NIKL Sprott Nickel Miners ETF

Pieridae Energy Limited (“Pieridae” or the “Company”) (PEA.TO) announces the release of its fourth quarter and full year 2022 financial and operating results and year end 2022 reserves. Pieridae generated Net Operating Income (“NOI”)1 of $201 million and made term debt principal repayments totalling $48 million during 2022.

In addition, the Company filed its Annual Information Form ("AIF") for the year ended December 31, 2022 containing Pieridae's 2022 independent oil and natural reserves evaluation as required under National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities (“NI51-101”). Pieridae’s 2022 NI51-101 reserve report is highlighted by an 89% increase in Proved Developed Producing (“PDP”) PV10 value to $807 million and 52% increase in Total Proved plus Probable (“TPP”) PV10 value to $1,526 million.

Pieridae’s AIF, management’s discussion and analysis (“MD&A”) and audited consolidated financial statements and notes for the year ended December 31, 2022 are available at www.pieridaeenergy.com and on SEDAR at www.sedar.com.

HIGHLIGHTS

Q4 2022

• Generated record quarterly NOI1 of $67.7 million ($0.43 per basic and $0.42 per fully diluted share) up 120% from $30.8 million ($0.20 per basic and fully diluted share) in Q4 2021, as a result of strong natural gas and natural gas liquids (“NGL”) prices;
• Generated Funds Flow from Operations1 of $57.6 million ($0.36 per basic and $0.35 per fully diluted share), up 365% from $12.4 million ($0.08 per basic and fully diluted share) in Q4 2021;
• Generated Net income of $114.7 million ($0.72 per basic and $0.70 per fully diluted share), compared to $4.7 million ($0.03 per basic and fully diluted share) in Q4 2021;
• Produced 34,715 boe/d (86% natural gas) down 16% from 41,304 boe/d in 2021, due primarily to the previously discussed re-injection of ethane volumes into the natural gas sales stream and an unplanned outage at the Caroline gas plant in Central Alberta, which has subsequently been repaired;
• Repaid $10.7 million of the senior secured term loan (including the net impact of interest paid in kind “PIK”), reducing the amount due at maturity to $217.1 million2 at year end; and
• Commenced winter drilling program in October, spudding the Company’s first Foothills well (02/6-35-44-18W5, “6-35”) targeting the Ostracod formation in the Brown Creek area of Central Alberta.

Full Year 2022

• Generated Record annual NOI1 of $201.0 million ($1.27 per basic and $1.25 per fully diluted share) up 139% from $84.1 million ($0.53 per basic and fully diluted share) in 2021, primarily as a result of strong natural gas and NGL prices;
• Generated Funds Flow from Operations1 of $153.7 million ($0.97 per basic and $0.95 per fully diluted share), up 658% from $20.3 million ($0.13 per basic and fully diluted share) in 2021;
• Generated Net income of $146.7 million ($0.93 per basic and $0.91 per fully diluted share), compared to a net loss of $39.8 million (-$0.25 per basic and fully diluted share) in 2021;
• Produced 36,868 boe/d (82% natural gas) down 9% from 40,562 boe/d in 2021, due to the previously discussed re-injection of ethane volumes into the natural gas sales stream and natural production declines;
• Reduced term debt principal by $48.3 million (including the net impact of PIK) during 2022 and reduced the adjusted working capital deficit3 by $50.3 million during 2022, primarily through reduction in accounts payable which totaled $22.6 million at year end 2022 compared to $74.7 million at year end 2021;
• Recorded 2022 NI51-101 PDP reserves of 126.8 MMboe, down 3% from 131.3 MMboe at year end 2021 with year over year increase of 89% in PDP PV10 reserve value to $807 million at January 1, 2023 evaluator consensus (“IC4”) pricing; and
• Recorded 2022 NI51-101 TPP reserves of 289.1 MMboe, up 7% from 269.2 MMboe at year end 2021 with year over year increase of 52% in TPP PV10 reserve value to $1,526 million at January 1, 2023 IC4 pricing.

Subsequent to Year End

• Repaid an additional $27 million of term debt.
• Completed drilling our first Brown Creek well (6-35) in Central Alberta in February 2023. The well was completed and temporarily tied-in to existing production infrastructure in March 2023 and is currently being flow-tested with production sold into the TC Energy (NGTL) sales gas system. After flowing continuously for 90.5 hours on test, this 100% working interest well was producing sweet natural gas through 60.3mm production tubing at a downhole-choked flow rate of 6.8 MMcf/d and a restricted flowing wellhead tubing pressure of 11.1 MPa (corresponding shut-in casing pressure of 17.1 MPa). At the conclusion of the anticipated 7-day flow test, 6-35 will be shut-in for an extended pressure build-up, during which the well will be permanently tied-in to the existing on-lease gas gathering system.
• Drilling also commenced on a second Brown Creek well in February 2023, with completion expected by April 2023; and
• Terminated the previously announced NE BC disposition transaction as the purchaser failed to meet the required closing conditions, following multiple extensions. The Company has retained a non-refundable deposit and will continue to market the NE BC property.

“Pieridae put up a very good result in the fourth quarter, punctuating a transformational year for the Company,” said Pieridae’s Chief Executive Officer, Alfred Sorensen. “Strong gas and liquids pricing drove record funds flow in Q4, offsetting lower production, due in part, to an unplanned outage at our Caroline plant which the team has since repaired. 2022 saw the Company commence drilling our extensive inventory of high-impact Foothills development locations and make progress on our path to de-levering the balance sheet, all while operating our assets in a safe, responsible and effective manner. Our disciplined hedging strategy continues to mitigate commodity price volatility and is offsetting the impact of lower AECO gas prices through the first quarter of 2023. I’d like to thank all Pieridae shareholders, lenders, employees and the communities in which we operate, for their ongoing interest and support.”

1 Refer to the “non-GAAP measures” section of the Company’s 2022 MD&A.2 Includes the $50 million non interest-bearing deferred fee due at maturity, A portion of this fee, closing fees and other amounts remain to be accreted to the term debt value. 3 Adjusted working capital is calculated as accounts payable and accrued liabilities, less cash and cash equivalents, restricted cash, accounts receivable, prepaids and deposits.

SELECTED Q4 AND ANNUAL 2022 OPERATIONAL & FINANCIAL RESULTS

	2022								2021
($ 000s unless otherwise noted)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Production
Natural gas (mcf/d)	179,143		181,030		178,918		187,719		198,596		191,439		194,232		215,179
Condensate (bbl/d)	2,469		2,911		2,864		3,201		2,851		2,555		2,950		3,158
NGLs (bbl/d)	2,389		2,876		3,695		6,003		5,354		4,133		3,083		4,975
Sulphur (tonne/d)	1,348		1,312		1,555		1,625		1,185		1,518		1,710		1,713
Total production (boe/d)	34,715		35,959		36,378		40,491		41,304		38,595		38,404		43,997
Financial
Realized natural gas price before physical commodity contracts $/mcf)	5.08		4.38		7.13		4.66		4.62		3.58		3.10		3.12
Realized natural gas price after physical commodity contracts ($/mcf)	5.24		3.62		4.67		4.08		3.67		2.70		2.59		2.63
Benchmark natural gas price ($/mcf)	5.20		4.28		7.22		4.75		4.69		3.59		3.11		3.16
Realized condensate price before physical commodity contracts ($/bbl)	110.24		103.71		132.60		112.09		91.69		85.25		76.72		68.85
Realized condensate price after physical commodity contracts ($/bbl)	117.67		105.82		116.61		106.13		69.71		65.33		68.08		58.40
Benchmark condensate price ($/bbl)	115.24		115.66		132.49		122.62		100.10		70.25		64.82		59.05
Net income (loss)	114,662		(1,573	)	22,982		10,549		4,661		(14,846	)	(10,058	)	(19,547	)
Net income (loss) $ per share, basic	0.72		(0.01	)	0.15		0.07		0.03		(0.09	)	(0.06	)	(0.12	)
Net income (loss) $ per share, diluted	0.70		(0.01	)	0.14		0.07		0.03		(0.09	)	(0.06	)	(0.12	)
Net operating income (1)	67,711		30,014		55,969		47,295		30,845		17,920		14,444		20,876
Cashflow provided by operating activities	40,134		9,899		34,922		3,212		21,139		6,885		12,093		11,000
Funds flow from operations (1)	57,641		17,721		43,462		34,855		12,408		6,780		(6,366	)	7,462
Total assets	615,477		473,642		499,580		552,781		622,540		560,782		575,690		557,696
Adjusted working capital deficit (2)	(11,249	)	(46,419	)	(28,892	)	(34,934	)	(61,588	)	(71,161	)	(65,977	)	(46,033	)
Net debt (1)	(214,503	)	(254,489	)	(248,967	)	(273,201	)	(293,169	)	(314,184	)	(298,360	)	(270,904	)
Capital expenditures	19,037		7,216		9,739		3,534		1,493		9,852		17,959		5,668
Development expenses (LNG project)	(4,514	)	-		-		-		225		783		(4,862	)	8,604
(1)   Refer to the “Net Operation Income”, “Capital Resources” and “non-GAAP measures” sections of the MD&A for reference to non-GAAP measures.(2)   Adjusted working capital is a non-GAAP measure and is calculated as accounts payable and accrued liabilities, less cash and cash equivalents, restricted cash, accounts receivable, prepaids and deposits.

($ 000s unless otherwise noted)	2022		2021		2020
Production
Natural gas (mcf/d)	181,677		199,793		201,040
Condensate (bbl/d)	2,860		2,877		3,020
NGLs (bbl/d)	3,729		4,386		5,473
Sulphur (tonne/d)	1,459		1,530		1,985
Total production (boe/d) (1)	36,868		40,562		42,000
Reserves
Net proved plus probable (“TPP”) reserves NPV10 (2)	1,525,930		1,002,134		976,147
Financial
Realized natural gas price before physical commodity contracts ($/mcf)	5.30		3.60		2.25
Realized natural gas price after physical commodity contracts ($/mcf)	4.40		2.90		2.00
Benchmark natural gas price ($/mcf)	5.36		3.63		2.26
Realized condensate price before physical commodity contracts ($/bbl)	114.66		80.24		37.54
Realized condensate price after physical commodity contracts ($/bbl)	111.18		63.21		51.24
Benchmark condensate price ($/bbl)	121.46		85.95		50.17
Net income (loss)	146,620		(39,790	)	(100,693	)
Net income (loss) $ per share basic	0.93		(0.25	)	(0.64	)
Net income (loss) $ per share diluted	0.91		(0.25	)	(0.64	)
Net operating income (3)	200,989		84,085		50,723
Cashflow provided by operating activities	88,167		51,117		2,234
Funds flow from operations (3)	153,679		20,284		7,374
Total assets	615,477		622,540		612,651
Adjusted working capital deficit (4)	(11,249	)	(61,588	)	(37,031	)
Net debt (3)	(214,503	)	(293,169	)	(256,586	)
Capital expenditures	39,526		34,972		17,243
Development expenses (Goldboro LNG project)	(4,514	)	4,750		18,742

(1)  Total production excludes sulphur.(2)  Estimated pre-tax net present value of discounted cash flows from reserves using a 10% discount rate.(3)  Refer to the “Net Operation Income”, “Capital Resources” and “non-GAAP measures” sections of the MD&A for reference to non-GAAP measures. (4)  Adjusted working capital is a non-GAAP measure and is calculated as accounts payable and accrued liabilities, less cash and cash equivalents, restricted cash, accounts receivable, prepaids and deposits.

PRODUCTION

	Three months ended December 31				Year ended December 31
	2022	2021	% Change		2022	2021	% Change
Natural gas (mcf/d)	179,143	198,596	(10	)	181,677	199,793	(9	)
Condensate (bbl/d)	2,469	2,851	(13	)	2,860	2,877	(1	)
NGLs (bbl/d)	2,389	5,354	(55	)	3,729	4,386	(15	)
Sulphur (tonne/d) (1)	1,348	1,185	14		1,459	1,530	(5	)
Total production (boe/d)	34,715	41,304	(16	)	36,868	40,562	(9	)

(1)   Total production excludes sulphur.Production in the fourth quarter of 2022 decreased 16% compared to Q4 2021 due in part to a December unplanned shut-in required to complete sulphur condenser repairs at the Company’s Caroline gas processing facility which suffered an upset in its sulphur recovery unit (2,500 boe/d). Other factors impacting fourth quarter production included pipeline inspections (680 boe/d), unseasonably cold weather which caused freeze-ups and run time restrictions at gas plants (1,500 boe/d) and ongoing ethane reinjection into the natural gas sales stream (1,900 boe/d). During 2022, average production decreased 9% compared to 2021 as a result of ethane reinjection and natural production declines.

OPERATING NETBACK

	Three months ended December 31						Year ended December 31
($ per boe)	2022		2021		% Change		2022		2021		% Change
Revenue before physical commodity contracts	38.69		33.53		15		40.98		27.28		50
Gain (loss) on physical commodity contracts	1.33		(6.04	)	122		(4.72	)	(4.67	)	1
Third party processing and other income	2.99		0.88		240		2.32		1.25		86
Revenue	43.01		28.37		52		38.58		23.86		62
Royalties	(3.73	)	(4.65	)	(20	)	(5.61	)	(2.12	)	165
Operating	(16.24	)	(14.17	)	15		(16.32	)	(14.77	)	10
Transportation	(1.83	)	(1.42	)	29		(1.71	)	(1.29	)	33
Netback ($/boe) (1)	21.21		8.13		161		14.94		5.68		163

(1) Netback per boe is a “non-GAAP measure”. Management considers operating netback an important measure to evaluate the Company’s operational performance as it demonstrates Pieridae’s field level profitability relative to current commodity prices. Operating netback equals revenue less royalties, operating expenses and transportation expenses calculated on a per BOE basis.

2022 RESERVES

Deloitte Touche Tohmatsu Limited (“Deloitte”), Pieridae’s independent, qualified reserves evaluator, performed reserves evaluations of the Company’s assets as at December 31, 2022, and December 31, 2021. The following table summarizes Pieridae’s reserves based on the Deloitte NI51-101 reserve report using the January 1, 2023 IC4 price forecast:

	Year ended December 31				Year ended December 31
	MMboe				$000, NPV10(1)
	2022	2021	% Change		2022	2021	% Change
Reserves Category (2)
Net proved developed producing (“PDP”) reserves	126.8	131.3	(3	)	806,872	427,675	89
Net proved (“1P”) reserves	208.7	202.6	3		1,223,438	752,202	63
Net proved plus probable (“TPP”) reserves	289.1	269.2	7		1,525,930	1,002,134	52

(1)   Estimated pre-tax net present value of discounted cash flows from reserves using a 10% discount rate.(2)   Net reserves reflect working interest share of the asset prior to the deduction of royalties.

				Year ended December 31
				2022		2021		% Change
Reserve replacement ratio (“TPP”) reserves				249	%	295	%	(16	)
Reserve life index (“TPP”) reserves				19.8		17.7		12

The following table outlines the primary drivers of reserve changes during 2022, as at December 31, 2022:

	Light & Medium Oil					Conventional Gas					Natural Gas Liquids
	Proved		Probable	Proved + Probable		Proved		Probable	Proved + Probable		Proved		Probable		Proved + Probable
	Mstb		Mstb	Mstb		MMcf		MMcf	MMcf		Mstb		Mstb		Mstb
Opening Balance	-		-			942,596		306,055	1,248,651		45,528		15,583		61,111
Production	(2	)	-	(2	)	(66,382	)		(66,382	)	(2,390	)			(2,390	)
Technical Revisions	1.8		0.1	1.9		3,626		35,045	38,672		(15,806	)	(4,678	)	(20,483	)
Extensions	1		-	1		22,971		9,695	32,666		2		1		3
Acquisitions	-		-	-		-		-	-		-		-		-
Economic Factors	1		-	1		127,734		55,082	182,816		9,579		1,849		11,428
Closing Balance	-		-	-		1,030,545		405,877	1,436,423		36,913		12,755		49,669

Refer to the Company’s AIF for the year ended December 31, 2022, for detailed information on the Company’s 2022 reserves.

HEDGE POSITION

The Company continues to execute a commodity price risk management program governed by its hedge policy.

The Company had the following fixed price physical commodity sales contracts and power purchase contracts in place at December 31, 2022:

Type of contract	Quantity	Time Period	Contract Price
Fixed Price - Natural Gas Sales	127,267 GJ/d	Jan – Mar 2023	CAD $5.78/GJ
Fixed Price - Natural Gas Sales	45,000 GJ/d	Apr – Sep 2023	CAD $4.49/GJ
Fixed Price - Natural Gas Sales	15,163 GJ/d	Oct – Dec 2023	CAD $4.49/GJ
Fixed Price - Condensate Sales	700 Bbl/d	Jan – Sep 2023	CAD $103.24/Bbl
Fixed Price - Condensate Sales (WTI Basis)	1,000 Bbl/d	Oct 2023 – Jun 2024	CAD $97.48/Bbl
Fixed price - Power Purchases	53 MW/h	Jan 2023 – Dec 2023	CAD $71.93/MWh
Fixed price - Power Purchases	53 MW/h	Jan 2024 – Dec 2024	CAD $68.38/MWh
Fixed price - Power Purchases	35 MW/h	Jan 2025 – Dec 2025	CAD $79.71/MWh

The Company had the following financial risk management contracts in place as at December 31, 2022:

Type of contract	Quantity	Time Period	Contract Price
AECO Natural Gas Swap	2,500 GJ/d	Jan – Mar 2023	CAD $5.54/GJ
AECO Natural Gas Swap	2,500 GJ/d	Apr – Jun 2023	CAD $3.94/GJ
C5 Differential (to WTI)	500 Bbl/d	Jan – Sep 2023	CAD -$4.67/Bbl
WTI Swap	500 Bbl/d	Jan – Sep 2023	CAD $107.64/Bbl

Pieridae will continue to hedge to mitigate commodity price volatility and protect the cash flow required to fund the Company’s facility maintenance capital requirements, debt service obligations and capital development program while allowing the Company to participate in future commodity price upside.

2023 OUTLOOK AND REVISED GUIDANCE

North American natural gas prices have sharply fallen off during the first quarter of 2023 as a result of the warmer than expected winter, high storage levels and constrained North American natural gas export capacity. AECO prices have averaged $3.13/GJ year to date in 2023, compared to $4.93/GJ in the fourth quarter of 2022. This price shock is largely mitigated during the first quarter by the Company’s natural gas hedges (129,767 GJ/d protected at $5.78/GJ). However, if depressed AECO prices continue or fall further as we enter the summer, 2023 NOI and funds flow from operations will be materially impacted.

As a result, management has revised annual NOI and netback guidance to reflect a lower commodity price forecast for the remainder of the year and is planning to defer certain expenditures into 2024, including investigating deferral of the maintenance turnaround at Waterton, which has been reflected in this revised guidance.

($ 000s unless otherwise noted)	Revised 2023 Guidance				Previous 2023 Guidance
	Low		High		Low		High
Total production (boe/d)		37,000		39,000		37,000		39,000
Net operating income (1)(2)	$120,000		$150,000		$170,000		$200,000
Implied operating netback ($/boe) (2)	$9.00		$11.00		$12.00		$14.00
Sustaining capital expenditures (3)	$15,000		$20,000		$50,000		$55,000
Development capital expenditures (4)	$15,000		$20,000		$15,000		$20,000

(1)   Refer to the “Net Operating Income” section of the Company’s MD&A for reference to non-GAAP measures.(2)   2022 outlook assumes average 2023 AECO price of $2.85/GJ and average 2023 WTI price of USD$74.75/bbl and accounts for fixed price forward commodity sales contracts as of February 28, 2023(3)   Comprised of facility maintenance and turnaround capital expenditures(4)   Comprised of seismic, development and land capital expenditures

Pieridae’s priority remains improving financial flexibility by strengthening the balance sheet while sustaining production, implementing cost control initiatives, optimizing infrastructure logistics and executing non-core asset dispositions.

CONFERENCE CALL DETAILS

A conference call to discuss the results will be held on on Wednesday, March 22, 2023, at 8:30 a.m. MDT / 10:30 a.m. EDT. To participate in the conference webcast or call, you are asked to register using one of the links provided below. Details regarding the webcast or call will be provided to you upon registration.

To register to participate via webcast please follow this link:https://edge.media-server.com/mmc/p/5usc6dvg

Alternatively, to register to participate by telephone please follow this link:https://register.vevent.com/register/BI8349a830b15f45f3ac8a1e0ace15538b

ABOUT PIERIDAEPieridae is a Canadian energy company headquartered in Calgary, Alberta. Through a number of corporate and asset acquisitions, we have grown into a significant upstream and midstream producer with assets concentrated in the Canadian Foothills, producing conventional natural gas, NGLs, condensate and sulphur. Pieridae provides the energy to fuel people’s daily lives while supporting the environment and the transition to a lower-carbon economy. Pieridae’s common shares trade on the TSX under the symbol “PEA”.

For further information, visit www.pieridaeenergy.com, or please contact:

Alfred Sorensen, Chief Executive Officer	Adam Gray, Chief Financial Officer
Telephone: (403) 261-5900	Telephone: (403) 261-5900

Investor Relationsinvestors@pieridaeenergy.com

Forward-Looking StatementsCertain statements contained herein may constitute "forward-looking statements" or "forward-looking information" within the meaning of applicable securities laws (collectively "forward-looking statements"). Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue", "shall", "estimate", "expect", "propose", "might", "project", "predict", "forecast" and similar expressions may be used to identify these forward-looking statements.

Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements including, but not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of resources estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits or synergies from acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and the risk factors outlined under "Risk Factors" and elsewhere herein. The recovery and resources estimate of Pieridae's reserves provided herein are estimates only and there is no guarantee that the estimated resources will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Forward-looking statements are based on a number of factors and assumptions which have been used to develop such forward-looking statements, but which may prove to be incorrect. Although Pieridae believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements because Pieridae can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Pieridae operates; the timely receipt of any required regulatory approvals; the ability of Pieridae to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which Pieridae has an interest in, to operate the field in a safe, efficient and effective manner; the ability of Pieridae to obtain financing on acceptable terms; the ability to replace and expand oil and natural gas resources through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of Pieridae to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Pieridae operates; timing and amount of capital expenditures, future sources of funding, production levels, weather conditions, success of exploration and development activities, access to gathering, processing and pipeline systems, advancing technologies, and the ability of Pieridae to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Pieridae's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), and at Pieridae's website (www.pieridaeenergy.com). Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with these forward-looking statements. Investors should not place undue reliance on forward-looking statements. These forward-looking statements are made as of the date hereof and Pieridae assumes no obligation to update or review them to reflect new events or circumstances except as required by Applicable Securities Laws.

Forward-looking statements contained herein concerning the oil and gas industry and Pieridae's general expectations concerning this industry are based on estimates prepared by management using data from publicly available industry sources as well as from reserve reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which Pieridae believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While Pieridae is not aware of any misstatements regarding any industry data presented herein, the industry involves risks and uncertainties and is subject to change based on various factors.

Additional Reader AdvisoriesBarrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Abbreviations

Natural Gas		Oil
mcf	thousand cubic feet	bbl/d	barrels per day
mcf/d	thousand cubic feet per day	boe/d	barrels of oil equivalent per day
mmcf/d	million cubic feet per day	WCS	Western Canadian Select
AECO	Alberta benchmark price for natural gas	WTI	West Texas Intermediate

Neither TSX nor its Regulation Services Provider (as that term is defined in policies of the TSX) accepts responsibility for the adequacy or accuracy of this release.