Paramount Resources Ltd. announces Q1 2021 results, increased production guidance, preliminary 2022 guidance, fully funded Wapiti acceleration and $77 million non-core disposition

CALGARY, AB

HIGHLIGHTS

Sales volumes averaged 80,540 Boe/d (43% liquids) in the first quarter of 2021, well ahead of the Company’s first half 2021 production guidance of 74,000 Boe/d to 76,000 Boe/d (43% liquids) due to significant outperformance at Karr as well as higher than expected field reliability corporately. ^⁽¹⁾
- Sales volumes at Karr averaged 33,230 Boe/d (55% liquids) in the quarter compared to 26,914 Boe/d (56% liquids) in the fourth quarter of 2020.
  - This increase was driven by strong performance from the six well 3-10 pad that was brought onstream in February and the five well 5-16 West pad that was brought onstream in the fourth quarter of 2020, as well as workovers on the 16-4 pad that were completed in the fourth quarter of 2020.
  - Paramount achieved an important milestone at Karr, with first quarter exit sales volumes exceeding targeted plateau production of 40,000 Boe/d for the first time and March sales volumes averaging 39,938 Boe/d (53% liquids). Paramount estimates that 12 to 16 new wells per year will be required to maintain plateau production.
  - At plateau production of 40,000 Boe/d, annual asset level free cash flow at Karr would be $260 million to $290 million. ⁽²⁾
- Sales volumes at Wapiti averaged 14,107 Boe/d (62% liquids) in the quarter compared to 10,764 Boe/d (64% liquids) in the fourth quarter of 2020. The 31% increase in sales volumes was primarily due to new well production from the 5-3 West pad that was brought onstream partway through the fourth quarter.

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(1)	In this press release, “liquids” refers to NGLs (including condensate) and oil combined, “natural gas” refers to conventional natural gas and shale gas combined, “condensate and oil” refers to condensate, light and medium crude oil and tight oil combined and “other NGLs” refers to ethane, propane and butane combined. See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. See also “Oil and Gas Measures and Definitions” in the Advisories section.
(2)	“Asset level free cash flow” is a Non-GAAP financial measure. See “Non-GAAP Financial Measures” in the Advisories section. Stated amounts are illustrative assuming Karr per-unit netbacks of $26.00/Boe, consistent with the first quarter of 2021, and 12 to 16 new wells per year at an average DCET cost of $7.5 million per well and excludes the cost of any potential incremental infrastructure requirements in the future.

First quarter capital spending totaled $59.3 million, which was focused on drilling and completion activities at Karr and Wapiti.
- All-in lease construction, drilling, completion, equip and tie-in (collectively “DCET”) costs for the six well Karr 3-10 pad averaged a pacesetting $6.8 million per well, $0.2 million lower per well than prior estimates and representing a 12% reduction relative to average DCET costs for Karr wells in 2020.
- Preliminary DCET costs at the three well Karr 4-28 pad, which was brought on production in late April 2021, were $6.9 million per well.
Paramount’s continued focus on strong execution, cost control and innovation has contributed to anticipated cost savings of $30 million in the Company’s 2021 capital program.
Abandonment and reclamation expenditures in the first quarter totaled $8.4 million, net of $1.7 million in funding under the Alberta Site Rehabilitation Program. Activities included the abandonment of 120 wells, 119 of which were abandoned under the Company’s ongoing area-based closure program at Zama.
Cash from operating activities was $81.3 million in the first quarter. Adjusted funds flow was $90.9 million or $0.69 per share. ^⁽¹⁾
Paramount generated $23.2 million of free cash flow in the first quarter that, along with approximately $80 million in cash proceeds from non-core dispositions, was directed to debt reduction. ^⁽¹⁾
Free cash flow in 2021 is expected to be directed towards debt reduction, with anticipated year-end 2021 net debt to adjusted funds flow of less than 1.5x.⁽¹⁾

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(1)	“Adjusted funds flow”, “free cash flow” and “net debt to adjusted funds flow” are Non-GAAP financial measures. See “Non-GAAP Financial Measures” in the Advisories section.

NON-CORE ASSET DISPOSITION

Paramount has entered into a definitive agreement for the sale of its non-operated Birch asset in northeast British Columbia for total consideration of approximately $77 million (the “Birch Disposition”). Closing is subject to customary conditions and is anticipated to occur in early July. Estimated second half 2021 production from the asset, net to Paramount, was approximately 1,900 Boe/d.

REVISED 2021 GUIDANCE

Paramount is increasing its 2021 sales volume forecast as a result of strong year-to-date performance. Sales volumes in 2021 are now expected to average between 80,000 Boe/d and 82,000 Boe/d (44% liquids) after taking into account the Birch Disposition. This is an increase from previous guidance of 77,000 Boe/d to 80,000 Boe/d (45% liquids).

Second quarter 2021 sales volumes are expected to average between 77,000 Boe/d and 78,000 Boe/d (42% liquids). Second half 2021 sales volumes guidance remains unchanged at between 80,000 Boe/d and 84,000 Boe/d (45% liquids) notwithstanding the Birch Disposition.

The Company will be advancing approximately $60 million of activities in the Wapiti area by six months into the second half of 2021, capitalizing on the $30 million of anticipated cost savings in its 2021 capital program, incremental cash flow generation in light of higher production guidance and the Birch Disposition. Accordingly, the Company’s capital budget for 2021 is being increased to between $265 million and $285 million, excluding land acquisitions and abandonment and reclamation activities. This is an increase of $30 million at the mid-point from the previous guidance range of between $230 million and $260 million. Additional activities at Wapiti will include drilling, completing and bringing onstream the seven well 9-22 pad, the tie-in of a pre-existing well from the 10-22 pad and the installation of associated infrastructure. Initial production from these activities is anticipated to come onstream in December 2021.

Inclusive of the increased capital at Wapiti, Paramount forecasts 2021 free cash flow of approximately $140 million. This is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $39.50/Boe (US$60.84/Bbl WTI, US$2.84/MMBtu NYMEX, $2.78/GJ AECO), (iv) royalties of $2.60/Boe, (v) operating costs of $11.30/Boe and (vi) transportation and processing costs of $3.85/Boe.

Approximately 52% of forecast midpoint production is hedged over the final three quarters of 2021. After taking such hedging into account, 2021 forecast free cash flow would still be approximately $60 million at an average WTI oil price of US$40.00/Bbl over the final three quarters of the year and would rise to $155 million at an average WTI oil price of US$65.00/Bbl over the final three quarters of the year.

The Company targets net debt to adjusted funds flow of between 1.0x and 2.0x. Free cash flow in 2021 is expected to be directed towards debt reduction, with anticipated year-end net debt to adjusted funds flow of less than 1.5x. The Company currently prioritizes the allocation of free cash flow to: (i) achieving the targeted range of net debt to adjusted funds flow; (ii) shareholder returns; and (iii) incremental growth.

PRELIMINARY 2022 GUIDANCE

Paramount expects to finalize its 2022 capital budget and related guidance in the first quarter of 2022. Based on preliminary planning and current market conditions, Paramount anticipates 2022 capital spending, excluding land acquisitions and abandonment and reclamation activities, to range between $325 million and $385 million, broken down as follows:

$250 million of sustaining capital and maintenance activities;
$75 million of growth capital with production benefits in 2022; and
$60 million of discretionary growth capital with production benefits largely in 2023.

A capital program in this range would be expected to result in 2022 annual average sales volumes of between 84,000 Boe/d and 88,000 Boe/d (45% liquids) and free cash flow of approximately $185 million. The free cash flow estimate is based on the following assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $30 million in abandonment and reclamation costs, (iii) realized pricing of $37.25/Boe (US$57.78/Bbl WTI, US$2.71/MMBtu NYMEX, $2.43/GJ AECO), (iv) royalties of $2.35/Boe, (v) operating costs of $11.10/Boe and (vi) transportation and processing costs of $3.75/Boe. If all expected free cash flow was directed towards debt reduction, anticipated year-end 2022 net debt to adjusted funds flow would be significantly less than 1.0x.

CORPORATE

The Company successfully closed non-core asset dispositions for cash proceeds of approximately $80 million in the first quarter of 2021.

In May 2021, Moody’s Investors Service Inc. assigned a “B2” corporate family rating to the Company with a positive outlook and S&P Global Ratings assigned its “B-” issuer credit rating to the Company with a positive outlook.

Paramount continues to evaluate and pursue opportunities to provide environmentally sustainable value creation for its stakeholders. Advancements in technology paired with government incentive programs have the potential to create stakeholder benefits from both a greenhouse gas (“GHG”) emissions reduction and economic perspective.

The Company has engaged an outside engineering firm and is working with Clean Energy Systems, Inc. (“CES”) to assess the opportunity for ultra-low emission upgrades to one of the Company’s facilities. The project envisions deploying CES’s oxy-combustion technology with CO₂ capture to eliminate GHG emissions and generate excess electricity. The captured CO₂ could be used for enhanced oil recovery in a Paramount owned and operated oil development or sequestered using the facility’s existing H₂S and CO₂ disposal system. The CES technology also provides an opportunity to treat produced water that can be used in place of fresh water for Paramount’s future developments. Paramount has held an indirect ownership interest in CES (through its investment in Paxton Corporation) for over a decade and is excited about the prospects for this technology.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

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

	Q1 2021		Q4 2020		%Change
Sales volumes
Natural gas (MMcf/d)	122.6		94.3		30
Condensate and oil (Bbl/d)	23,974		19,635		22
Other NGLs (Bbl/d)	2,984		2,429		23
Total (Boe/d)	47,385		37,782		25
*% liquids*	57%		58%
Netback	($ millions)	($/Boe)	($ millions)	($/Boe)	% Change in $ millions
Petroleum and natural gas sales	194.0	45.50	125.1	36.00	55
Royalties	(11.6)	(2.72)	(6.2)	(1.78)	87
Operating expense	(49.0)	(11.49)	(42.4)	(12.20)	16
Transportation and NGLs processing	(20.0)	(4.69)	(14.2)	(4.07)	41
	113.4	26.60	62.3	17.95	82

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

KARR AREA

Karr sales volumes and netbacks are summarized below:

	Q1 2021		Q4 2020		% Change
Sales volumes
Natural gas (MMcf/d)	90.2		70.5		28
Condensate and oil (Bbl/d)	16,095		13,348		21
Other NGLs (Bbl/d)	2,108		1,817		16
Total (Boe/d)	33,230		26,914		23
*% liquids*	55%		56%
Netback	($ millions)	($/Boe)	($ millions)	($/Boe)	% Change in $ millions
Petroleum and natural gas sales	132.5	44.31	86.1	34.79	54
Royalties	(8.6)	(2.89)	(4.6)	(1.87)	87
Operating expense	(31.9)	(10.67)	(27.8)	(11.24)	15
Transportation and NGLs processing	(14.0)	(4.68)	(10.5)	(4.26)	33
	78.0	26.07	43.2	17.42	81

First quarter sales volumes at Karr averaged 33,230 Boe/d (55% liquids) compared to 26,914 Boe/d (56% liquids) in the fourth quarter of 2020. Sales volumes increased as a result of new well production that came onstream in the first quarter and from a full quarter of production from wells that came onstream in the fourth quarter of 2020. Incremental production from existing wells following workovers in the fourth quarter of 2020 also contributed to the overall increase.

The 3-10 pad has continued to outperform internal type well projections, averaging gross peak 30-day production per well of 2,068 Boe/d (6.0 MMcf/d of shale gas and 1,073 Bbl/d of NGLs) with an average CGR of 180 Bbl/MMcf.⁽¹⁾Likewise, production at the five well 5-16 West pad that came onstream in November 2020 continues to exhibit higher initial production rates than predicted by the type well. This performance, along with higher than anticipated production from the two well 16-4 pad, post-workover, combined to increase first quarter production above prior projections.

Three new Montney wells on the 4-28 pad were brought onstream in late April. Pressure data collected pre-completion from the pad confirms the northeast portion of Karr is in the over-pressured window of the Montney. This new data has resulted in an adjustment of the over-pressured boundary to the east of Karr and has increased the potential well inventory.

Additional gas lift compression was recently installed to support base and incremental production in the area. The Company anticipates base production up-lift at a number of pads that had been impacted by insufficient lift gas supply.

Per unit operating costs trended lower as a result of higher production volumes combined with a continued focus on cost reduction initiatives. The Company achieved per unit operating costs of $10.67/Boe in the first quarter of 2021 and anticipates operating costs of approximately $10.00/Boe at plateau production levels.

Paramount continues to focus on driving DCET costs lower while maintaining well performance and in the first quarter realized cost improvements relative to the most recent pacesetting results. All-in DCET costs at the six well 3-10 pad averaged a pacesetting $6.8 million per well, $0.2 million lower per well than prior estimates and representing a 12% reduction relative to average DCET costs for Karr wells in 2020. Preliminary DCET costs at the three well 4-28 pad averaged $6.9 million per well.

Drilling operations at the five well 7-18 pad were completed in the first quarter under budget and included one new pacesetter well, drilling an average 313 meters per day. Paramount plans to complete, tie-in and bring on production all five wells on the 7-18 pad by the third quarter. Drilling of the five well 5-16 East pad recently commenced, and the Company plans to complete, tie-in and bring on production all five wells by the fourth quarter. Paramount anticipates commencing drilling operations on the ten well 16-17 pad in the fourth quarter and expects that seven wells will be drilled by year end.

Production in the second quarter will be impacted by scheduled curtailments at the third-party Karr 6-18 facility related to inlet separation and liquids handling optimization. The curtailments are anticipated to reduce sales volumes by approximately 50% for seven days in May.

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(1)

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

WAPITI AREA

Wapiti sales volumes and netbacks are summarized below:

	Q1 2021		Q4 2020		% Change
Sales volumes
Natural gas (MMcf/d)	32.1		23.3		38
Condensate and oil (Bbl/d)	7,884		6,286		25
Other NGLs (Bbl/d)	867		589		47
Total (Boe/d)	14,107		10,764		31
*% liquids*	62%		64%
Netback	($ millions)	($/Boe)	($ millions)	($/Boe)	% Change in $ millions
Petroleum and natural gas sales	61.4	48.42	38.9	39.30	58
Royalties	(2.9)	(2.32)	(1.6)	(1.58)	81
Operating expense	(16.8)	(13.25)	(14.2)	(14.36)	18
Transportation and NGLs processing	(6.0)	(4.73)	(3.6)	(3.62)	67
	35.7	28.12	19.5	19.74	83

First quarter sales volumes at Wapiti averaged 14,107 Boe/d (62% liquids), 3,343 Boe/d higher than in the fourth quarter of 2020 primarily due to new well production from the 5-3 West pad that was brought onstream partway through the fourth quarter.

Drilling operations were completed at the seven well 6-4 pad in the first quarter, $4.4 million under budget for the pad. A pilot project to test the viability of monobore drilling techniques on two wells on the 6-4 pad was successful. Lower drilling and completion costs and higher frac fluid pumping rates in the wellbore compared to conventional multiple casing wellbores are anticipated to further enhance the economics and productivity of these wells. The Company anticipates completing and bringing on production all seven wells by the third quarter.

In the first quarter Paramount tied its Wapiti gas lift infrastructure into the high-pressure gas gathering system managed by the third-party operator of the Wapiti natural gas processing plant. This new connection provides Wapiti area wells with a more reliable source of lift gas which is anticipated to reduce the time required to re-start wells after turnarounds, workovers and other disruptions.

The 2021 capital program at Wapiti is being expanded to bring forward activities by approximately six months to advance the next major phase of development. Activities include drilling, completing and bringing onstream the seven well 9-22 pad, the tie-in of a pre-existing well from the 10-22 pad and the installation of associated infrastructure. Initial production from these activities is anticipated to come onstream in December 2021.

KAYBOB REGION

Kaybob Region sales volumes averaged 24,938 Boe/d (28% liquids) in the first quarter of 2021 compared to 27,056 Boe/d (27% liquids) in the fourth quarter of 2020. Production in the Kaybob Region was relatively flat after adjusting for the impact of non-core asset dispositions in the first quarter. The Company completed and recently brought on production one Montney oil well in Ante Creek that was drilled in 2020.

Paramount holds material positions in Duvernay and Montney resource plays in the Kaybob Region that will compete for capital in the medium term.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 8,217 Boe/d (14% liquids) in the first quarter compared to 8,622 (15% liquids) in the fourth quarter of 2020.

The Company holds a material, contiguous Duvernay position at Willesden Green and continues to actively evaluate longer-term full field development plans for this asset. Drilling operations are ongoing at a two well, liquids rich Duvernay pad in the Willesden Green area and Paramount plans to complete, tie-in and bring on production both wells in the second half of the year.

HEDGING

The Company’s commodity hedging position at March 31, 2021 is summarized below:

Natural Gas:April – December 2021                 60,000 MMBtu/d at US$2.71/MMBtu
April – October 2021                     50,000 GJ/d at CDN$2.52/GJ
April – December 2021                 50,000 GJ/d at CDN$2.51/GJ

Oil:April – June 2021                          23,000 Bbl/d at US$46.93/Bbl
July – September 2021                 15,000 Bbl/d at US$45.87/Bbl
October – December 2021            10,000 Bbl/d at US$45.82/Bbl
April – September 2021                3,000 Bbl/d at CDN$65.29/Bbl

The Company has also hedged the differential on 4,000 Bbl/d of condensate at Edmonton for the second quarter at WTI plus US$0.06/Bbl.

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

ABOUT PARAMOUNT

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

Paramount’s first quarter 2021 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at:
https://mma.prnewswire.com/media/1503692/Paramount_Resources_Ltd_Announces_Q1_2021_Results.pdf . A summary of historical financial and operating results is also available on Paramount’s website at http://www.paramountres.com/investor-relations/financial-reports#2021.

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

FINANCIAL AND OPERATING RESULTS ⁽¹⁾ ($ millions, except as noted)
	Q1 2021		Q4 2020
Net income (loss)	(82.5)		311.5
per share – basic and diluted ($/share)	(0.62)		2.35
Cash from operating activities	81.3		53.2
per share – basic and diluted ($/share)	0.61		0.40
Adjusted funds flow	90.9		67.9
per share – basic and diluted ($/share)	0.69		0.51
Total assets	3,583.1		3,497.0
Long-term debt	712.7		813.5
Net debt	761.7		854.1
Common shares outstanding (thousands)⁽²⁾	132,754		132,284

Sales volumes
Natural gas (MMcf/d)	273.1		256.3
Condensate and oil (Bbl/d)	29,854		25,752
Other NGLs (Bbl/d) ⁽³⁾	5,170		4,987
Total (Boe/d)	80,540		73,460
*% liquids*	43%		42%

Grande Prairie Region (Boe/d)	47,385		37,782
Kaybob Region (Boe/d)	24,938		27,056
Central Alberta and Other Region (Boe/d)	8,217		8,622
Total (Boe/d)	80,540		73,460

Netback		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾
Natural gas revenue	77.3	3.14	66.7	2.83
Condensate and oil revenue	185.9	69.20	123.3	52.03
Other NGLs revenue ⁽³⁾	15.0	32.29	9.5	20.61
Royalty and other revenue	1.7	─	2.5	─
Petroleum and natural gas sales	279.9	38.61	202.0	29.89
Royalties	(18.6)	(2.57)	(11.7)	(1.73)
Operating expense	(84.3)	(11.63)	(79.8)	(11.80)
Transportation and NGLs processing ⁽⁵⁾	(27.9)	(3.84)	(24.6)	(3.63)
Netback	149.1	20.57	85.9	12.73
Financial commodity contract settlements	(32.7)	(4.51)	7.9	1.18
Netback including financial commodity contract settlements	116.4	16.06	93.8	13.91
Total Capital Expenditures
Grande Prairie Region	51.3		64.3
Kaybob Region	5.0		1.8
Central Alberta and Other Region	1.2		0.8
Corporate ⁽⁶⁾	1.8		(1.8)
Total capital expenditures	59.3		65.1
Asset retirement obligation settlements	8.4		0.1

(1)									Readers are referred to the advisories concerning Non-GAAP Financial Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP financial measures: Adjusted funds flow, Net debt, Netback and Total capital expenditures. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product types.
(2)									Common shares are presented net of shares held in trust under the Company’s restricted share unit plan (000’s of common shares): Q1 2021: 1,914 and Q4 2020: 1,914.
(3)									Other NGLs means ethane, propane and butane.
(4)									Natural gas revenue presented as $/Mcf.
(5)									Includes downstream transportation costs and NGLs fractionation costs.
(6)									Includes transfers between regions.

PRODUCT TYPE INFORMATION

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


	Total		Grande Prairie Region		Kabob Region		Central Alberta and Other Region
	Q1 2021	Q4 2020	Q1 2021	Q4 2020	Q1 2021	Q4 2020	Q1 2021	Q4 2020
Shale gas (MMcf/d)	197.8	170.7	120.6	92.7	42.1	41.9	35.1	36.1
Conventional natural gas (MMcf/d)	75.3	85.6	2.0	1.6	65.8	76.3	7.5	7.7
Natural gas (MMcf/d)	273.1	256.3	122.6	94.3	107.9	118.2	42.6	43.8
Condensate (Bbl/d)	27,017	22,782	23,974	19,635	2,611	2,631	433	515
Other NGLs (Bbl/d)	5,170	4,987	2,984	2,429	1,677	1,953	509	605
NGLs (Bbl/d)	32,187	27,769	26,958	22,064	4,288	4,584	942	1,120
Tight oil (Bbl/d)	479	437	–	–	342	299	136	138
Light and Medium crude oil (Bbl/d)	2,358	2,533	–	–	2,321	2,480	37	54
Crude oil (Bbl/d)	2,837	2,970	–	–	2,663	2,779	173	192
Total (Boe/d)	80,540	73,460	47,385	37,782	24,938	27,056	8,217	8,622

	Karr		Wapiti
	Q1 2021	Q4 2020	Q1 2021	Q4 2020
Shale gas (MMcf/d)	89.1	69.6	31.5	22.8
Conventional natural gas (MMcf/d)	1.1	0.9	0.6	0.5
Natural gas (MMcf/d)	90.2	70.5	32.1	23.3
NGLs (Bbl/d)	18,203	15,165	8,751	6,875
Total (Boe/d)	33,230	26,914	14,107	10,764

The Company forecasts that 2021 sales volumes will average between 80,000 Boe/d and 82,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second quarter 2021 sales volumes are expected to average between 77,000 Boe/d and 78,000 Boe/d (58% shale gas and conventional natural gas combined, 36% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2021 sales volumes are expected to average between 80,000 Boe/d and 84,000 Boe/d (55% shale gas and conventional natural gas combined, 39% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).

Advisories & Contact

ADVISORIES

Forward-looking Information

Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “estimate”, “will”, “expect”, “plan”, “schedule”, “intend”, “propose”, or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:

the estimated number of wells required per year to maintain plateau production at Karr;
illustrative asset level free cash flow at Karr at plateau production;
anticipated cost savings in the Company’s 2021 capital program;
the anticipated closing of the Birch Disposition;
forecast sales volumes for 2021 and certain periods therein;
forecast free cash flow in 2021;
planned capital expenditures in 2021;
planned abandonment and reclamation expenditures in 2021;
the Company’s expectation that 2021 free cash flow will be directed towards debt reduction;
forecast 2021 year-end net debt to annual adjusted funds flow;
preliminary anticipated capital expenditures in 2022 and the resulting expected 2022 average sales volumes, free cash flow and year-end net debt to adjusted funds flow;
planned exploration, development and production activities, including the expected timing of completing and bringing new wells on production;
scheduled facility curtailments at Karr and the anticipated impact thereof;
anticipated operating costs;
the expected benefits of monobore drilling techniques; and
the expected benefits of additional gas lift compression at Karr and new gas lift infrastructure at Wapiti.

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

future commodity prices and the potential impact of the COVID-19 pandemic thereon;
the likely impact of the COVID-19 pandemic on operations;
the satisfaction of the conditions to closing of the Birch Disposition;
the ability to realize expected cost savings;
royalty rates, taxes and capital, operating, processing, transportation, general & administrative and other costs;
foreign currency exchange rates and interest rates;
general business, economic and market conditions;
the ability of Paramount to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations;
the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities;
the ability of Paramount to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
the ability of Paramount to market its production successfully to current and new customers;
the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
the timely receipt of required governmental and regulatory approvals;
the receipt of benefits under government programs;
the application of regulatory requirements respecting abandonment and reclamation; and
anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. There are no assurances that the Birch Disposition will close at the anticipated time or at all. Forward-looking information is based on expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information. The material risks and uncertainties include, but are not limited to:

fluctuations in commodity prices, including in relation to the impact of the COVID-19 pandemic;
the failure to satisfy the conditions to closing of the Birch Disposition;
changes in capital spending plans and planned exploration and development activities;
the potential for changes to preliminary anticipated 2022 capital expenditures prior to finalization and changes to the resulting expected 2022 average sales volumes, free cash flow and year-end net debt to adjusted funds flow;
changes in foreign currency exchange rates and interest rates;
the uncertainty of estimates and projections relating to future revenue, free cash flow, production, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
the ability to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms;
operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost;
potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);
processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
risks and uncertainties involving the geology of oil and gas deposits;
the uncertainty of reserves estimates;
general business, economic and market conditions;
the ability to generate sufficient cash from operating activities and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations);
changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
the ability to obtain required governmental or regulatory approvals in a timely manner, and to enter into and maintain leases and licenses;
the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders;
the outcome of existing and potential lawsuits, insurance claims, regulatory actions, audits and assessments; and
other risks and uncertainties described elsewhere in this document and in Paramount’s other filings with Canadian securities authorities.

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

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

Non-GAAP Financial Measures

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

“Adjusted funds flow” refers to cash from operating activities before net changes in non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements and provision. Adjusted funds flow is used to assist management and investors in measuring the Company’s ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company. Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary significantly from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as being an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS. The following are the calculations of adjusted funds flow from the nearest GAAP measure for the three months ended March 31, 2021 and December 31, 2020:

Three months ended	March 31, 2021 (MM$)	Dec 31, 2020 (MM$)
Cash from operating activities	81.3	53.2
Change in non-cash working capital	(7.9)	12.5
Geological and geophysical expenses	1.6	2.1
Asset retirement obligations settled	8.4	0.1
Provision	7.5	–
Adjusted funds flow	90.9	67.9

“Asset level free cash flow” refers to aggregate netback from an asset during the period less capital expenditures with respect to such asset for the period. Asset level free cash flow is used by management and investors to assess the cash generating capacity of an asset.

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

Three months ended			March 31, 2021 (MM$)
Cash from operating activities			81.3
Change in non-cash working capital			(7.9)
Geological and geophysical expenses			1.6
Asset retirement obligations settled			8.4
Provision			7.5
Adjusted funds flow			90.9
Total capital expenditures			(59.3)
Asset retirement obligation settlements			(8.4)
Free cash flow			23.2

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

“Net debt” is a measure of the Company’s overall debt position after adjusting for certain working capital and other amounts and is used by management to assess the Company’s overall leverage position. Refer to the Liquidity and Capital Resources section of the Company’s Management’s Discussion and Analysis for the three months ended March 31, 2021 (the “MD&A”) for the calculation of net debt.

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

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

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

Oil and Gas Measures and Definitions

Abbreviations

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

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

This press release contains disclosures expressed as “Boe”, “$/Boe” and “Boe/d”. Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2021, the value ratio between crude oil and natural gas was approximately 25:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

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

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.