region, which includes the Willesden Green Duvernay development in central Alberta and shale gas producing properties in the Horn River Basin and at Birch in northeast British Columbia.

The Company's assets include: (i) strategic investments in exploration and pre-development stage assets, including prospective shale gas acreage in the Liard Basin, prospective natural gas and oil acreage in the Mackenzie Delta and at Central Mackenzie and interests held by the Company's wholly-owned subsidiary Cavalier Energy Inc. ("Cavalier") prospective for in-situ thermal oil recovery and heavy oil production; (ii) drilling rigs owned by the Company's wholly-owned limited partnership Fox Drilling Limited Partnership ("Fox Drilling"); and (iii) investments in other entities.

NOTE REGARDING PRODUCT TYPES

This MD&A includes references to sales volumes of "natural gas", "condensate and oil" and "Other NGLs" and revenues therefrom. "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. "Other NGLs" refers to ethane, propane and butane. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes and revenues for applicable periods by specific product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil.

FINANCIAL AND OPERATING HIGHLIGHTS (1)(2)

	2020	2019	2018
FINANCIAL
Petroleum and natural gas sales	626.0	914.9	965.5

Net income (loss)	(22.7)	(87.9)	(367.2)
Per share – basic & diluted ($/share)	(0.17)	(0.67)	(2.78)

Cash from operating activities	80.9	255.7	223.4
Per share – basic & diluted ($/share)	0.61	1.96	1.69
Adjusted funds flow	150.0	299.0	263.9
Per share – basic & diluted ($/share)	1.12	2.29	2.00

Total assets	3,497.0	3,531.3	4,118.1

Long-term debt	813.5	632.3	815.0

Net debt	854.1	703.5	896.0

Total liabilities	1,459.2	1,448.1	1,867.6

Common shares outstanding (thousands) (3)	132,284	133,337	130,326

OPERATIONALSales volumes
Natural gas (MMcf/d)	248.7	303.3	325.9
	22,565	25,079	24,238
Condensate and oil (Bbl/d)
Other NGLs (Bbl/d)	4,325	6,767	7,386
Total (Boe/d)	68,340	82,394	85,941
Realized prices
Natural gas ($/Mcf)	2.25	2.36	2.25
Condensate and oil ($/Bbl)	46.47	66.66	67.81
	15.63	15.24	30.67
Other NGLs ($/Bbl)
Petroleum and natural gas sales ($/Boe)	25.03	30.42	30.78
Total capital expenditures	220.8	404.1	580.2

(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 and to the reconciliations of such Non-GAAP financial measures to their most directly comparable measure under GAAP in the applicable sections of this document. This table contains the following Non-GAAP financial measures: Adjusted funds flow, Net debt and Total capital expenditures.

(2) "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. "Other NGLs" refers to ethane, propane and butane. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes and revenues for all applicable periods by specific product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil.

(3) Common Shares are presented net of shares held in trust under the Company's restricted share unit plan (000's of Common Shares): 2020: 1,914; 2019: 860; 2018: 574.

2020 OVERVIEW

Paramount's financial and operating results for 2020 reflect both the significant impact of the COVID-19 pandemic and the Company's successful response.

On March 4, 2020, Paramount announced initial capital expenditure guidance for 2020 of between $350 million and $450 million and resulting forecast average annual sales volumes of between 75,000 and 80,000 Boe/d. Shortly thereafter, a decline in oil and condensate prices that had begun in late-February due to disputes among members of OPEC+ and growing concerns respecting the potential impact of the COVID-19 pandemic rapidly accelerated. Paramount responded swiftly by announcing on March 19, 2020 a reduction of capital expenditure guidance to a range of between $185 and $250 million and a resulting reduction of forecast average annual sales volumes to a range of between 70,000 and 75,000 Boe/d. Paramount also implemented significant cost reduction initiatives aimed at lowering general and administrative expenses and operating costs, including securing reduced contractor and supplier rates. These initiatives included workforce reductions, a 20 percent reduction in the salary of the President and Chief Executive Officer and in the cash compensation of the Board of Directors, a 10 percent reduction in the salaries of all other staff and the suspension or elimination of a number of benefits and incentive compensation programs. As a further response, Paramount moved to temporarily shut-in certain production at various properties.

Despite the resolution of the OPEC+ disputes in the latter part of the second quarter of 2020, the erosion of global demand for crude oil and petroleum products in connection with the COVID-19 pandemic further negatively and materially impacted the oil and condensate prices received by the Company in the quarter. On May 13, 2020, Paramount revised its 2020 capital expenditure guidance to $165 million and withdrew its sales volume guidance. On June 29, 2020, Paramount's senior secured revolving bank credit facility was amended to provide for a period of financial covenant relief with a decrease in the size of the facility to $1.0 billion, as further described in this MD&A under "Liquidity and Capital Resources".

The third quarter of 2020 saw moderate stabilization and improvement in oil and condensate prices. To capitalize on the strengthening pricing environment and to position itself for a 2021 price recovery, Paramount announced on September 14, 2020 that it was accelerating $60 million of development activities at its Karr and Wapiti properties from 2021 to the second half of 2020. This resulted in 2020 capital expenditure guidance being revised to $225 million and the reinstatement of sales volume guidance for the second half of 2020 of a range between 62,500 and 67,500 Boe/d and for the fourth quarter of a range of between 67,000 and 72,000 Boe/d. By the end of the quarter, the Company had exceeded its 2020 cost reduction targets of $25 million in operating costs and $15 million in general and administrative expenses. In conjunction with the release of its third quarter results on November 5, 2020, the Company announced that it was maintaining its 2020 capital guidance of $225 million and revising fourth quarter forecast sales volumes to a range of between 70,000 and 72,000 Boe/d. The Company also announced that it had largely brought back on production wells that had been shut-in earlier in the year.

Oil and condensate prices continued to recover as the fourth quarter of 2020 progressed and the Company delivered strong operational results while maintaining capital discipline. The continued realization of significant capital costs savings enabled the completion of additional development activities at Karr and Wapiti not contemplated in the capital budget while keeping total 2020 capital expenditures under guidance at $220.8 million. Fourth quarter sales volumes exceeded the upper range of guidance of 72,000 Boe/d, averaging 73,460 Boe/d, as a result of higher than expected production at Karr from the five-well 2-1 pad and the five-well 5-16 West pad.

Throughout 2020, Paramount continued to realize significant cost savings in its capital program by a combination of advancements in well design, drill bit technology, fluid selection and reducing vendor rates. The provincial and federal governments also introduced a variety of measures to provide assistance to businesses. The Company realized $11.1 million of benefits under the Federal Government's Canada Emergency Wage Subsidy (the "CEWS") program in 2020 and received approvals for up to $14 million of funding under the Alberta Site Rehabilitation Program (the "ASRP"), of which $4 million was used in 2020, with the remainder available for use in 2021 and 2022. See "Operating Results", "Corporate" and "Property, Plant and Equipment and Exploration Expenditures" in this MD&A.

PARAMOUNT'S CONTINUING RESPONSE TO THE COVID-19 PANDEMIC

Pricing conditions for oil and condensate have strengthened in the first part of 2021 but remain subject to the impact of the evolving COVID-19 pandemic. Paramount has hedged approximately 57 percent of its forecasted 2021 production to reduce its exposure to price volatility. The Company has flexibility to adjust capital expenditure plans as conditions develop in 2021.

Paramount has implemented a corporate pandemic response plan aimed at ensuring the health and safety of its staff and contractors and the people they come in contact with. The Company is conducting its operations in compliance with public health requirements and guidelines, including by providing additional personal protective equipment and restricting access to its work sites to critical personnel. Paramount has implemented processes to permit its Calgary head office employees to work either remotely or in the office depending on personal circumstances and the public health measures in place from time to time.

Paramount continues to monitor the effect of the COVID-19 pandemic on its supply chain and the availability of third party services. To date, the Company has not experienced a material interruption in supplies or services related to the pandemic.

The course of the COVID-19 pandemic and its ultimate economic impact remain highly uncertain. Paramount will continue to proactively respond to the pandemic and the risks that it poses to the Company, including the risks described in this MD&A under "Risk Factors".

2021 GUIDANCE

Paramount's capital budget for 2021 is expected to range between $230 million and $260 million, excluding land acquisitions and abandonment and reclamation activities. Over 60 percent of the capital budget will be incurred in the first half of 2021. Approximately 85 percent of the 2021 program will be focused on advancing the Company's liquids-rich Montney developments at Karr and Wapiti. Approximately 70% of the 2021 capital budget is being allocated to sustaining capital and maintenance activities and the remaining 30% to production growth.

The Company forecasts that 2021 sales volumes will average between 77,000 Boe/d and 80,000 Boe/d (45 percent liquids). First half 2021 sales volumes are expected to average between 74,000 Boe/d and 76,000 Boe/d (43 percent liquids) as the majority of new wells will be brought on later in the year and volumes will be impacted by a scheduled outage at Karr in the second quarter. Despite a scheduled outage at Wapiti in the third quarter, second half 2021 sales volumes are expected to increase to average between 80,000 Boe/d and 84,000 Boe/d (46 percent liquids) as additional liquids-rich wells are brought onstream. (1)

The Company forecasts 2021 free cash flow of approximately $160 million based on: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $39.50/Boe (US$58.60/Bbl WTI, US$3.00/MMBtu NYMEX, $2.80/GJ AECO), (iv) operating costs of $11.65/Boe, and (v) transportation and processing costs of $4.00/Boe. With approximately 57 percent of forecast midpoint 2021 production hedged, forecast free cash flow would still be approximately $100 million at an average 2021 WTI oil price of US$43.50/Bbl. Below is forecasted free cash flow at alternate average 2021 WTI prices. (2)

(1) Liquids refers to NGLs (including condensate) and oil combined. Readers are referred to the Product Type Information section of this document for more information respecting the composition of forecast sales volumes.

(2) "Free cash flow" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section.

CONSOLIDATED RESULTS

Net Loss

Paramount recorded a net loss of $22.7 million for the year ended December 31, 2020 compared to a net loss of $87.9 million in the same period in 2019. Significant factors contributing to the change are shown below:

Year ended December 31
Netloss–2019	(87.9)
•Lower depletion, depreciation and net impairment reversals in 2020, mainly due to netimpairmentreversalsof $141.9 millionand lower depletion expensein 2020	252.7
•Lower income tax expense in 2020	102.1
•Gain on financial commodity contractsin 2020 compared to a loss in 2019	54.1
•Lower general and administrative expenses in 2020	19.7
•Closure program costs recognized in 2019	14.0
•Lower accretion expense on asset retirement obligations in 2020	13.3
•Lower netback in 2020, mainly due tolower commodity prices and sales volumes, partially offset bylower operating expense	(184.6)
•Loss on the sale of oil and gas assets in 2020 compared to a gain in 2019	(178.0)
•Lower recovery related to changes in asset retirement obligations in 2020	(16.0)
•Higher interest and financing expenses in 2020	(13.5)
•Other	1.4
Net loss –2020	(22.7)

Paramount recorded a net loss of $87.9 million for the year ended December 31, 2019 compared to a net loss of $367.2 million in the same period in 2018. Significant factors contributing to the change are shown below:

Year ended December 31
Net loss –2018	(367.2)
•Lowerdepletion, depreciation and impairment in 2019 mainly due to impairment charges of $502.5million in 2018	612.4
•Higher gain on the sale of oil and gas assets in 2019	111.9
•Income tax expense in 2019, which includeda reduction in Alberta income tax rates, compared to arecovery in 2018	(305.7)
•Loss on financial commodity contractsin 2019 compared to a gain in 2018	(52.2)
•Lower netback in 2019, mainly due to lower liquidsprices and lower natural gas sales volumes, partiallyoffset by higher natural gas prices	(41.4)
•Closure program costs recognized in2019	(14.0)
•Lower recovery related to changes in asset retirement obligations in 2019	(12.9)
•Other	(18.8)
Net loss –2019	(87.9)

Cash From Operating Activities

Cash from operating activities for the year ended December 31, 2020 was $80.9 million compared to $255.7 million for the same period in 2019. Significant factors contributing to the change are shown below:

Year ended December 31
Cash from operating activities –2019	255.7
•Lower netback in 2020, mainly due tolower commodity prices and sales volumes, partially offset bylower operating expense	(184.6)
•Change in non-cash working capital	(33.8)
•Higher interest and financing expenses in 2020	(12.3)
•Higher asset retirement obligation settlements in 2020	(5.6)
•Higher receipts on financial commodity contract settlements in2020	24.4
•Lower general and administrative expenses in 2020	19.7
•Closure program costs recognized in 2019	14.0
•Other	3.4
Cash from operating activities –2020	80.9

Cash from operating activities for the year ended December 31, 2019 was $255.7 million compared to $223.4 million for the same period in 2018. Significant factors contributing to the change are shown below:

Year ended December 31
Cash from operating activities –2018	223.4
•Receipts on financial commodity contract settlements in 2019 compared to payments in 2018	89.7
•Lower netback in 2019, mainly due to lower liquidsprices and lower natural gas sales volumes,partiallyoffset by higher natural gas prices	(41.4)
•Closure program costs recognized in2019	(14.0)
•Other	(2.0)
Cash from operating activities –2019	255.7

Adjusted Funds Flow (1)

The following is a reconciliation of adjusted funds flow to the nearest GAAP measure:

Year ended December 31	2020	2019	2018
Cash from operating activities	80.9	255.7	223.4
Change in non-cash working capital	17.9	(15.9)	(7.0)
Geological and geophysical expenses	8.5	11.0	12.5
Asset retirement obligations settled	35.0	29.4	29.4
Closure costs	–	14.0	–
Provision and other	4.7	2.5	–
Transaction and reorganization costs	3.0	2.3	5.6
Adjusted funds flow	150.0	299.0	263.9
Adjusted funds flow ($/Boe)	6.00	9.94	8.41

(1) "Adjusted funds flow" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section.

Adjusted funds flow for the year ended December 31, 2020 was $150.0 million compared to $299.0 million for the year ended 2019. Significant factors contributing to the change are shown below:

Year ended December 31
Adjusted funds flow –2019	299.0
•Lower netback in 2020, mainly due to lower commodity prices and lower sales volumes, partially offset	(184.6)
by lower operating expense•Higher interest and financing expenses in 2020	(12.3)
•Higher receipts on financial commodity contract settlements in 2020	24.4
•Lower general and administrative expenses in 2020	19.7
•Other	3.8
Adjusted funds flow–2020	150.0

Adjusted funds flow for the year ended December 31, 2019 was $299.0 million compared to $263.9 million for the same period in 2018. Significant factors contributing to the change are shown below:

Year ended December 31
Adjusted funds flow –2018	263.9
•Receipts on financial commodity contractsettlements in 2019 compared to payments in 2018	89.7
•Lower netback in 2019, mainly due to lower liquidsprices and lower natural gas sales volumes,partiallyoffset by higher natural gas prices	(41.4)
•Higher interest and financing expenses in 2019	(9.2)
•Other	(4.0)
Adjusted funds flow–2019	299.0

OPERATING RESULTS

Netback (1)

Year ended December 31		2020	2019
		($/Boe)(2)		($/Boe) (2)
Natural gas revenue	204.9	2.25	261.0	2.36
Condensate and oil revenue	383.8	46.47	610.2	66.66
Other NGLs revenue (3)	24.7	15.63	37.7	15.24
Royalty and otherrevenue	12.6	–	6.0	–
Petroleum and natural gas sales	626.0	25.03	914.9	30.42
Royalties	(31.3)	(1.25)	(63.3)	(2.10)
Operating expense	(297.1)	(11.88)	(376.0)	(12.50)
Transportation and NGLs processing (4)	(101.3)	(4.05)	(94.7)	(3.15)
Netback	196.3	7.85	380.9	12.67
Financial commodity contractsettlements	37.6	1.50	13.2	0.44
Netback including financial commodity contractsettlements	233.9	9.35	394.1	13.11

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

(2) Natural gas revenue shown per Mcf.

(3) Other NGLs means ethane, propane and butane.

(4) Includes downstream natural gas, NGLs and oil transportation costs and NGLs fractionation costs.

Petroleum and natural gas sales were $626.0 million in 2020, a decrease of $288.9 million from the prior year due to lower commodity prices and sales volumes.

	NaturalGas	Condensateand Oil	OtherNGLs	Royalty andOther	Total
Year ended December 31, 2019	261.0	610.2	37.7	6.0	914.9
Effect of changes in sales volumes	(46.4)	(59.7)	(13.5)	–	(119.6)
Effect of changes in prices	(9.7)	(166.7)	0.5	–	(175.9)
Change in royalty and otherrevenue	–	–	–	6.6	6.6
Year ended December 31, 2020	204.9	383.8	24.7	12.6	626.0

The impact of changes in sales volumes and prices on petroleum and natural gas sales are as follows:

Petroleum and natural gas sales were $914.9 million in 2019, a decrease of $50.6 million from 2018 mainly due to lower liquids prices and lower natural gas and other NGLs sales volumes, partially offset by higher natural gas prices.

The impact of changes in sales volumes and prices on petroleum and natural gas sales are as follows:

	Natural	Condensate	Other	Royalty and
	Gas	and oil	NGLs	Other	Total
Year ended December 31, 2018	267.1	599.9	82.7	15.8	965.5
Effect of changes in sales volumes	(18.5)	20.8	(6.9)	–	(4.6)
Effect of changes in prices	12.4	(10.5)	(38.1)	–	(36.2)
Change in royalty and otherrevenue	–	–	–	(9.8)	(9.8)
Year ended December 31, 2019	261.0	610.2	37.7	6.0	914.9

Sales Volumes (1)

	Yearended December 31
		Natural Gas		Condensate and Oil			Other NGLs			Total
		(MMcf/d)			(Bbl/d)(Bbl/d)			(Boe/d)
	2020		2019 % Change	2020	2019	% Change	2020		2019 % Change	2020		2019 % Change
Grande Prairie	78.6	79.5	(1)	16,005	13,973	15	1,964	1,814	8	31,076	29,040	7
Kaybob	125.9	146.2	(14)	5,895	8,650	(32)	1,812	2,476	(27)	28,685	35,500	(19)
Central Alberta& Other	44.2	77.6	(43)	665	2,456	(73)	549	2,477	(78)	8,579	17,854	(52)
Total	248.7	303.3	(18)	22,565	25,079	(10)	4,325	6,767	(36)	68,340	82,394	(17)

(1) Readers are referred to the Product Type Information section of this document for more information respecting the composition of sales volumes by specific product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil.

Sales volumes were 68,340 Boe/d for the year ended December 31, 2020, compared to 82,394 Boe/d in the same period in 2019. The decrease was primarily due to the sale of certain natural gas-weighted properties in West Central Alberta (the "West Central Alberta Assets") in late-2019 and natural declines in the Kaybob Region where the Company deployed limited capital in 2020 to focus on more profitable developments at Karr and Wapiti in the Grande Prairie Region. In December 2019, Paramount closed the sale of the West Central Alberta Assets for gross cash proceeds of approximately $52.4 million. The West Central Alberta Assets were included in the Central Alberta & Other Region and had average sales volumes of approximately 8,500 Boe/d (30.6 MMcf/d of conventional natural gas, 2,947 Bbl/d of NGLs and 466 Bbl/d of light and medium crude oil) and a netback of approximately $22.5 million in 2019 prior to the date of sale.

The decreases in sales volumes in 2020 in the lower netback Central Alberta & Other and Kaybob Regions were partially offset by higher sales volumes in the liquids rich Grand Prairie Region. Sales volumes at Wapiti increased from 6,082 Boe/d (10.8 MMcf/d of shale gas, 0.3 MMcf/d of conventional gas and 4,223 Bbl/d of NGLs) in 2019 to 10,207 Boe/d (21.5 MMcf/d of shale gas, 0.4 MMcf/d of conventional natural gas and 6,550 Bbl/d of NGLs) in 2020, primarily as a result of a full year of production following the start-up of the new third-party Wapiti natural gas processing plant in May 2019 (the "Wapiti Plant"). 2020 Wapiti sales volumes were impacted by about 2,200 Boe/d due to approximately 10 weeks of downtime at the Wapiti Plant. At Karr, sales volumes were 20,777 Boe/d (55.6 MMcf/d of shale gas, 0.7 MMcf/d of conventional natural gas and 11,389 Bbl/d of NGLs) in 2020 compared to 22,755 Boe/d (67.2 MMcf/d of shale gas, 0.5 MMcf/d of conventional natural gas and 11,477 Bbl/d of NGLs) in 2019, reflecting the impact of deferred capital activities in 2020 and the effects of gathering system constraints. Paramount completed a debottlenecking project in the third quarter to alleviate these gathering system constraints.

Commodity Prices

Year Ended December 31	2020	2019	% Change
Natural Gas
Paramount realized natural gas price ($/Mcf)	2.25	2.36	(5)
AECO daily spot ($/GJ)	2.11	1.67	26
AECO monthly index ($/GJ)	2.12	1.54	38
Dawn ($/MMbtu)	2.51	3.22	(22)
NYMEX (US$/MMbtu)	2.13	2.53	(16)
Malin –monthly index (US$/MMbtu)	2.15	2.67	(19)
Condensate and Oil
Paramount realized condensate & oil price ($/Bbl)	46.47	66.66	(30)
Edmonton light sweetcrude oil($/Bbl)	45.39	68.87	(34)
West Texas Intermediate crude oil (US$/Bbl)	39.40	57.02	(31)
Other NGLs (1)
Paramount realized Other NGLs price ($/Bbl)(1)	15.63	15.24	3
Conway –propane ($/Bbl)	24.83	26.43	(6)
Belvieu –butane ($/Bbl)	30.48	35.95	(15)
Foreign Exchange
$CDN / 1 $US	1.34	1.33	1

(1) Other NGLs means ethane, propane and butane.

Paramount's natural gas portfolio primarily consists of sales priced at Alberta, California, Chicago, Ventura and Eastern Canada markets, which are sold in a combination of daily, monthly and seasonal contracts. The Company's natural gas portfolio includes arrangements to sell approximately 60,000 GJ/d of natural gas at Dawn, approximately 22,000 GJ/d of natural gas at Malin and 40,000 GJ/d of natural gas sales priced in the US Midwest.

The Company had the following AECO fixed-price physical contracts to sell natural gas in place at December 31, 2020:

Quantity	Location	Average fixed price	Remaining term
40,000 GJ/d	AECO	CDN$2.68/GJ	January 2021 -March 2021
50,000 GJ/d	AECO	CDN$2.51/GJ	January 2021 -December 2021

Subsequent to December 31, 2020, the Company entered into the following AECO fixed-price physical contracts to sell natural gas:

Quantity	Location	Average fixed price	Remaining term
50,000 GJ/d	AECO	CDN$2.52/GJ	April 2021-October 2021

Paramount ships a portion of its condensate and crude oil production on third-party pipelines for sale in Edmonton, Alberta, where volumes sold generally receive higher prices due to the greater diversity of potential purchasers. A limited portion of the Company's production continues to be sold at truck terminals or at the lease when warranted by economic or operational factors. Sales prices for condensate and oil are based on West Texas Intermediate reference prices, adjusted for transportation, quality and density differentials.

The Company's butane and propane volumes are generally sold under contracts that are renewed annually in April each year. The contracts in place in 2020 had more favorable differentials to West Texas Intermediate reference prices than in 2019.

Financial Commodity Contracts

From time-to-time Paramount uses financial commodity contracts to manage exposure to commodity price volatility. Changes in the fair value of the Company's financial commodity contracts are as follows:

Year ended December 31	2020	2019
Fair value, beginning of year	6.1	64.4
Changes in fair value	8.8	(45.1)
Settlements received	(37.6)	(13.2)
Fair value, end of year	(22.7)	6.1

For further details on the Company's financial commodity contracts, refer to Note 14 of the Consolidated Financial Statements.

Subsequent to December 31, 2020, the Company entered into the following financial commodity contracts:

Instruments	Aggregatenotional	Averagefixed price	Remaining term
Oil –NYMEX WTI Swaps (Sale)	3,000 Bbl/d	CDN$65.29/Bbl	April 2021 –September 2021
Oil –NYMEX WTI Swaps (Sale)	4,573Bbl/d	US$58.52/Bbl	February2021 –June 2021
Oil –Edmonton Condensate WTI DifferentialSwap (Sale)	4,000 Bbl/d	WTI + US$0.06/Bbl	April 2021 –June 2021

The following table summarizes the Company's 2021 financial commodity contracts and fixed-price physical contracts:

	Type(1)	Q1 2021	Q2 2021	Q32021	Q42021	Average Price (2)
Oil –WTI Swaps (Sale)(Bbl/d)	Financial	24,589	23,000	15,000	10,000	US$46.35/Bbl
Oil –WTI Swap (Sale) (Bbl/d)	Financial	–	3,000	3,000	–	C$65.29/Bbl
Condensate –Basis Swap(Sale) (Bbl/d)	Financial	1,000	4,000	–	–	WTI + US$0.15/Bbl
Gas –NYMEX Swaps (Sale)(MMbtu/d)	Financial	90,000	60,000	60,000	60,000	US$2.73/MMbtu
Gas –AECO fixed price (GJ/d)	Physical	90,000	100,000	100,000	66,848	C$2.53/GJ

(1) Financial, refers to financial commodity contracts. Physical, refers to fixed-priced physical contracts.

(2) Average price is calculated using weighted average notional volumes and prices.

Royalties

Year ended December 31	2020	Rate	2019	Rate
Royalties	31.3	5.1%	63.3	7.0%
$/Boe	1.25		2.10

Royalties were $31.3 million for the year ended December 31, 2020, $32.0 million lower than the same period in 2019, primarily as a result of lower condensate and oil prices and decreased sales volumes.

Operating Expense

Year ended December 31	2020	2019	% Change
Operating expense	297.1	376.0	(21)
$/Boe	11.88	12.50	(5)

Operating expense was $297.1 million for the year ended December 31, 2020, $78.9 million lower than the same period in 2019.

Operating costs in 2020 were lower compared to the same period in 2019 primarily due to lower production in the Central and Other and Kaybob Regions and as a result of the Company's response to the decreased oil and condensate prices as described in this MD&A under "2020 Overview", which included decreased labour costs, supplier cost savings and lower maintenance costs. The Company also realized cost reductions from the closure of the Zama property, new water disposal wells and lower power costs.

The decreases in operating expenses in 2020 were partially offset by higher operating costs in the Grande Prairie Region as a result of incremental processing fees following the start-up of the Wapiti Plant in May 2019 and the sale of the Karr 6-18 natural gas facility in August 2019 (the ʺMidstream Transactionʺ).

Operating costs were $11.88 per Boe for the twelve months ended December 31, 2020 compared to $12.50 per Boe in the same period of 2019. The decrease in operating expense per Boe is mainly due to the changes described above.

Transportation and NGLs Processing

Year ended December 31	2020	2019	% Change
Transportation and NGLs processing	101.3	94.7	7
$/Boe	4.05	3.15	29

Transportation and NGLs processing expense was $101.3 million for the year ended December 31, 2020 compared to $94.7 million in the same period in 2019. Transportation and NGLs processing costs increased in 2020 mainly as a result of higher contracted capacity for Wapiti and Karr, partially offset by lower production in the Central and Other and Kaybob Regions.

Other Operating Items

Year ended December 31	2020	2019
Depletion and depreciation (excluding net impairmentreversals)	(253.9)	(364.8)
Net impairment reversalsof property plant and equipment	141.9	–
Gain (loss) on sale of oil and gas assets	(8.7)	169.3
Exploration and evaluation expense	(34.0)	(22.4)

Depletion and depreciation expense decreased to $253.9 million in 2020 compared to $364.8 million in 2019, mainly due to lower sales volumes and lower depletion rates following impairment charges of $191.8 million recorded in the first quarter of 2020.

At December 31, 2020, the Company recorded aggregate impairment reversals of $333.7 million from previously recorded impairment charges, comprised of $287.7 million, $30.6 million and $15.4 million related to petroleum and natural gas assets in the Kaybob, Northern and Central Alberta cash-generating units ("CGUs"), respectively. The impairment reversals resulted from an increase in the estimated recoverable amount of such CGUs compared to the prior impairment assessment performed at March 31, 2020.

The $333.7 million aggregate impairment reversals represent the amount to bring the carrying values of the Kaybob and Northern CGUs to their estimated recoverable amounts and the carrying value of the Central Alberta CGU to the amount, net of depletion and amortization, had no impairment charges been recognized in prior periods. The increase in the estimated recoverable amount of these CGUs was mainly due to lower operating and capital costs than previously forecasted and changes to the development plan.

The recoverable amount of the Kaybob, Northern and Central Alberta CGUs as at December 31, 2020 was estimated on a fair value less costs of disposal ("FVLCD") basis, using a discounted cash flow method (level 3 fair value hierarchy estimate). Cash flows were projected over the expected remaining productive life of the proved plus probable reserves assigned to the Kaybob, Northern and Central Alberta CGUs, at discount rates of 11.5 percent, 13.5 percent and 13.0 percent, respectively. Proved plus probable reserves estimates were prepared by Paramount's independent qualified reserves evaluator. The reserves evaluation process is inherently subjective and involves considerable estimation uncertainty.

The following table sets out the forecast benchmark commodity prices and exchange rates used to determine estimated recoverable amounts at December 31, 2020: (1)

(Average for the period)	2021	2022	2023	2024	2025	2026-2033	Thereafter
Natural Gas(2)
AECO ($/MMBtu)	2.78	2.70	2.61	2.65	2.70	2.76–3.16	+2%/yr
Henry Hub (US$/MMBtu)	2.83	2.87	2.90	2.96	3.02	3.08 –3.53	+2%/yr
Crude Oil and Condensate (2)
Edmonton Condensate($/Bbl)	59.24	63.19	67.34	69.77	71.18	72.61–83.44	+2%/yr
WTI (US$/Bbl)	47.17	50.17	53.17	54.97	56.07	57.19–65.70	+2%/yr
Foreign Exchange
$US /1 $CDN	0.77	0.77	0.76	0.76	0.76	0.76	0.76

(1) Average of forecasts published by: (i) McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. at January 1, 2021 and (ii) Sproule Associates Ltd. at December 31, 2020.

(2) Forecast benchmark prices are adjusted for quality differentials, heat content, distance to market and other factors in determining estimated recoverable amounts.

The following table summarizes the impact of a change to the discount rate or before tax undiscounted cash flow estimates on the net impairment reversals as at December 31, 2020:

	Discount Rate		Cash Flow Estimates
	One Percent	One Percent	FivePercent	Five Percent
	Increase	Decrease	Increase	Decrease
Net impairment reversals –increase (decrease)	(55,455)	62,102	38,432	(38,432)

At March 31, 2020, the Company recorded impairments of $188.3 million and $3.5 million related to petroleum and natural gas assets in the Kaybob and Northern CGUs, respectively. The impairments were recorded because the carrying value of the CGUs exceeded their estimated recoverable amount, which were estimated based on expected net cash flows from the production of proved plus probable reserves ascribed to each CGU. The impairments resulted from decreases in estimated future net revenues, mainly due to lower forecasted oil and natural gas prices.

Recoverable amounts were estimated on a FVLCD basis using a discounted cash flow method (level three fair value hierarchy estimate). Cash flows were determined based on internally estimated after-tax discounted future net cash flows from the production of proved plus probable reserves assigned to the Kaybob and Northern CGUs, at discount rates of 11.5 percent and 13.5 percent, respectively. The net cash flows from the proved plus probable reserves estimated by Paramount's independent qualified reserves evaluator as at December 31, 2019 were internally updated by Management to reflect commodity price estimates at March 31, 2020 and for changes to certain operating and capital assumptions to reflect the prevailing economic environment. The reserves evaluation process is inherently subjective and involves considerable estimation uncertainty.

The following table sets out the forecast benchmark commodity prices and exchange rates used to determine estimated recoverable amounts at March 31, 2020 (1):

	(Apr-Dec)
	2020	2021	2022	2023	2024	2025-2032	Thereafter
Natural Gas(2)
AECO ($/MMBtu)	1.74	2.20	2.38	2.45	2.53	2.60-3.04	+2%/yr
Henry Hub (US$/MMBtu)	2.10	2.58	2.79	2.86	2.93	3.00-3.45	+2%/yr
Crude Oil and Condensate(2)
Edmonton Condensate ($/Bbl)	34.35	50.72	62.80	68.49	71.73	73.16-84.23	+2%/yr
WTI (US$/Bbl)	29.17	40.45	49.17	53.28	55.66	56.87-65.33	+2%/yr
Foreign Exchange
$US / 1 $CDN	0.71	0.73	0.75	0.75	0.75	0.75	0.75

(1) Average of forecasts published by: (i) McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. at April 1, 2020 and (ii) Sproule Associates Ltd. at March 31, 2020.

(2) Forecast benchmark prices are adjusted for quality differentials, heat content, distance to market and other factors in determining estimated recoverable amounts.

In August 2019, Paramount closed the Midstream Transaction for gross cash proceeds of $331.6 million. The cash proceeds included the reimbursement of capital expenditures related to the expansion of the 6- 18 Facility. In connection with the sale, the Company entered into a midstream services agreement that includes a fee-for-service arrangement and a take-or-pay volume commitment that ends in 2040. A gain of $153.6 million was recognized on the sale.

Exploration and Evaluation ("E&E") expense was $34.0 million in 2020, an increase of $11.6 million compared to 2019, primarily due to higher expenses for expired mineral leases.

DISSENT PAYMENT ENTITLEMENT

As atDecember 31	2020	2019
Dissent Payment Entitlement	89.3	–

Paramount held 85 million common shares of Strath Resources Ltd. (ʺStrathʺ) prior to its amalgamation with Cona Resources Ltd. in August 2020 to form Strathcona Resources Ltd. (ʺStrathconaʺ). Paramount objected to the amalgamation and exercised its right of dissent under section 191 of the Business Corporations Act (Alberta) (the ʺABCAʺ) with respect to its Strath shares. As a result, the Company is entitled to be paid in cash the fair value of its Strath shares, determined as of the close of business on July 24, 2020 (the ʺDissent Payment Entitlementʺ).

The amount of the Dissent Payment Entitlement and the timing of the payment thereof are uncertain. Paramount has applied to the Court of Queen's Bench of Alberta (the ʺCourtʺ) seeking Strathcona's payment of the Dissent Payment Entitlement. Strathcona made a statutorily required offer with respect to the Dissent Payment Entitlement in the amount of $45 million (the ʺOffered Amountʺ). Paramount has rejected such offer and applied to the Court for an interim payment of the Offered Amount pending final determination of the amount of the Dissent Payment Entitlement. In the event the parties are unable to agree on the amount of the Dissent Payment Entitlement, the final amount, including any interest thereon, will be determined by the Court. Any payment of the Dissent Payment Entitlement will be subject to the satisfaction by Strathcona of the solvency tests provided in the ABCA.

The Dissent Payment Entitlement is a financial instrument measured at amortized cost and was recorded based on valuation techniques and assumptions that incorporate unobservable inputs (level three fair value hierarchy inputs), including market-based metrics of comparable companies and transactions and other indicators of value.

INVESTMENTS IN SECURITIES

As at December 31	2020	2019
Level one fair value hierarchy securities	48.4	88.4
Level three fair value hierarchy securities	11.1	68.5
	59.5	156.9

Paramount holds investments in a number of publicly-traded and private corporations as part of its portfolio of investments.

Investments that are categorized as level one fair value hierarchy securities (ʺLevel One Securitiesʺ) are carried at their period-end trading prices. Estimates of fair values for investments that are categorized as level three fair value hierarchy securities (ʺLevel Three Securitiesʺ) are based on valuation techniques that incorporate unobservable inputs. The valuation techniques utilize market-based metrics of comparable companies and transactions, indications of value based on equity transactions of the entities and other indicators of value including financial and operating results of the entities. Fair value estimates of Level Three Securities are updated at each balance sheet date to confirm whether the carrying value of the investment continues to fall within a range of possible fair values indicated by such techniques.

For the year ended December 31, 2020 the Company recorded a charge of $18.1 million to other comprehensive income (ʺOCIʺ) as a result of changes in the fair value estimates of investments in Level One Securities and investments in Level Three Securities.

For the twelve months ended December 31, 2020, the Company recorded a loss of $1.7 million to net loss related to a change in the estimated fair value of warrants. Accumulated losses of $83.9 million were reclassified from accumulated OCI to accumulated deficit, which included $69.9 million related to the Company's exercise of its Strath dissent rights.

In 2020, the Company acquired 17.3 million common shares of NuVista Energy Ltd. ("NuVista Shares") at a price of $0.61 per share for an aggregate purchase price of $10.6 million. At December 31, 2020, the Company owned a total of 39.8 million NuVista Shares, representing 17.6 percent of the outstanding NuVista Shares, which were included in Investments in Securities and classified as Level One Securities.

In 2019, Paramount sold a portion of its investment in MEG Energy Corp. for cash proceeds of $13.6 million. As a result of the sale, $61.8 million of accumulated losses were reclassified from accumulated OCI to retained earnings.

Changes in the fair value of investments in securities are as follows:

Year endedat December 31	2020	2019(1)
Investments in securities, beginning of year	156.9	231.7
Changes in fair value of Level One Securities–recorded in OCI	(50.6)	6.3
Changes in fair value of Level Three Securities (2) –recorded in OCI	32.5	(118.1)
Transfer to Dissent Payment Entitlement	(89.3)	–
Changes in fair value of warrants (3) –recorded in earnings	(1.7)	(9.2)
Acquired –cash	11.7	55.1
Acquired –non-cash	–	4.5
Dispositions	–	(13.6)
Investments in securities, end of year	59.5	156.9

(1) Column does not add due to rounding.

(2) Primarily related to the change in fair value of Strath common shares.

(3) Strathcona warrants (previously the Strath warrants).

ASSET RETIREMENT OBLIGATIONS

The area-based closure program introduced by the Alberta Energy Regulator in September 2018 allows companies to approach abandonment and reclamation activities in an efficient and cost-effective manner by targeting efforts in a concentrated area. Paramount's strategy is to utilize the advantages of the areabased closure program by focusing its abandonment and reclamation activities on the Hawkeye property, which was shut-in in 2018, and the Zama property, which was shut-in in 2019.

Abandonment and reclamation expenditures in 2020 totaled $35 million. In addition, approximately $4 million of activities were funded by the ASRP. Activities included the abandonment of 254 inactive wells, 236 of which were abandoned under the Company's ongoing area-based closure program at the Hawkeye and Zama properties.

The Company has budgeted approximately $31 million of abandonment and reclamation activities in 2021. Approximately $6 million is to be funded directly under the ASRP, resulting in approximately $25 million net to Paramount. The majority of 2021 closure activities will be performed at the Zama property.

As at December 31, 2020, estimated undiscounted, uninflated asset retirement obligations were $1,351.7 million (December 31, 2019 – $1,381.5 million). As at December 31, 2020, the Company's discounted asset retirement obligations were $419.5 million (discounted at 11.0 percent and using an inflation rate of 2.0 percent) compared to $569.9 million as at December 31, 2019 (discounted at 8.0 percent and using an inflation rate of 2.0 percent). For further details concerning the Company's asset retirement obligations, refer to the Consolidated Financial Statements.

OTHER ASSETS

Fox Drilling

Fox Drilling owns seven triple-sized drilling rigs, including four walking rigs, that are used to drill Company wells. The walking rigs have the capability of moving across a lease with the derrick and drill pipe remaining vertical, significantly increasing efficiencies when drilling multi-well pads.

Cavalier Energy

As at December 31, 2020, Cavalier Energy held approximately 1.354 million gross (1.307 million net) acres of land located primarily in the Athabasca and Peace River regions of Alberta. Cavalier Energy's lands are prospective for in-situ thermal oil recovery and heavy oil but are at the early stages of their development.

CORPORATE

Year ended December 31	2020	2019
General and administrative	(32.9)	(52.6)
Share-based compensation	(13.0)	(18.5)
Interest and financing	(53.7)	(40.2)
Accretion of asset retirement obligations	(43.4)	(56.7)
Change in asset retirement obligations	91.3	107.3
Closure costs	–	(14.0)
Dispute settlements	–	(2.5)
Deferred income tax expense	(10.2)	(112.3)

General and administrative and share-based compensation expenses were lower for the year ended December 31, 2020 compared to the same period in 2019 primarily due to cost reduction initiatives, including workforce and salary reductions and the suspension or elimination of a number of benefits and incentive compensation programs. General and administrative expense in 2020 was reduced by $6.4 million as a result of the Company's claim of benefits under the CEWS program.

Interest and financing expense was $53.7 million in 2020, an increase of $13.5 million compared to 2019, as a result of higher average debt balances and interest rates under the Paramount Facility (as described below).

For the year ended December 31, 2020, the Company recorded a recovery of $91.3 million (2019 - $107.3 million recovery) to earnings mainly related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value. In 2020, the changes mainly resulted from revisions in the credit-adjusted risk-free rate used to discount obligations. The changes in 2019 were a result of revisions to the estimated costs and timing of retirement.

In early 2019, Paramount made the decision to cease production operations at its Zama property in the Central Alberta and Other Region. Sales volumes at Zama averaged approximately 1,200 Boe/d (2.3 MMcf/d of conventional natural gas, 30 Bbl/d of NGLs and 817 Bbl/d of light and medium crude oil) in the fourth quarter of 2018. The Company recognized a provision of $14.0 million in 2019 in respect of the expected costs of the Zama closure program, of which the entire $14.0 million had been incurred to December 31, 2019.

The Company recognized a charge of $2.5 million in the fourth quarter of 2019 in respect of two legal disputes. For further details, refer to the Consolidated Financial Statements.

Deferred income tax expense for 2019 included a charge of approximately $101.2 million related to a reduction in Alberta income tax rates.

Tax Pools

At December 31, 2020, Paramount had approximately $3.5 billion of non-capital loss and scientific research and experimental development pools, $1.3 billion of Canadian resource and undepreciated capital cost pools and $0.1 billion of financing cost and other pools.

PROPERTY, PLANT AND EQUIPMENT AND EXPLORATION EXPENDITURES

Year ended December 31	2020	2019
Drilling, completion and tie-ins	199.5	297.7
Facilities and gathering(1)	18.4	92.8
Corporate	2.3	6.0
Land and property acquisitions	0.6	7.6
Total capital expenditures (2)	220.8	404.1

Grande Prairie Region (1)	196.9	302.2
Kaybob Region	16.4	80.7
Central Alberta and Other Region	4.6	7.6
Corporate	2.3	6.0
Land and property acquisitions	0.6	7.6
Total capital expenditures (2)	220.8	404.1

(1) Total capital expenditures for the year ended December 31, 2019 includes $45.5 million of capital spending related to the Karr 6-18 natural gas facility prior to its sale.

(2) "Total capital expenditures" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section.

Total capital expenditures were $220.8 million for the year ended December 31, 2020 compared to $404.1 million in the same period of 2019.

Activities in 2020 mainly related to drilling and completion programs in the Grande Prairie Region.

Significant capital program activities undertaken in 2020 are described below:

At Karr, the Company drilled 15 (15.0 net) Montney wells, completed 15 (15.0 net) wells and brought 15 (15.0 net) wells on production in 2020. Paramount brought into service two new water disposal wells that have decreased operating costs by reducing the need to truck and dispose of water at third-party facilities. In addition, gas lift and related compression at pads near the southwest terminus of the Karr gathering system were installed to mitigate the impact from new higher-pressure wells upstream. In the fourth quarter, the Company brought onstream 5 (5.0 net) Montney wells and drilled 6 (6.0 net) wells.
At Wapiti, Paramount drilled 8 (8.0 net) Montney wells, completed 5 (5.0 net) wells and brought 6 (6.0 net) wells on production wells in 2020. In the fourth quarter, the Company brought onstream 5 (5.0 net) Montney wells and drilled 1 (1.0 net) wells.
In the Kaybob Region, Paramount drilled 1 (1.0 net) Montney oil appraisal well at Ante Creek.
In the Central and Other Region, 1 (0.5 net) well was completed at the Company's non-operated Birch property in British Columbia.

Paramount reduced average per well lease construction, drilling, completion and tie-in costs in 2020 compared to 2019 by approximately 37 percent at Karr and 21 percent at Wapiti. The reductions were driven by improvements in well design, drill bit technology, fluid selection and reducing vendor rates. Cost savings in Paramount's capital program allowed the completion of additional unbudgeted development activities at Karr and Wapiti in 2020 without exceeding total capital expenditure guidance.

LIQUIDITY AND CAPITAL RESOURCES

Paramount's primary objectives in managing its capital structure are to:

i. maintain a flexible capital structure which optimizes the cost of capital at an acceptable level of risk;
ii. maintain sufficient liquidity to support ongoing operations, capital expenditure programs, strategic initiatives and the settlement of obligations when due; and
iii. maximize shareholder returns.

Paramount manages its capital structure to support current and future business plans and periodically adjusts the structure in response to changes in economic conditions and the risk characteristics of the Company's underlying assets and operations. Paramount may adjust its capital structure through a number of means, including by issuing or repurchasing shares, altering debt levels, modifying capital spending programs, acquiring or disposing of assets and participating in joint ventures and farm-ins and farm-outs, the availability of any such means being dependent upon market conditions.

As atDecember 31	2020	2019
Cash and cash equivalents	(4.6)	(6.0)
Accounts receivable(1)	(97.7)	(116.6)
Prepaid expenses and other	(9.9)	(11.0)
Accounts payable and accrued liabilities	152.8	204.8
Adjusted working capitaldeficit(1) (2)	40.6	71.2
Long-term debt	813.5	632.3
Net debt(2)	854.1	703.5
Share capital	2,207.4	2,207.5
Accumulated deficit	(235.1)	(128.5)
Reserves	65.4	4.2
Total Capital	2,891.8	2,786.7

(1) Adjusted working capital excludes risk management assets and liabilities, current accounts receivable relating to subleases (December 31, 2020 - $2.3 million, December 31, 2019 – $2.0 million) and the current portion of asset retirement obligations and other.

(2) "Adjusted working capital deficit" and "Net debt" are Non-GAAP financial measures. See "Non-GAAP Financial Measures" in the Advisories section.

Paramount's operations are capital intensive and adequate sources of liquidity are required to fund ongoing exploration and development activities, discharge asset retirement obligations and satisfy contractual commitments. Paramount's available capital resources include adjusted funds flow and available capacity under its senior secured revolving bank credit facility (the "Paramount Facility"), the terms of which are described further below.

Based on the forecasts of 2021 sales volumes and the pricing assumptions set out in this MD&A under "2021 Guidance", Paramount expects to fully fund budgeted capital expenditures of between $230 million and $260 million and net budgeted expenditures for abandonment and reclamation activities of $25 million from cash from operating activities. Paramount may utilize borrowing capacity under the Paramount Facility for liquidity from time to time to fund operations during periods of the year in which expenditures exceed cash from operating activities.

The ability of cash from operating activities to satisfy the Company's funding requirements in 2021 and future years is dependent on a number of factors, including commodity prices, sales volumes, royalties, operating and transportation costs, general and administrative and interest expenses and foreign exchange rates.

Paramount may also determine to divest of assets or investments in securities from time to time to reduce indebtedness or fund operations. In the first quarter of 2021, the Company sold certain non-core properties in the Kaybob and Central Alberta & Other Regions for aggregate cash proceeds of approximately $80 million and used such proceeds to reduce indebtedness under the Paramount Facility.

Subject to market conditions and availability, proceeds from new debt and/or equity financings may also provide additional sources of capital from time to time. In January 2021, as described below under "Debentures", the Company issued $35 million of senior unsecured convertible debentures and used the proceeds to reduce indebtedness under the Paramount Facility.

Paramount Facility

The Company has a $1.0 billion financial covenant-based senior secured revolving bank credit facility (the "Paramount Facility"). The maturity date of the Paramount Facility is currently November 16, 2022, which may be extended from time to time at the option of Paramount and with the agreement of the lenders.

Borrowings under the Paramount Facility bear interest at the lenders' prime lending rate, US base rate, bankers' acceptance rate, or LIBOR, as selected at the discretion of the Company, plus a margin within a graduated range (the "Pricing Range") depending on the Company's prevailing Senior Secured Debt to Consolidated EBITDA ratio. The Paramount Facility is secured by a charge over substantially all of the assets of Paramount.

Paramount is subject to the following two financial covenants under the Paramount Facility (except during the period of financial covenant relief described further below) which are tested at the end of each fiscal quarter and calculated on a trailing twelve-month basis:

Senior Secured Debt to Consolidated EBITDA to be 3.50 to 1.00 or less; and
Consolidated EBITDA to Consolidated Interest Expense to be 2.50 to 1.00 or greater.

Senior Secured Debt currently consists of amounts drawn on the Paramount Facility and the undrawn face amounts of letters of credit outstanding under the Paramount Facility.

Consolidated EBITDA is adjusted for material acquisitions and dispositions and is generally calculated as net income before Consolidated Interest Expense, taxes, depletion, depreciation, amortization, impairment and E&E expense and is also adjusted to exclude non-recurring items and other non-cash items including unrealized mark-to-market amounts on derivatives, unrealized foreign exchange, share-based compensation expense and accretion.

Consolidated Interest Expense is reduced by customary exclusions including interest income.

In June 2020, the Paramount Facility was amended, which amendments included:

a period of financial covenant relief to and including June 30, 2021 (the "Covenant Relief Period") providing for a full waiver of the Senior Secured Debt to Consolidated EBITDA covenant and a reduction of the Consolidated EBITDA to Consolidated Interest Expense covenant in certain periods;
a decrease in the size of the Paramount Facility from $1.5 billion to $1.0 billion, with availability in excess of $900 million subject to certain new additional conditions (the "New Conditions"); and
the margin applicable to credit facility drawings remaining at the highest end of the Pricing Range during the Covenant Relief Period.

In January 2021, the Paramount Facility was further amended to remove the New Conditions on availability in excess of $900 million. As a result, the full $1.0 billion capacity of the Paramount Facility is available.

During the Covenant Relief Period, Paramount was subject to the following financial covenant, tested at the end of each fiscal quarter:

Consolidated EBITDA to Consolidated Interest Expense to be:

1.75 to 1.00 or greater for the quarter ending December 31, 2020, calculated on a trailing twelve-month basis; and
1.75 to 1.00 or greater for the quarters ending March 31, 2021 and June 30, 2021, calculated on a current quarter basis.

Paramount was in compliance with the applicable financial covenant under the Paramount Facility at December 31, 2020.

Paramount elected to exit the Covenant Relief Period in March 2021, prior to its scheduled expiry on June 30, 2021.

Paramount had undrawn letters of credit outstanding under the Paramount Facility totaling $1.3 million at December 31, 2020 that reduce the amount available to be drawn on the Paramount Facility.

Unsecured Letter of Credit Facility

The Company has a $70 million unsecured demand revolving letter of credit facility (the "LC Facility") with a Canadian bank.

Paramount's obligations under the LC Facility are supported by a performance security guarantee ("PSG") from Export Development Canada ("EDC"). The PSG is valid to June 30, 2021 and may be extended at the option of Paramount and with the agreement of EDC. At December 31, 2020, $40.7 million in undrawn letters of credit were outstanding under the LC Facility.

Debentures

In January 2021, the Company completed a private placement of $35 million of senior unsecured convertible debentures (the "Debentures"). An entity controlled by Paramount's President and Chief Executive Officer and Chairman purchased $25 million of the Debentures. An entity controlled by the Company's Executive Vice President, Corporate Development and Planning, purchased $0.1 million of the Debentures. The Debentures mature on January 31, 2024 (the "Maturity Date"), bear interest at 7.50 percent per annum payable monthly in arrears and are convertible by the holder into Common Shares at any time prior to the Maturity Date at a conversion price of $6.72 per Common Share prior to January 31, 2022, $7.33 per Common Share on or after January 31, 2022 and prior to January 31, 2023 and $7.94 per Common Share on or after January 31, 2023.

The Debentures are redeemable by Paramount, in whole or in part, at any time prior to the Maturity Date, at a redemption price (expressed as percentages of principal amount) equal to 107.50 percent prior to January 31, 2022, 103.75 percent on or after January 31, 2022 and prior to January 31, 2023 and 101.875 percent on or after January 31, 2023.

Cash Flow Hedges

The Company had the following floating-to-fixed interest rate and electricity swaps in place at December 31, 2020:

	Aggregate		Average fixed
Contract type	notional	Remaining term	contract rate	Reference	Fair value
Interest Rate Swaps	$250 million	January 2021-January 2023	2.3%	CDOR (1)	(9.2)
Interest Rate Swaps	$250 million	January 2021-January 2026	2.4%	CDOR (1)	(19.8)
Electricity Swaps	5 MWh/d(2)	January 2021 -December 2021		$51.68/MWh AESO Pool Price(3)	0.4
					(28.6)

(1) Canadian Dollar Offered Rate.

(2) "MWh" means MegaWatt hour.

(3) Floating hourly rate established by the Alberta Electric System Operator.

In 2019, Paramount entered into interest rate swaps to manage the uncertainty of variable interest rates by fixing the underlying CDOR interest rate on a portion of the Company's long-term debt. The Company classified these arrangements as cash flow hedges and has applied hedge accounting. There is an economic relationship between the hedged items and hedging instruments as the timing and amount of the cash flows received from the interest rate swaps matched the terms of the expected highly probable forecast transactions, which is the underlying CDOR amount of interest paid on $500 million of the Company's long-term debt. A hedge ratio of 1 to 1 was established as the underlying risk of the interest rate swaps were identical to the hedged risk components. As at December 31, 2020, there were no changes to the critical terms of the hedging relationship and no hedge ineffectiveness was identified.

In the third quarter of 2020, Paramount entered into floating-to-fixed-price swaps to manage exposure to the variable market price of electricity by fixing the underlying AESO Pool Price on a portion of the Company's power. The Company classified these arrangements as cash flow hedges and has applied hedge accounting. As at December 31, 2020, there were no changes to the critical terms of the hedging relationship and no hedge ineffectiveness was identified.

Share Capital

In November 2019, Paramount issued 5.9 million Common Shares on a "flow-through" basis in respect of Canadian development expenses at a price of $6.65 per share for gross proceeds of $39.2 million pursuant to a private placement. An entity controlled by the Company's President and Chief Executive Officer and Chairman acquired 3.8 million of the Common Shares under the private placement for $24.9 million. A liability of $2.6 million was initially recognized on the issuance of the flow-through shares in respect of the Company's obligation to renounce qualifying expenditures. Paramount has since incurred sufficient qualifying expenditures to satisfy commitments associated with the flow-through share issuance.

In January 2020, Paramount implemented a normal course issuer bid program (the ʺ2020 NCIBʺ) under which the Company was permitted to purchase up to 7,044,289 Common Shares for cancellation. The Company did not purchase any Common Shares under the 2020 NCIB and the 2020 NCIB expired in January 2021.

Paramount previously implemented a normal course issuer bid program in January 2019 (the ʺ2019 NCIBʺ). In 2019, the Company purchased and cancelled 2,622,200 million Common Shares at a total cost of $14.4 million under the 2019 NCIB.

At February 28, 2021, Paramount had 132,642,503 Common Shares outstanding (net of 1,914,394 Common Shares held in trust under the Company's restricted share unit plan) and 9,321,415 options to acquire Common Shares outstanding, of which 2,046,890 options are exercisable.

At February 28, 2021, $35 million of Debentures are issued and outstanding. A total maximum of 5.2 million Common Shares are issuable upon conversion of the outstanding Debentures at the current conversion price of $6.72 per Common Share.

FOURTH QUARTER RESULTS

Netback (1)

Three months ended December 31	2020		2019
		($/Boe)(2)		($/Boe)(2)
Natural gas revenue	66.7	2.83	75.1	2.73
Condensate and oil revenue	123.3	52.03	175.0	66.70
Other NGLs revenue (3)	9.5	20.61	8.5	13.03
Royalty and otherrevenue	2.5	–	1.3	–
Petroleum and natural gas sales	202.0	29.89	259.9	33.08
Royalties	(11.7)	(1.73)	(17.2)	(2.19)
Operating expense	(79.8)	(11.80)	(105.0)	(13.36)
Transportation and NGLs processing (4)	(24.6)	(3.63)	(22.8)	(2.90)
Netback	85.9	12.73	114.9	14.63
Financial commodity contractsettlements	7.9	1.18	4.7	0.60
Netback including financial commodity contractsettlements	93.8	13.91	119.6	15.23

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

(2) Natural gas revenue shown per Mcf.

(3) Other NGLs means ethane, propane and butane.

(4) Includes downstream natural gas, NGLs and oil transportation costs and NGLs fractionation costs.

Fourth quarter 2020 petroleum and natural gas sales were $202.0 million, a decrease of $57.9 million from the fourth quarter of 2019, mainly due to lower condensate and oil prices and decreased sales volumes.

The impact of changes in sales volumes and prices on petroleum and natural gas sales are as follows:

	NaturalGas	Condensateand Oil	OtherNGLs	Royalty andOther	Total
Three months ended December 31, 2019	75.1	175.0	8.5	1.3	259.9
Effect of changes in sales volumes	(10.7)	(17.0)	(2.5)	–	(30.2)
Effect of changes in prices	2.3	(34.7)	3.5	–	(28.9)
Change in royalty and otherrevenue	–	–	–	1.2	1.2
Three monthsended December 31, 2020	66.7	123.3	9.5	2.5	202.0

Sales Volumes (1)

	Three monthsended December 31
		Natural Gas		Condensate and Oil			Other NGLs			Total
		(MMcf/d)		(Bbl/d)		(Bbl/d)			(Boe/d)
	2020		2019 % Change	2020	2019	% Change	2020		2019 % Change	2020		2019 % Change
Grande Prairie	94.3	93.4	1	19,635	18,851	4	2,429	2,376	2	37,782	36,789	3
Kaybob	118.2	137.4	(14)	5,410	7,771	(30)	1,953	2,504	(22)	27,056	33,167	(18)
Central Alberta& Other	43.8	68.2	(36)	707	1,894	(63)	605	2,184	(72)	8,622	15,455	(44)
Total	256.3	299.0	(14)	25,752	28,516	(10)	4,987	7,064	(29)	73,460	85,411	(14)

Sales volumes in the fourth quarter of 2020 averaged 73,460 Boe/d compared to 85,411 Boe/d in the fourth quarter of 2019. The decrease was primarily due to the sale of the West Central Alberta Assets in December 2019 and natural declines in the Kaybob Region where the Company deployed limited capital in 2020 to focus on developments at Karr and Wapiti in the Grande Prairie Region.

These decreases were partially offset by higher sales volume in the Grande Prairie Region, where the Company brought 15 new Montney wells onstream at Karr in third and fourth quarters of 2020 and 5 new Montney wells onstream at Wapiti in the fourth quarter of 2020.

For the three months ended December 31, 2019, the West Central Alberta Assets had average sales volumes of approximately 5,900 Boe/d (20.7 MMcf/d of conventional natural gas, 2,085 Bbl/d of NGLs and 324 Bbl/d of light and medium crude oil) and a netback of approximately $5.4 million.

In the first quarter of 2021, the Company sold certain non-core properties in the Kaybob and Central Alberta CGUs for aggregate cash proceeds of approximately $80 million. For the three months ended December 31, 2020 these assets had average sales volumes of approximately 2,700 Boe/d (15.4 MMcf/d of conventional natural gas and 142 Bbl/d of NGLs) and a netback of approximately $3 million.

Commodity Prices

Three months ended December 31	2020	2019	% Change
Natural Gas
Paramount realized price ($/Mcf)	2.83	2.73	4
AECO daily spot ($/GJ)	2.50	2.35	6
AECO monthly index ($/GJ)	2.62	2.21	19
Dawn ($/MMbtu)	2.97	2.99	(1)
NYMEX (US$/MMbtu)	2.76	2.42	14
Malin –monthly index (US$/MMbtu)	2.93	2.65	11
Condensate and Oil
Paramount realized condensate& oil price ($/Bbl)	52.03	66.70	(22)
Edmonton light sweetcrude oil($/Bbl)	49.17	66.77	(26)
West Texas Intermediatecrude oil(US$/Bbl)	42.66	56.96	(25)
Other NGLs (1)
Paramount realized Other NGLs price ($/Bbl) (1)	20.61	13.03	58
Conway –propane ($/Bbl)	30.32	26.05	16
Belvieu –butane ($/Bbl)	36.10	39.85	(9)
Foreign Exchange
$CDN / 1 $US	1.30	1.32	(2)

(1) Other NGLs means ethane, propane and butane.

The Company's realized natural gas prices increased in the fourth quarter of 2020 compared to the same period in 2019 mainly due to higher benchmark prices. Realized natural gas prices also included the impact of fixed-price AECO physical contracts to sell approximately 67,000 GJ/d of natural gas at C$2.18/GJ in the fourth quarter of 2020 (2019 - approximately 17,000 GJ/d of natural gas at C$2.36/GJ).

Realized condensate and oil prices in the fourth quarter of 2020 decreased 22 percent compared to the fourth quarter of 2019 as a result of decreases in benchmark prices.

The Company's propane and butane contracts in place in the fourth quarter of 2020 had more favorable differentials to West Texas Intermediate reference prices than the same period in 2019.

Royalties decreased $5.5 million in the fourth quarter of 2020 compared to the same period in 2019, primarily as a result of lower condensate and oil prices and decreased sales volumes.

Operating expense decreased $25.2 million to $79.8 million in the fourth quarter of 2020 compared to $105.0 million in the same period in 2019. Operating costs in the fourth quarter of 2020 were lower compared to the same period in 2019 primarily as a result of lower production in the Central and Other and Kaybob regions, cost reductions from new water disposal wells, decreased labour and power costs and supplier cost savings. Operating expenses were $11.80 per Boe in the fourth quarter of 2020, which is $0.30 per Boe higher than forecasted due to unbudgeted well workovers in Karr which increased fourth quarter production.

Transportation and NGLs processing costs increased in the fourth quarter of 2020 mainly as a result of higher contracted capacity for Karr and Wapiti, partially offset by lower production in the Central and Other and Kaybob Regions.

Net Income (Loss)

Three months ended December 31	2020	2019

Petroleum and natural gas sales	202.0	259.9
Royalties	(11.7)	(17.2)
Revenue	190.3	242.7
Losson financial commodity contracts	(24.1)	(17.2)
	166.2	225.5
(Expenses) Income
Operating expense	(79.8)	(105.0)
Transportation and NGLs processing	(24.6)	(22.8)
General and administrative	(9.1)	(12.6)
Share-based compensation	(6.8)	(4.2)
Depletion, depreciationand impairmentreversals	268.8	(116.1)
Exploration and evaluation	(8.8)	(4.4)
Gainon sale of oil and gas assets	0.1	4.2
Interest and financing	(17.8)	(10.2)
Accretion of asset retirement obligations	(11.2)	(12.2)
Change in asset retirement obligations	(29.7)	33.8
Closure costs	–	(0.5)
Transaction and reorganization costs	–	(2.3)
Foreign exchange	(0.6)	–
	80.5	(252.3)
Other	0.4	(7.2)
Income (loss)before tax	247.1	(34.0)
Incometaxrecovery
Deferred	64.4	2.9

Netincome(loss)	311.5	(31.1)

Paramount recorded net income of $311.5 million for the three months ended December 31, 2020 compared to a net loss of $31.1 million in the same period in 2019. Significant factors contributing to the change are shown below:

Three months endedDecember 31,
Net loss–2019	(31.1)
•A recovery of $268.8 million recorded for depletion, depreciation and net impairment reversals in 2020compared to an expense of $116.1 million in 2019, mainly due to impairment reversals of $333.7 millionand lower depletion expense in 2020	384.9
•Higher income tax recovery in 2020, mainly due to the recognition of the previously unrecognizeddeferred income tax asset	61.5
•Expenserelated to changes in asset retirement obligations in 2020compared to a recovery in 2019	(63.5)
•Lower netback in 2020, mainly due to lower condensate and oilprices and lower sales volumes, partiallyoffset by lower operating expense	(29.0)
•Higher interest and financing expenses in 2020	(7.6)
•Higher loss on financial commodity contractsin 2020	(6.9)
•Other	3.2
Net income–2020	311.5

Cash From Operating Activities

Cash from operating activities for the three months ended December 31, 2020 was $53.2 million compared to $70.5 million for the same period in 2019. Significant factors contributing to the change are shown below:

Three months ended December 31
Cash from operating activities –2019	70.5
•Lower netback in 2020, mainly due to lower condensate and oil prices and lower sales volumes, partiallyoffset by lower operating expense	(29.0)
•Change in non-cash working capital	(20.5)
•Higher interest and financing expenses in 2020	(7.0)
•Lower asset retirement obligation settlements in 2020	17.9
•Closure program costs recognized in 2019	4.7
•Lower general and administrative expenses in 2020	3.5
•Higher receipts on financial commodity contract settlements in 2020	3.2
•Other	9.9
Cash from operating activities –2020	53.2

Adjusted Funds Flow (1)

The following is a reconciliation of adjusted funds flow to the nearest GAAP measure:

Three months ended December 31	2020	2019
Cash from operating activities	53.2	70.5
Change in non-cash working capital	12.5	(8.0)
Geological and geophysical expenses	2.1	3.5
Asset retirement obligations settled	0.1	18.0
Closure costs	–	4.7
Dispute settlements	–	2.5
Transaction and reorganization costs	–	2.3
Adjusted funds flow	67.9	93.5
Adjusted funds flow ($/Boe)	10.05	11.89

(1) Refer to the advisories concerning Non-GAAP financial measures in the Advisories section of this document.

Adjusted funds flow in the fourth quarter of 2020 was $67.9 million compared to $93.5 million in the same period in 2019. Significant factors contributing to the change are shown below:

Three months ended December 31
Adjusted funds flow –2019	93.5
•Lower netback in 2020, mainly due to lower condensate and oil prices and lower sales volumes, partiallyoffset by lower operating expense	(29.0)
•Higher interest and financing expenses in 2020	(7.0)
•Lower general and administrative expenses in 2020	3.5
•Higher receipts on financial commodity contract settlements in 2020	3.2
•Other	3.7
Adjusted funds flow–2020	67.9

Total Capital Expenditures by Region (1)

Three months ended December 31	2020	2019
Grande Prairie Region	64.3	60.7
Kaybob Region	1.8	9.5
Central Alberta and Other Region	0.8	0.6
Corporate(2)	(1.8)	–
Land and property acquisitions	–	1.4
Total capital expenditures	65.1	72.2

(1) Readers are referred to the advisories concerning Non-GAAP financial measures in the Advisories section of this document.

(2) Includes transfers between regions.

Total capital expenditures in the fourth quarter of 2020 totaled $65.1 million, with the majority of spending directed towards drilling and completion programs in the Grande Prairie Region.

QUARTERLY INFORMATION

		2020		2019
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Petroleum and natural gas sales	202.0	138.8	113.2	172.1	259.9	199.8	209.2	246.1
Net income (loss)	311.5	(23.3)	(75.7)	(235.1)	(31.1)	141.0	(121.0)	(76.7)
Per share – basic & diluted ($/share)	2.35	(0.17)	(0.57)	(1.76)	(0.24)	1.08	(0.93)	(0.59)
Cash from (used in)operatingactivities	53.2	11.4	(14.2)	30.5	70.5	48.6	48.1	88.5
Per share – basic & diluted ($/share)	0.40	0.09	(0.11)	0.23	0.54	0.37	0.37	0.68
Adjusted funds flow	67.9	29.5	19.0	33.5	93.5	50.9	54.2	100.5
Per share – basic & diluted ($/share)	0.51	0.22	0.14	0.25	0.71	0.39	0.41	0.77
Sales volumes(1)
Natural gas (MMcf/d)	256.3	224.0	253.2	261.5	299.0	296.6	309.7	308.0
Condensate and oil (Bbl/d)	25,752	19,782	22,823	21,898	28,516	24,761	23,312	23,679
Other NGLs (Bbl/d)	4,987	3,952	3,817	4,539	7,064	6,851	6,859	6,284
Total (Boe/d)	73,460	61,064	68,839	70,022	85,411	81,046	81,793	81,296
Realized prices
Natural gas ($/Mcf)	2.83	1.94	1.94	2.25	2.73	1.58	1.76	3.37
Condensate and oil ($/Bbl)	52.03	48.74	29.05	55.92	66.70	65.73	71.02	63.26
Other NGLs ($/Bbl)	20.61	18.10	12.28	10.75	13.03	9.78	11.01	28.55
Total ($/Boe)	29.89	24.70	18.07	27.01	33.08	26.80	28.10	33.63

Significant Items Impacting Quarterly Results

Quarterly earnings variances include the impacts of changing production volumes and market prices.

Fourth quarter 2020 earnings include aggregate impairment reversals of $333.7 million from previously recorded impairment charges of petroleum and natural gas assets and a deferred income tax recovery of $64.4 million, partially offset by a charge of $29.7 million related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value.
The third quarter 2020 loss includes a recovery of $25.6 million related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value.
The second quarter 2020 loss includes a recovery of $13.6 million related to deferred income tax.
The first quarter 2020 loss includes a $191.8 million impairment of petroleum and natural gas assets and a derecognition of $130.0 million of the deferred income tax asset, partially offset by a recovery of $94.8 million related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value.
The fourth quarter 2019 loss includes a recovery of $33.8 million related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value.
Third quarter 2019 earnings include a $157.3 million gain on the sale of oil and gas assets, primarily related to the Midstream Transaction and a recovery of $73.5 million related to changes in the discounted carrying value of estimated asset retirement obligations in respect of properties that had a nil carrying value.
The second quarter 2019 loss includes $102.1 million of deferred income tax expense, primarily related to a reduction in Alberta income tax rates and a $27.6 million gain on financial commodity contracts.
The first quarter 2019 loss includes a $72.6 million loss on financial commodity contracts.

OTHER INFORMATION

Contractual Obligations

Paramount had the following contractual obligations at December 31, 2020: (1)

	Within 1year	After oneyear butnot morethan threeyears	After threeyears butnot morethan fiveyears	More thanfive years	Total
Paramount Facility	–	815.7	–	–	815.7
Transportation and processing commitments (2)	259.1	467.8	421.7	1,174.4	2,323.0
Asset retirement obligations (3)	22.3	74.6	87.7	1,167.1	1,351.7
Finance lease and other commitments(4)	12.9	13.6	14.1	–	40.6
	294.3	1,371.7	523.5	2,341.5	4,531.0

(1) Excludes risk management liabilities and accounts payable and accrued liabilities, which are described in Note 14 of the Consolidated Financial Statements.

(3) Undiscounted, uninflated asset retirement obligations estimated as at December 31, 2020. Does not include impact of government funding. Estimated costs and timing of settlement are revised from time-to-time based on new information.

(4) Undiscounted finance lease payments in respect of office and vehicle commitments have been reduced by sublease revenue amounts receivable.

Transportation and processing commitments mainly relate to long-term firm service arrangements for the processing and transportation of the Company's sales volumes.

(2) Certain of the transportation and processing commitments are secured by outstanding letters of credit totaling $13.2 million at December 31, 2020 (December 31, 2019 - $10.2 million).

Contingencies

In the normal course of Paramount's operations, the Company may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty. Other than with respect to the Dissent Payment Entitlement, Paramount does not anticipate that these claims will have a material impact on its financial position.

Tax and royalty legislation and regulations, and government interpretation and administration thereof, continually change. As a result, there are often tax and royalty matters under review by relevant government authorities. All tax and royalty filings are subject to subsequent government audit and potential reassessments. Accordingly, the final amounts may differ materially from amounts estimated and recorded.

Provision

In the first quarter of 2020, a provision of $4.7 million was recorded related to a pending partner dispute.

NEW AND UPDATED ACCOUNTING POLICIES AND STANDARDS

Financial Instruments

Effective January 1, 2020, the Company adopted the amendments to IFRS 9 – Financial Instruments ("IFRS 9"), IAS 39 – Financial Instruments: Recognition and Measurement ("IAS 39") and IFRS 7 – Financial Instruments: Disclosures ("IFRS 7"). These amendments provided relief on hedge accounting from the potential effects of the uncertainty arising from the phase-out of interest rate benchmarks, the Interbank Offered Rate ("IBOR") reform. The Company's floating-to-fixed interest rate swaps, which are described in Note 14 of the Consolidated Financial Statements, are impacted by these amendments as hedge accounting is applied to these instruments and hedging relationships may be impacted by the IBOR reform. There has been no impact on the recognized assets, liabilities or comprehensive loss of the Company resulting from the adoption of these amendments.

Government Grants

Government grants are recognized when there is reasonable assurance that the relevant conditions of the grant are met and that the grant will be received. The Company records the grant in the Consolidated Financial Statements with the related expenditure in the period in which the eligible costs are incurred. For the year ended December 31, 2020 the Company recognized $11.1 million relating to the CEWS program which reduced general and administrative expenses, operating expenses and capital expenditures by $6.4 million, $4.0 million and $0.7 million, respectively. Asset retirement settlements approved under government programs are recorded as a credit to earnings in change in asset retirement obligations in the period in which the related eligible costs are incurred.

Future Changes in Accounting Standards

In 2020, the International Accounting Standards Board published phase two of its amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 – Insurance Contracts and IFRS 16 - Leases ("IFRS 16") to assist companies in applying IFRS when changes are made to contractual cash flows or hedging relationships arising from the replacement of an interest rate benchmark with an alternative benchmark rate from IBOR reform. These amendments are effective for years beginning on or after January 1, 2021. Paramount expects that the amendments will not have a material impact on the Consolidated Financial Statements on adoption.

DISCLOSURE CONTROLS AND PROCEDURES

As of the year ended December 31, 2020, an evaluation of the effectiveness of Paramount's disclosure controls and procedures ("DCP"), as defined under National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings" ("NI 52-109"), was performed by the Company's Management with the oversight of the Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, the Company's Chief Executive Officer and Chief Financial Officer have concluded that the Company's DCP are effective as of December 31, 2020.

It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Company's disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management, with the oversight of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's internal controls over financial reporting ("ICFR") as defined under NI 52-109 as at December 31, 2020. In making its evaluation, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013). Based on this evaluation, the Company's Chief Executive Officer and Chief Financial Officer have concluded that the Company's ICFR was effective as of December 31, 2020.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Changes in Internal Control Over Financial Reporting

During the year ended December 31, 2020, there was no change in the Company's ICFR that materially affected, or is reasonably likely to materially affect, the Company's ICFR. Paramount does not believe that process changes adopted in connection with the COVID-19 pandemic have materially affected ICFR.

RISK FACTORS

Readers should, in conjunction with their review of this MD&A, carefully review the "Risk Factors" section in the Company's Annual Information Form for the year ended December 31, 2020, which is available under the Company's profile on SEDAR at www.sedar.com.

The course of the COVID-19 pandemic and its ultimate economic impact remain highly uncertain. The ultimate impact of the pandemic on Paramount's future operations and financial performance is unknown and will be dependent on a number of unpredictable factors outside of the knowledge and control of Management, including: (i) the duration and severity of the pandemic; (ii) the impact of the pandemic on economic growth, commodity prices and financial and capital markets; and (iii) governmental responses and restrictions. These uncertainties may continue to persist beyond the point where the outbreak of the COVID-19 virus has subsided. See "Risk Factors – COVID 19 Pandemic" in the Annual Information Form.

CRITICAL ACCOUNTING ESTIMATES

The timely preparation of financial statements requires Management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosures regarding contingent assets and liabilities. Estimates and assumptions are regularly evaluated and are based on Management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Changes in judgments, estimates and assumptions based on new information could result in a material change to the carrying amount of assets or liabilities and have a material impact on assets, liabilities, revenues and expenses recognized in future periods.

The potential impact of the COVID-19 pandemic has been considered by Management in making judgments, estimates and assumptions used in the preparation of the Consolidated Financial Statements, but the inherent risks and uncertainties resulting from the pandemic may result in material changes to such judgments, estimates and assumptions in future periods as additional information becomes available.

A description of the accounting judgments, estimates and assumptions that are considered significant is set out below.

Exploration or Development

The Company is required to apply judgment when designating a project as exploration and evaluation or development, including assessments of geological and technical characteristics and other factors related to each project.

Exploration and Evaluation Projects

The accounting for E&E projects requires Management to make judgments as to whether exploratory projects have discovered economically recoverable quantities of petroleum and natural gas, which requires the quantity and realizable value of such petroleum and natural gas to be estimated. Previous estimates are sometimes revised as new information becomes available. Where it is determined that an exploratory project did not discover economically recoverable petroleum and natural gas, the costs are written-off as E&E expense.

If hydrocarbons are encountered, but further appraisal activity is required, the exploratory costs remain capitalized as long as sufficient progress is being made in assessing whether the recovery of the petroleum and natural gas is economically viable. The concept of "sufficient progress" is a judgmental area, and it is possible to have exploratory costs remain capitalized for several years while additional exploratory activities are carried out or the Company seeks government, regulatory or partner approval for development plans. E&E assets are subject to ongoing technical, commercial and Management review to confirm the continued intent to establish the technical feasibility and commercial viability of the discovery. When Management is making this assessment, changes to project economics, expected quantities of petroleum and natural gas, expected production techniques, drilling results, estimated capital expenditures and production costs, results of other operators in the region and access to infrastructure and potential infrastructure expansions are important factors. Where it is determined that an exploratory project is not economically viable, the costs are written-off as E&E expense.

Reserves Estimates

Reserves engineering is an inherently complex and subjective process of estimating underground accumulations of petroleum and natural gas. The process relies on judgments based on the interpretation of available geological, geophysical, engineering and production data. The accuracy of a reserves estimate is a function of the quality and quantity of available data, the interpretation of such data, the accuracy of various economic assumptions and the judgment of those preparing the estimate. Because these estimates depend on many assumptions, all of which may differ from actual results, reserves estimates, and estimates of future net revenue will be different from the sales volumes ultimately recovered and net revenues actually realized. Changes in market conditions, regulatory matters, the results of subsequent drilling, testing and production and other factors may result in revisions to the original estimates.

Estimates of reserves impact: (i) the assessment of whether a new well has found economically recoverable reserves; (ii) depletion rates; (iii) the estimated fair value of petroleum and natural gas properties acquired in a business combination; and (iv) the estimated recoverable amount of petroleum and natural gas properties used for the purposes of impairment and impairment reversal assessments, all of which could have a material impact on earnings.

Business Combinations

Management is required to exercise judgment in determining whether assets acquired and liabilities assumed constitute a business. A business consists of an integrated set of assets and activities, comprised of inputs and processes, that is capable of being conducted and managed as a business by a market participant.

Business combinations are accounted for using the acquisition method of accounting, whereby the net identifiable assets acquired are recorded at fair value. The fair value of individual assets is often required to be estimated, which may involve estimating the fair values of proved plus probable reserves, contingent resources, tangible assets, undeveloped land, intangible assets and other assets. These estimates incorporate assumptions using indicators of fair value, as determined by Management. Changes in any of the estimates or assumptions used in determining the fair value of the net identifiable assets acquired may impact the carrying values assigned to assets acquired and liabilities assumed and could have a material impact on earnings.

Estimates of Recoverable Amounts

Estimates of recoverable amounts used in impairment and impairment reversal assessments often incorporate level three fair value hierarchy inputs, including estimated volumes and future net revenues from proved plus probable reserves, contingent resource estimates, future net cash flow estimates related to other long-lived assets and internal and external market metrics used to estimate value based on comparable assets and transactions. By their nature, such estimates are subject to measurement uncertainty. Changes in such estimates, and differences between actual and estimated amounts, could have a material impact on earnings.

Determination of CGUs

The recoverability of the carrying value of petroleum and natural gas assets is generally assessed at the CGU level. The determination of the properties and other assets grouped within a particular CGU is based on Management's judgment with respect to the integration between assets, shared infrastructure and cash flows, the overall significance of individual properties and the manner in which Management monitors its operations and allocates capital. Changes in the assets comprising CGUs could have an impact on estimated recoverable amounts used in impairment assessments and could have a material impact on earnings.

Depletion

Depletion rates are determined based on Management's estimates of the expected usage pattern of the Company's petroleum and natural gas assets, including assumptions regarding future production volumes and the useful lives of production equipment and gathering systems.

Dissent Payment Entitlement

The Dissent Payment Entitlement is a financial instrument measured at amortized cost and was recorded based on the estimated fair value thereof on initial recognition. Management exercised judgment in estimating the fair value of the Dissent Payment Entitlement through the use of available market inputs and other assumptions. On initial recognition and at the end of each period Management assess the Dissent Payment Entitlement for any expected credit loss. Changes in estimates of the initial fair value and the expected credit loss could have a material impact on the Dissent Payment Entitlement asset and on comprehensive income.

Investments in Securities

The Company's investments in securities are accounted for as fair value through OCI financial assets. Management is required to exercise judgment in estimating the fair value of investments in the securities of corporations that are not publicly traded using the Company's assessment of available market inputs and other assumptions. Changes in estimates of fair value for such investments could have a material impact on comprehensive income.

Provisions

A provision is recognized where the Company has determined that it has a present obligation arising from past events and the settlement of the obligation is expected to result in an outflow of economic benefits. The determination of whether the Company has a present obligation arising from past events requires Management to exercise judgement as to the facts and circumstances of the event and the extent of any expected obligations of Paramount. Changes in facts and circumstances as a result of new information and other developments may impact Management's assessment of the Company's obligations, if any, in respect of such events. Changes in such estimates could have a material impact on Paramount's assets, liabilities, revenues, expenses and earnings.

Asset Retirement Obligations

Estimates of asset retirement costs are based on assumptions regarding the methods, timing, economic environment and regulatory standards that are expected to exist at the time assets are retired. Management also exercises judgment to determine the credit-adjusted risk-free discount rate at the end of each reporting period which may change in response to numerous market factors. The Company adjusts estimated amounts periodically as assumptions are updated to incorporate new information. The actual amount and timing of payments to settle the obligations may differ materially from estimates.

Share-Based Payments

The Company estimates the grant date value of stock options awarded using the Black-Scholes-Merton model. The inputs used to determine the estimated value of the options are based on assumptions regarding share price volatility, the expected life of the options, expected forfeiture rates and future interest rates. By their nature, these inputs are subject to measurement uncertainty and require Management to exercise judgment.

Income Taxes

Accounting for income taxes is a complex process requiring Management to interpret frequently changing laws and regulations and make judgments and estimates related to the application of tax law, the timing of temporary difference reversals and the likelihood of realizing deferred income tax assets. All tax filings are subject to subsequent government audits and potential reassessment. These interpretations and judgments, and changes related to them, impact current and deferred income tax provisions, the carrying value of deferred income tax assets and liabilities and could have a material impact on earnings.

PRODUCT TYPE INFORMATION

This MD&A includes references to sales volumes of "natural gas", "condensate and oil" and "Other NGLs" and revenues therefrom. "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. "Other NGLs" refers to ethane, propane and butane. Below is a complete breakdown of sales volumes for applicable periods by specific product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. Numbers may not add due to rounding.

	2020			2019				Annual
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1	2020	2019	2018
SALES VOLUMES -BY PRODUCT	TYPE
Shale gas (MMcf/d)	170.7	141.0	156.0	158.9	176.6	159.3	164.1	163.9	156.7	166.0	165.9
Conventional natural gas (MMcf/d)	85.6	83.0	97.2	102.6	122.4	137.3	145.6	144.1	92.0	137.3	160.0
Natural gas (MMcf/d)	256.3	224.0	253.2	261.5	299.0	296.6	309.7	308.0	248.7	303.3	325.9
Condensate (Bbl/d)	22,782	17,020	19,615	17,908	23,956	20,230	17,781	16,933		19,334 19,746	16,384
Other NGLs (Bbl/d)	4,987	3,952	3,817	4,539	7,064	6,851	6,859	6,284	4,325	6,767	7,386
NGLs (Bbl/d)	27,769	20,972	23,432	22,447	31,020	27,081	24,640	23,217		23,659 26,513	23,770
Tight oil (Bbl/d)	437	457	381	575	745	523	603	653	462	631	830
Light and Medium crude oil (Bbl/d)	2,533	2,305	2,827	3,416	3,815	4,008	4,928	6,093	2,768	4,703	7,024
Crude oil (Bbl/d)	2,970	2,762	3,208	3,991	4,560	4,531	5,531	6,746	3,230	5,334	7,854
Total (Boe/d)	73,460	61,064	68,839	70,022	85,411	81,046	81,793	81,296	68,340	82,394	85,941

SALES VOLUMES – BY REGION BY PRODUCT TYPE

GRANDE PRAIRIE REGION
Shale gas (MMcf/d)	92.7	66.0	76.8	73.1	91.5	70.5	73.4	76.7	77.2	78.0	65.5
Conventional natural gas (MMcf/d)	1.6	1.3	1.5	1.5	1.9	1.6	1.2	1.3	1.4	1.5	10.7
Natural gas (MMcf/d)	94.3	67.3	78.3	74.6	93.4	72.1	74.6	78.0	78.6	79.5	76.2
Condensate (Bbl/d)	19,635	13,959	16,292	14,058	18,760	14,269	11,678	10,883	15,991	13,920	11,342
Other NGLs (Bbl/d)	2,429	2,060	1,680	1,680	2,376	1,587	1,686	1,602	1,964	1,814	1,945
NGLs (Bbl/d)	22,064	16,019	17,972	15,738	21,136	15,856	13,364	12,485	17,955	15,734	13,287
Tight oil (Bbl/d)	–	–	–	–	–	–	–	–	–	–	–
Light and medium crude oil (Bbl/d)	–	1	17	39	91	61	13	46	14	53	77
Crude oil (Bbl/d)	–	1	17	39	91	61	13	46	14	53	77
Total (Boe/d)	37,782	27,237	31,039	28,214	36,789	27,927	25,804	25,530	31,076	29,040	26,059

KAYBOB REGION
Shale gas (MMcf/d)	41.9	40.4	44.4	48.6	48.3	52.4	51.6	49.1	43.8	50.3	59.4
Conventional natural gas (MMcf/d)	76.3	73.4	87.1	91.6	89.1	91.8	101.5	101.4	82.1	95.9	102.8
Natural gas (MMcf/d)	118.2	113.8	131.5	140.2	137.4	144.2	153.1	150.5	125.9	146.2	162.2
Condensate (Bbl/d)	2,631	2,577	2,954	3,385	3,899	4,411	4,526	4,618	2,885	4,361	3,519
Other NGLs (Bbl/d)	1,953	1,363	1,718	2,218	2,504	2,450	2,622	2,324	1,812	2,476	2,450
NGLs (Bbl/d)	4,584	3,940	4,672	5,603	6,403	6,861	7,148	6,942	4,697	6,837	5,969
Tight oil (Bbl/d)	299	308	203	394	541	329	286	280	301	360	439
Light and medium crude oil (Bbl/d)	2,480	2,257	2,762	3,343	3,331	3,391	4,182	4,835	2,709	3,929	5,565
Crude oil (Bbl/d)	2,779	2,565	2,965	3,737	3,872	3,720	4,468	5,115	3,010	4,289	6,004
Total (Boe/d)	27,056	25,477	29,561	32,700	33,167	34,615	37,127	37,143	28,685	35,500	39,004

	2020					2019				Annual
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1	2020	2019	2018
CENTRAL ALBERTA & OTHER REGION
Shale gas (MMcf/d)	36.1	34.6	34.8	37.1	36.8	36.4	39.1	38.1	35.7	37.7	41.0
Conventional natural gas (MMcf/d)	7.7	8.3	8.6	9.6	31.4	43.9	42.9	41.4	8.5	39.9	46.5
Natural gas (MMcf/d)	43.8	42.9	43.4	46.7	68.2	80.3	82.0	79.5	44.2	77.6	87.5
Condensate (Bbl/d)	515	484	369	465	1,298	1,551	1,577	1,433	458	1,464	1,522
Other NGLs (Bbl/d)	605	529	419	641	2,184	2,814	2,551	2,358	549	2,477	2,991
NGLs (Bbl/d)	1,120	1,013	788	1,106	3,482	4,365	4,128	3,791	1,007	3,941	4,513
Tight oil (Bbl/d)	138	149	178	180	203	194	317	373	161	271	391
Light and Medium crude oil (Bbl/d)	54	47	48	33	393	556	733	1,211	46	721	1,383
Crude oil (Bbl/d)	192	196	226	213	596	750	1,050	1,584	207	992	1,774
Total (Boe/d)	8,622	8,350	8,239	9,108	15,455	18,504	18,862	18,623	8,579	17,854	20,878

The Company forecasts that 2021 sales volumes will average between 77,000 Boe/d and 80,000 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). First half 2021 sales volumes are expected to average between 74,000 Boe/d and 76,000 Boe/d (57% shale gas and conventional natural gas combined, 37% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2021 sales volumes are expected to increase to average between 80,000 Boe/d and 84,000 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).

ADVISORIES

Forward-looking Information

Certain statements in this MD&A 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 document includes, but is not limited to:

planned capital expenditures in 2021 and the timing and allocation thereof;
forecast sales volumes for 2021 and certain periods therein;
forecast free cash flow in 2021;
planned exploration, development and production activities, including the expected timing of completing and bringing new wells on production;
planned facility outages and turnarounds;
planned abandonment and reclamation expenditures and activities in 2021 and anticipated funding under the ASRP;
the expectation that the Company will be able to fund budgeted capital expenditures and budgeted expenditures for abandonment and reclamation activities from cash from operating activities;
the anticipation that legal proceedings will not have a material impact on Paramount's financial position;
the expectation that the adoption of the amendments to IFRS described under "Updates to Accounting Policies - Future Changes in Accounting Standards" will not have a material impact on the Company's Consolidated Financial Statements; and
COVID-19 pandemic response measures and the potential impacts of the pandemic.

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 document:

future commodity prices and the potential impact of the COVID-19 pandemic thereon;
the likely impact of the COVID-19 pandemic on operations;
royalty rates, taxes and capital, operating, 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;
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 application of regulatory requirements respecting abandonment and reclamation;
the merits of outstanding and pending legal proceedings; and

• anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins and the construction, commissioning and start-up of new and expanded facilities).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this MD&A, 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:

those risks set out in this MD&A under "Risk Factors";
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;
changes in foreign currency exchange rates and interest rates;
the uncertainty of estimates and projections relating to future revenue, free cash flow, future production, reserves 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 sakes volumes, 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 adjusted funds flow 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, 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.

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, 2020, which is available on SEDAR at www.sedar.com. The forward-looking information contained in this document 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.

Non-GAAP Financial Measures

In this document, "Adjusted funds flow", "Free cash flow", "Netback", "Net debt", "Adjusted working capital" and "Total capital expenditures", collectively the "Non-GAAP Financial Measures", are used and do not have any standardized meanings as prescribed by IFRS.

"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, provision 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. Refer to the Consolidated Results section of this MD&A for the calculation thereof.

"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.

"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 Operating Results section of this MD&A 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 this MD&A for the calculation of "Net debt" and "Adjusted working capital".

"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 this MD&A for the calculation thereof.

The 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

The term "liquids" includes oil, condensate and Other NGLs (ethane, propane and butane). NGLs consist of condensate and Other NGLs.

Abbreviations

Liquids		Natural Gas
Bbl	Barrels	Mcf	Thousands of cubic feet
Bbl/d	Barrels per day	MMcf/d	Millions of cubic feet per day
NGLs	Natural gas liquids	GJ	Gigajoule
Condensate	Pentane and heavier hydrocarbons	GJ/d	Gigajouleper day
		MMbtu	Millions of British thermal units
		MMbtu/d	Millions of British thermal units per day
Oil Equivalent		WTI	NYMEX
Boe	Barrels of oil equivalent	AECO	AECO-C reference price
Boe/d	Barrels of oil equivalent per day

This MD&A 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 year ended December 31, 2020, the value ratio between crude oil and natural gas was approximately 21:1. 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.

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.

AI assistant

Paramount Resources Ltd. — Management Reports 2021

43230_rns_2021-03-03_25019f57-4a02-46c8-8798-a92124595ad4.PDF

ABOUT PARAMOUNT

NOTE REGARDING PRODUCT TYPES

FINANCIAL AND OPERATING HIGHLIGHTS (1)(2)

2020 OVERVIEW

PARAMOUNT'S CONTINUING RESPONSE TO THE COVID-19 PANDEMIC

2021 GUIDANCE

CONSOLIDATED RESULTS

Net Loss

Cash From Operating Activities

Adjusted Funds Flow (1)

OPERATING RESULTS

Netback (1)

Sales Volumes (1)

Commodity Prices

Financial Commodity Contracts

Royalties

Operating Expense

Transportation and NGLs Processing

Other Operating Items

DISSENT PAYMENT ENTITLEMENT

INVESTMENTS IN SECURITIES

ASSET RETIREMENT OBLIGATIONS

OTHER ASSETS

Fox Drilling

Cavalier Energy

CORPORATE

Tax Pools

PROPERTY, PLANT AND EQUIPMENT AND EXPLORATION EXPENDITURES

LIQUIDITY AND CAPITAL RESOURCES

Paramount Facility

Unsecured Letter of Credit Facility

Debentures

Cash Flow Hedges

Share Capital

FOURTH QUARTER RESULTS

Netback (1)

Sales Volumes (1)

Commodity Prices

Net Income (Loss)

Cash From Operating Activities

Adjusted Funds Flow (1)

Total Capital Expenditures by Region (1)

QUARTERLY INFORMATION

Significant Items Impacting Quarterly Results

OTHER INFORMATION

Contractual Obligations

Contingencies

Provision

NEW AND UPDATED ACCOUNTING POLICIES AND STANDARDS

Financial Instruments

Government Grants

Future Changes in Accounting Standards

DISCLOSURE CONTROLS AND PROCEDURES

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Changes in Internal Control Over Financial Reporting

RISK FACTORS

CRITICAL ACCOUNTING ESTIMATES

Exploration or Development

Exploration and Evaluation Projects

Reserves Estimates

Business Combinations

Estimates of Recoverable Amounts

Determination of CGUs

Depletion

Dissent Payment Entitlement

Investments in Securities

Provisions

Asset Retirement Obligations

Share-Based Payments

Income Taxes

PRODUCT TYPE INFORMATION

SALES VOLUMES – BY REGION BY PRODUCT TYPE

ADVISORIES

Forward-looking Information

Non-GAAP Financial Measures

Oil and Gas Measures and Definitions

Abbreviations

Paramount Resources Ltd. Management Reports 2021