Pipestone Energy Corp. announces strong year-over-year reserves growth and record quarterly production

CALGARY, Alberta – (PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to provide an update on its operations with record quarterly production achieved; and to report its year-end 2021 independent reserves evaluation prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) with an effective date of December 31, 2021 (the “McDaniel Report”).

Recent Operations Highlights:

Record Production Volumes: Q4 2021 production averaged 28,623 boe/d (30% condensate, 44% total liquids), the highest quarterly production since inception. Production during Q4 2021 was impacted by several cold weather-related outages at 3^rd party midstream facilities;
2021 Production Guidance Achieved: 2021 production averaged 24,584 boe/d⁽¹⁾ (31% condensate, 45% total liquids) within previously announced guidance of 24,000 – 26,000 boe/d; and
Record Quarterly Operating Netback: The Company realized continued improvement in operating netback in Q4 2021 to a corporate record of $25.06/boe (inclusive of $8.45/boe in realized hedging losses), an increase of 14% over Q3 2021, and a 148% increase over Q4 2020.

2021 Reserve Highlights⁽¹⁾:

Pipestone delivered 28% growth in Proved Developed Producing (“PDP”) reserves from 31.7 MMboe in 2020 to 40.5 MMboe and achieved a Finding & Development (“F&D”) cost of $10.37/boe, coupled with a full year 2021 operating netback of $27.72/boe (exclusive of hedging losses) drives a 2021 PDP F&D recycle ratio⁽²⁾ of 2.7x;
Total Proved (“1P”) reserve volumes increased year-over-year by 20% from 134 MMboe to 160 MMboe with an F&D recycle ratio⁽²⁾ of 3.9x;
Total Proved plus Probable (“2P”) reserve volumes increased year-over-year by 21% from 228 MMboe to 275 MMboe with an F&D recycle ratio⁽²⁾ of 6.6x;
Increase in 1P Future Development Capital (“FDC”) of 11% from $640 million to $708 million, and a 6% increase in 2P FDC from $935 million to $989 million, which is equivalent to approximately 5 years at our 2022 capital spending budget;
Go-forward estimated undeveloped 1P F&D cost (FDC / Undeveloped Reserves) of $6.15/boe ($6.33/boe at YE 2020) and Undeveloped 2P F&D cost of $4.62/boe ($5.03/boe at YE 2020) reflect the continued efficiencies achieved in the business during 2021; and
Updated 1P and 2P Net Asset Value per Share (“NAVPS”) of $6.03 and $9.43 per fully diluted share, respectively, utilizing a 10% discount rate at a flat price deck (US$80/bbl WTI, C$3.50/GJ AECO, $0.80 CADUSD, no inflation). These NAVPS values reflect a premium of 36% and 113%, for 1P and 2P respectively, over the current share price of $4.42.

	(1)	2021 annual production volumes, capital expenditures and operating netbacks referenced throughout this press release are unaudited. All reserve volumes are reported on a net working interest, gross of royalties basis.
	(2)	Recycle Ratio is calculated by dividing Operating Netback per boe by F&D costs per boe. 2021 Operating Netback (unaudited) used to calculate Recycle Ratio is exclusive of realized hedging impacts and is calculated as revenue less royalties, operating, and transportation costs. Operating Netback is a non-GAAP measure, see “Advisories” for further details.

Operations Update:

Development Map:

An infographic accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/ab1d192e-186d-4203-b449-559feabf88ff

Development Program:

Pipestone successfully executed on all of its planned Q4 2021 development activities. During the quarter, the Company drilled 6 wells on the 2-31 pad, which were subsequently completed in early 2022. These wells are now equipped and will be on production by the end of February. Also, during the fourth quarter, Pipestone drilled 3 wells on the 6-30 pad, which were completed in early January and will also be on production by the end of February. In early January, Pipestone began drilling operations at the 2-25 pad and is currently on the last of four planned wells, with completions currently scheduled for Q1 2022. Approximately $3 million of capital spending originally planned for 2022 was accelerated into Q4 2021 in order to gain operational efficiencies. Total estimated capital expenditures for 2021 are approximately $184 million.

Production & Well Results:

Based on field estimates, Pipestone is pleased to confirm it met its previously announced average corporate production target for November and December 2021 of 30,000 boe/d with average production of 30,809 boe/d. As a result, Pipestone delivered record quarterly production of 28,623 boe/d in Q4 2021, which represents an increase of 16% over Q3 2021 and an increase of 61% over Q4 2020. During Q4 2021, the Company brought 3 new wells at the 6-13 pad on production with a shorter average lateral length of approximately 2,400 metres, which have achieved an average IP90 of 493 bbl/d wellhead condensate and 4.6 MMcf/d raw gas (condensate gas ratio “CGR” of ~107 bbl/MMcf). Based on these results and an actual achieved DCE&T cost of $4.9 million, the company forecasts these wells to payback in approximately 4 months from being brought on production at a flat price deck (US$80/bbl WTI, C$3.50/GJ AECO, $0.80 CADUSD).

On the 14-4 delineation pad, Pipestone drilled two Montney ‘B’ (2,920 metre average lateral length) wells which were brought on production in November 2021. The two Montney ‘B’ wells are in-line with expectations, achieving an IP90 of 330 bbl/d and 3.4 MMcf/d raw gas (CGR of ~97 bbl/MMcf). These wells are forecast to produce ~85 Mbbls of wellhead condensate over the first 12 months on production. Based on these results and an actual achieved DCE&T cost of $5.9 million, the Company forecasts these wells to payback in approximately 7 months from being brought on production at a flat price deck (US$80/bbl WTI, C$3.50/GJ AECO, $0.80 CADUSD). A Lower Montney ‘D’ well on the 14-4 pad tested with significant gas deliverability, averaging 4.4 MMcf/d raw gas and 365 bbl/d condensate, but with an elevated H₂S content of 11%, requiring the well to be shut-in while awaiting the installation of blending equipment. Based on a current field average H₂S content of 4 – 5%, Pipestone is capable of accommodating higher sulphur content wells through blending.

In H1 2022, the Company expects to bring on stream 13 additional wells, which will underpin its 2022 annual production growth. The Company also continues to evaluate alternatives to contract incremental gas processing capacity, which it expects to contractually secure prior to the end of Q1 2022.

Year-End 2021 Reserve Results:

		December 31, 2021⁽¹⁾		December 31, 2020⁽²⁾
2P Reserve Volumes (Working Interest)		Amount	Weight	Amount	Weight	Change
Condensate⁽³⁾	Mbbls	73,582	27%	65,323	29%	13%
Other NGLs	Mbbls	42,036	15%	30,382	13%	38%
Total Natural Gas Liquids	Mbbls	115,618	42%	95,705	42%	21%
Shale Gas	MMcf	957,635	58%	791,801	58%	21%
Total	Mboe	275,223	*100*%	227,672	*100*%	21%

Total by Category
Proved Developed Producing	Mboe	40,510	15%	31,735	14%	28%
Proved Developed Non-Producing	Mboe	4,394	2%	1,258	1%	249%
Proved Undeveloped	Mboe	115,244	42%	100,984	44%	14%
Total Proved	Mboe	160,148	58%	133,977	59%	20%
Probable	Mboe	115,075	42%	93,695	41%	23%
Total Proved + Probable	Mboe	275,223	*100*%	227,672	*100*%	21%

	(1)	Volumes calculated using the 3 Consultant (“3C”) Average Price Deck as of January 1, 2022. The 3C price Deck includes pricing forecasts from McDaniel and Associates, GLJ Petroleum Consultants, and Sproule.
	(2)	Volumes calculated using the 3C Average Price Deck as of January 1, 2021.
	(3)	Included in the Total Condensate 2P Reserve Volumes (Working Interest) are nominal Crude Oil Volumes.

2021 Independent Reserves Evaluation:

McDaniel conducted an independent Reserves Evaluation effective December 31, 2021, which was prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101. The Reserves Evaluation was based on 3C forecast pricing and foreign exchange rates at January 1, 2022 as outlined in this press release.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. In addition to the information disclosed in this news release, more detailed information will be included in Pipestone’s annual information form for the year ended December 31, 2021, which will be available on the Company’s website at www.pipestonecorp.com and on SEDAR at www.sedar.com on or before March 31, 2022.

Company Gross (before royalties) Working Interest Reserves:

	2021 Year-End Reserves (Working Interest)⁽¹⁾
			Natural Gas	Total
	Tight Oil	Shale Gas	Liquids⁽²⁾	Company
Reserve Category	(Mbbl)	(MMcf)	(Mbbl)	(Mboe)
Proved
Developed Producing	23	145,910	16,169	40,510
Developed Non-Producing	–	16,372	1,665	4,394
Undeveloped	–	391,595	49,979	115,245
Total Proved	23	553,877	67,813	160,149
Total Probable	7	403,757	47,775	115,075
Total Proved + Probable⁽³⁾	30	957,635	115,588	275,224

	(1)	Volumes calculated using the 3C Average Price Deck as of January 1, 2022.
	(2)	Natural Gas Liquids includes condensate volumes. Booked 2P condensate volumes are 73,552 Mbbls as at December 31, 2021.
	(3)	Amounts may not add due to rounding.

Company Net Present Value of Future Net Revenue Using 3C Price Forecast ⁽¹⁾:

	Before Income Taxes
$C Millions	Discount Factor (% / Year)
Reserve Category		0%		5%		10%		15%		20%
Proved
Developed Producing	$582		$510		$454		$411		$379
Developed Non-Producing	$70		$57		$48		$42		$38
Undeveloped	$1,749		$1,251		$934		$720		$570
Total Proved⁽²⁾	$2,401		$1,818		$1,436		$1,174		$987
Probable	$2,051		$1,204		$782		$548		$408
Total Proved + Probable⁽²⁾	$4,452		$3,022		$2,218		$1,723		$1,395

	(1)	Calculated using the 3C Average Price Deck as of January 1, 2022.
	(2)	Amounts may not add due to rounding.

Future Development Capital and F&D Costs:

FDC reflects McDaniel’s best estimate of the future cost to bring Pipestone’s proved and probable developed and undeveloped reserves on production. Changes in forecasted FDC occur annually as a result of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, and changes in service costs. Undiscounted 2P FDC at December 31, 2021 increased by $53 million relative to December 31, 2020, to total $989 million.

		Total Proved
	Total Proved	+ Probable
Year	(C$MM)	(C$MM)
2022	$180	$180
2023	$197	$197
2024	$129	$129
2025	$139	$139
2026	$57	$75
Remainder Thereafter	$6	$269
Total FDC Undiscounted⁽¹⁾	$708	$989
Total FDC Discounted (10%)	$585	$736

(1)

Amounts may not add due to rounding.

2021 F&D Costs \| Recycle Ratio
Proved Developed Producing
Reserve Additions	Mboe		17,748
2021 Capital Expenditures (Estimated)	$MM	$184
F&D per boe	$/boe	$10.37
2021 Operating Netback (Estimated)⁽¹⁾	$/boe	$27.72
Recycle Ratio		2.7x
Total Proved
Reserve Additions	Mboe		35,145
2021 Capital Expenditures (Estimated)	$MM	$184
2021 Change in FDC	$MM	$68
F&D per boe	$/boe	$7.17
2021 Operating Netback (Estimated) ⁽¹⁾	$/boe	$27.72
Recycle Ratio		3.9x
Proved + Probable
Reserve Additions	Mboe		56,535
2021 Capital Expenditures (Estimated)	$MM	$184
2021 Change in FDC	$MM	$53
F&D per boe	$/boe	$4.20
2021 Operating Netback (Estimated) ⁽¹⁾	$/boe	$27.72
Recycle Ratio		6.6x

(1)

2021 Operating Netback (unaudited) used to calculate Recycle Ratio is exclusive of realized hedging impacts and is calculated as revenue less royalties, operating, and transportation costs. Operating Netback is a non-GAAP measure, see “Advisories” for further details

1P / 2P Future Undeveloped F&D Costs
Proved Undeveloped
1P Future Development Capital	$MM	$708.3
Proved Undeveloped Reserves	Mboe		115,244
1P F&D	*$/boe*	$6.15

Proved + Probable
2P Future Development Capital	$MM	$988.7
Proved + Probable Undeveloped Reserves	Mboe		214,155
2P F&D	*$/boe*	$4.62

Annual Reserve Reconciliation:

		Tight Oil			Natural Gas			Natural Gas Liquids⁽¹⁾			Company Total
Company Gross		(Mbbl)			(MMcf)			(Mbbl)			(Mboe)
Proved Developed Producing
Balance – December 31, 2020	25.8			116,852			12,234			31,735
Extensions⁽²⁾	–			5,703			737			1,688
Economic Factors⁽³⁾	8.7			3,929			409			1,072
Technical Revisions⁽⁴⁾	15.2			(30,568		)	(2,342		)	(7,422		)
Technical Revisions – PUD Transfer⁽⁵⁾	–			79,784			9,112			22,409
Production	(27.0		)	(29,791		)	(3,981		)	(8,973		)
Balance – December 31, 2021	22.7			145,910			16,169			40,510
Total Proved
Balance – December 31, 2020	25.8			462,484			56,870			133,977
Extensions⁽²⁾	–			112,354			14,120			32,846
Economic Factors⁽³⁾	8.7			8,339			917			2,316
Technical Revisions⁽⁴⁾	15.2			471			(114		)	(17		)
Technical Revision – PUD Transfer	–			–			–			–
Production	(27.0		)	(29,791		)	(3,981		)	(8,973		)
Balance – December 31, 2021	22.7			553,877			67,813			160,148
Total Probable
Balance – December 31, 2020	10.7			329,317			38,798			93,695
Extensions⁽²⁾	–			61,996			6,707			17,040
Economic Factors⁽³⁾	1.0			6,957			741			1,901
Technical Revisions	(4.8		)	5,487			1,529			2,439
Technical Revision – PUD Transfer	–			–			–			–
Production	–			–			–			–
Balance – December 31, 2021	6.9			403,757			47,775			115,075
Proved + Probable
Balance – December 31, 2020	36.5			791,801			95,668			227,672
Extensions⁽²⁾	–			174,351			20,828			49,886
Economic Factors⁽³⁾	9.7			15,296			1,658			4,217
Technical Revisions	10.4			5,978			1,415			2,422
Technical Revision – PUD Transfer	–			–			–			–
Production	(27.0		)	(29,791		)	(3,981		)	(8,973		)
Balance – December 31, 2021	29.5			957,635			115,588			275,223

	(1)	Natural Gas Liquids includes condensate volumes. Booked 2P condensate volumes are 73,552 Mbbls as of December 31, 2021.
	(2)	Total proved extensions are a result of 8 new booked locations as a result of increased take away capacity. Proved + Probable extensions are a result of 7 new booked locations. PDP extensions are a result of a step out well that was not previously booked being brought on production prior to YE2021.
	(3)	Economic Factor changes are due to an increase in forecasted commodity prices compared to 2020.
	(4)	The technical revisions within the Proved Developed Producing category relate primarily to a reduction in previously forecast production due to higher fluid rates, as well as other miscellaneous items. The majority of the technical revisions reflect the transfer of reserves from Proved Developed Producing into the Proved Developed Non-Producing category, as evidenced by the minimal revision to Total Proved Reserves. The Company expects to recover these volumes back into Proved Developed Producing category over the course of 2022 through the ongoing optimization of existing artificial lift systems as well as the potential implementation of new systems.
	(5)	Technical revision related to the conversion of Proven Undeveloped Locations by 2021 capital expenditures.

Pre-Tax Net Asset Value – Excludes Unbooked Land Value:

	As at December 31, 2021
		3C Price	Flat Price
$C Millions		Forecast	Deck⁽¹⁾
2P Reserves, Before-Tax NPV10%		$2,218	$2,884
(-) Abandonment Obligations (Estimated)		($15)	($15)
(-) Mark-to-Market of Hedges⁽²⁾		($6)	($6)
(-) Net Debt (Estimated)⁽³⁾		($204)	($204)

= Implied Net Asset Value		$1,993	$2,659
Fully Diluted Shares Outstanding (millions)⁽⁴⁾		282	282
Net Asset Value per Share ($/share)		$7.07	$9.43

Note: The above Net Asset Value excludes any additional land value for approximately 70 net sections of unbooked undeveloped land, which represents approximately 50% of the Company’s total land base.

	(1)	Flat Price Deck utilizes US$80 per barrel WTI, C$3.50 per GJ AECO, and $0.80 CADUSD exchange rate with no future inflation.
	(2)	Hedges include commodity price hedges as at December 31, 2021.
	(3)	Net debt represents bank debt and the addition of working capital and is a non-GAAP measure. See “Advisories” for further details.
	(4)	Fully Diluted Shares Outstanding at December 31, 2021 assumes full dilutive impact of the convertible preferred shares balance as at December 31, 2021 and other dilutive instruments.

Q4 2021 and Full Year 2021 Financial Results Conference Call

Fourth Quarter and Full year 2021 results are expected to be released before market open on March 9, 2022. A conference call has been scheduled for March 9, 2022 at 9:00 a.m Mountain Time (11:00 a.m Eastern Time) for interested investors, analysts, brokers, and media representatives.

Conference Call Details:

Toll-Free: (866) 953-0776
International: (630) 652-5852
Conference ID: 5089085

Pipestone Energy Corp.

Pipestone is an oil and gas exploration and production company focused on developing its large contiguous and condensate rich Montney asset base in the Pipestone area near Grande Prairie. Pipestone expects to grow its production to 35 Mboe/d (midpoint) in 2022, while generating significant free cash flow and de-leveraging the business. Pipestone is committed to building long term value for our shareholders while maintaining the highest possible environmental and operating standards, as well as being an active and contributing member to the communities in which it operates. Pipestone has achieved certification of all its production from its Montney asset under the Equitable Origin EO100^TM Standard for Responsible Energy Development. Pipestone shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.

Advisories & Contact

Pipestone Energy Contacts:

Paul Wanklyn President and Chief Executive Officer (587) 392-8407 paul.wanklyn@pipestonecorp.com	Craig Nieboer Chief Financial Officer (587) 392-8408 craig.nieboer@pipestonecorp.com

Dan van Kessel VP Corporate Development (587) 392-8414 dan.vankessel@pipestonecorp.com

Advisory Regarding Non-GAAP Measures

Non-GAAP measures

This press release includes references to financial measures commonly used in the oil and natural gas industry. The terms “free cash flow”, “operating netback”, and “net debt”, are not defined under IFRS, which have been incorporated into Canadian GAAP, as set out in Part 1 of the Chartered Professional Accountants Canada Handbook – Accounting, are not separately defined under GAAP, and may not be comparable with similar measures presented by other companies. The reconciliations of these non-GAAP measures to the nearest GAAP measure are discussed in the MD&A dated November 10, 2021, a copy of which is available electronically on Pipestone’s SEDAR at www.sedar.com.

Management believes the presentation of the non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the opportunity to better analyze and compare performance against prior periods.

Free cash flow

“Free cash flow” is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital and decommissioning provision costs incurred, less capital expenditures incurred, and is not defined under IFRS. Free cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management uses free cash flow to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone’s principal business activities, inclusive of ongoing capital expenditures, prior to consideration of changes in working capital.

Operating netback

“Operating netback” is a non-GAAP measure that is calculated on either a total dollar or per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales adjusted for realized gains/losses on commodity risk management contracts.

Operating netback is a common metric used in the oil and natural gas industry and is used by Company management to measure operating results on a per boe basis to better analyze and compare performance against prior periods, as well as formulate comparisons against peers.

Net debt

“Net debt” is a non-GAAP measure that equals bank debt outstanding plus adjusted working capital. The Company does not consider its convertible preferred share obligation to be part of net debt as this represents a non-cash obligation that will ultimately be settled by conversion into Pipestone common shares and reclassified from a liability to share capital on the Company’s statement of financial position. Net debt is considered to be a useful measure in assisting management and investors to evaluate Pipestone’s financial strength.

NAVPS

NAVPS is a non-GAAP financial ratio calculated as the before-tax NPV for 1P and 2P reserves discounted at 10%, less abandonment obligations, mark-to-market of hedges, and Net Debt divided by the fully diluted common shares outstanding as at December 31, 2021.

Advisory Regarding Forward-Looking Statements

In the interest of providing shareholders of Pipestone and potential investors information regarding Pipestone, this news release contains certain information and statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future results or events, are based upon internal plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “estimate”, “expect”, “intend”, “forecast”, “continue”, “propose”, “may”, “will”, “should”, “believe”, “plan”, “target”, “objective”, “project”, “potential” and similar or other expressions indicating or suggesting future results or events.

Forward-looking statements are not promises of future outcomes. There is no assurance that the results or events indicated or suggested by the forward-looking statements, or the plans, intentions, expectations or beliefs contained therein or upon which they are based, are correct or will in fact occur or be realized (or if they do, what benefits Pipestone may derive therefrom).

In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: expected timing to bring the 2-31 pad, 6-30 pad, and 2-25 pad on production; the expected payout periods for the 14-4 and 6-13 pads, including the expected condensate volume recovery from the 14-4 Montney ‘B’ wells; contractually securing incremental natural gas processing capacity prior to the end of Q1 2022; the expectation to recover the majority of the Proved Developed Non-Producing volumes back into the Proved Developed Producing category over the course of 2022; and the total number of wells expected to be brought on production in the first half of 2022. In addition, statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

With respect to the forward-looking statements contained in this news release, Pipestone has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, natural gas liquids (NGLs) and natural gas prices with current commodity price forecasts; the ability to contractually secure incremental natural gas processing capacity, beginning in 2023, on terms acceptable to Pipestone or at all; the economic impacts of the COVID-19 pandemic; the ability to integrate Blackbird Energy Inc.’s (“Blackbird”) and Pipestone Oil Corp. ’s (“Pipestone Oil”) historical businesses and operations and realize financial, operational and other synergies from the combination transaction completed on January 4, 2019; Pipestone’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the predictability of future results based on past and current experience; the predictability and consistency of the legislative and regulatory regime governing royalties, taxes, environmental matters and oil and gas operations, both provincially and federally; Pipestone’s ability to successfully market its production of oil, NGLs and natural gas; the timing and success of drilling and completion activities (and the extent to which the results thereof meet expectations); Pipestone’s future production levels and amount of future capital investment, and their consistency with Pipestone’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone’s reserves and other resources; Pipestone’s ability to economically produce oil and gas from its properties and the timing and cost to do so; the performance of both new and existing wells; future cash flows from production; future sources of funding for Pipestone’s capital program, and its ability to obtain external financing when required and on acceptable terms; future debt levels; geological and engineering estimates in respect of Pipestone’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations to which Pipestone may be subject from time to time; and the impact of industry competition.

The forward-looking statements contained herein reflect management’s current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Pipestone believes that its underlying assessments and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking statements, which are inherently uncertain, depend upon the accuracy of such assessments and assumptions, and are subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are beyond Pipestone’s control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking statements. Such risks and uncertainties include, but are not limited to, volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; the ability to successfully integrate Blackbird’s and Pipestone Oil’s historical businesses and operations; general economic, business and industry conditions; variance of Pipestone’s actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; and the availability of sufficient natural gas processing capacity; and risks related to the exploration, development and production of oil and natural gas reserves and resources. Additional risks, uncertainties and other factors are discussed in the MD&A dated November 10, 2021 and in Pipestone’s annual information form dated March 10, 2021, copies of which are available electronically on Pipestone’s SEDAR at www.sedar.com.

Certain information in this news release is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure of the company’s reasonable expectations of our anticipate results. The financial outlook is provided as of the date of this news release. Certain assumptions made underlying the financial outlook are disclosed herein under “2022 Guidance & Corporate Forecast Update”. Readers are cautioned that this financial outlook may not be appropriate for other purposes. The forward-looking statements contained in this news release are made as of the date hereof and Pipestone assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking statements herein are expressly qualified by this advisory.

Initial Production Rates and Short-Term Test Rates

This document may disclose test rates of production for certain wells over short periods of time (i.e. IP90), which are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability and may not be representative of stabilized on-stream production rates.

Production over a longer period will also experience natural decline rates, which can be high in the Montney play and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered “load” fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material.

Oil and Gas Measures

Basis of Barrel of Oil Equivalent

Petroleum and natural gas reserves and production volumes are stated as a “barrel of oil equivalent” (boe), derived by converting natural gas to oil equivalency in the ratio of 6,000 cubic feet of gas to one barrel of oil. Readers are cautioned that boe figures may be misleading, particularly if used in isolation. A boe conversion ratio of 6,000 cubic feet of gas to one barrel of oil is based on energy equivalency, which is primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.

CGR

Any references herein to “CGR” mean condensate/gas ratio and is expressed as a volume of condensate (expressed in barrels) per million cubic feet (mmcf) of natural gas.

DCE&T

This news release contains reference to DCE&T (drilling, completion, equip and tie-in costs), which does not have a standardized meaning or standard method of calculation and therefore such measure may not be comparable to similar measures used by other companies and should not be used to make comparisons. This metric has been included herein to provide readers with an additional measure to evaluate the Company’s performance; however, this measure is not a reliable indicator of the future performance and future performance may not compare to the performance in previous periods and therefore such a metric should not be unduly relied upon. DCE&T includes all capital spent to drill, complete, equip and tie-in a well.

F&D costs

The calculation of F&D costs includes all exploration and development capital for the year plus the change in future development capital for the year. This total capital including the change in future development capital is divided by the change in reserves for the year.

Recycle Ratio

Recycle Ratio is measured by dividing the Operating Netback, excluding realized hedging impacts, by the F&D cost per boe for the year.

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