PIPE Pipestone Energy Corporation

(PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to report its fourth quarter and full year 2022 financial and operation results.

FOURTH QUARTER 2022 CORPORATE HIGHLIGHTS

• In Q4 2022, Pipestone achieved record average quarterly production totaling 33,816 boe/d (30% condensate and crude oil, 42% total liquids), representing a 5% quarterly increase over Q3 2022, and a 18% increase over Q4 2021. The Company’s average annual production for 2022 was 31,090 boe/d (29% condensate, 41% total liquids) within its guidance range of 31,000 boe/d and 33,000 boe/d, representing 26% year-over-year growth in average daily production volumes. Production volumes averaged 34,500 boe/d (30% condensate and crude oil, 40% total liquids) in January and February 2023, based on field estimates;
• As a result of increased production volumes and improved commodity prices, the Company generated quarterly revenue of $185.4 million which represents a $48.1 million or 35% increase from Q4 2021 revenue of $137.3 million. This is also an increase of $11.0 million or 6% from Q3 2022 revenue of $174.4 million with realized commodity prices remaining relatively flat quarter over quarter;
• In Q4 2022, the Company’s operating netback(1) was $34.58/boe, an increase of 38% over Q4 2021 operating netback(1) of $25.06/boe and a 8% increase over Q3 2022 operating netback(1) of $31.88/boe.
• In Q4 2022, the Company produced adjusted funds flow from operations(1) of $99.7 million ($0.36 per share basic and diluted), an increase of 69% from its Q4 2021 adjusted funds flow from operations(1) of $58.9 million ($0.31 per share basic and $0.21 per share diluted) and representing a $13.2 million or 15% increase from Q3 2022 adjusted funds flow from operations(1) of $86.5 million ($0.46 per share basic and $0.30 per share diluted);
• The Company has realized robust returns on invested capital with Q4 2022 annualized ROCE(1) and CROIC(1) of 28% and 34%, respectively, as compared to Q4 2021 annualized ROCE(1) and CROIC(1) of 23% and 26%, respectively;
• In Q4 2022, Pipestone generated record free cash flow(1) of $70.1 million while continuing to grow its production (three months ended December 31, 2021 – free cash flow(1) of 19.8 million). In executing its return of capital to shareholders plan, Pipestone utilized $4.9 million or 7% of the free cash flow(1) to repurchase its common shares during Q4 2022 pursuant to its normal course issuer bid (“NCIB”) with the remainder allocated to deleveraging its balance sheet.
• The Company exited 2022 with net debt(1) of $117.4 million, which is a material reduction of $62.8 million or 35% from its September 30, 2022 net debt(1) balance of $180.2 million and a decrease of $87.0 million or 43% from its December 31, 2021 net debt(1) balance of $204.4 million. The Company’s net debt(1) to annualized trailing quarter adjusted funds flow from operations(1) ratio at December 31, 2022 is 0.3 times (December 31, 2021 – 0.9 times) which demonstrates the strength of the Company’s current financial position.

      (1)   See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.

Pipestone Energy Corp. – Financial and Operating Highlights

	Three months ended December 31,						Year ended December 31,
($ thousands, except per unit and per share amounts)	2022			2021			2022			2021
Financial
Sales of liquids and natural gas	$	185,405		$	137,264		$	723,755		$	391,295
Cash from operating activities		96,119			71,810			378,805			157,864
Adjusted funds flow from operations(1)		99,739			58,927			382,960			166,358
Per share, basic		0.36			0.31			1.82			0.87
Per share, diluted		0.36			0.21			1.79			0.59
Capital expenditures, including capitalized G&A		29,603			39,219			245,727			186,838
Free cash flow(1)		70,136			19,777			137,233			(20,633	)
Income and comprehensive income		53,437			51,307			220,117			67,920
Per share, basic		0.20			0.27			1.04			0.35
Per share, diluted		0.19			0.18			1.04			0.24
Adjusted EBITDA(1)		104,906			63,667			401,952			183,882
Annualized cash return on invested capital (CROIC)(1)		33.8	%		26.1	%		32.4	%		18.9	%
Annualized return on capital employed (ROCE)(1)		28.0	%		22.8	%		30.9	%		14.9	%
Net debt(end of period)(1)								117,435			204,418
Net debt to annualized adjusted funds flow from operations for the trailing period(1)		0.3x			0.9x			0.3x			1.2x
Available funding(end of period)(1)							$	153,800		$	75,160
Amount purchased under NCIB		4,890			3,434			39,363			3,434
Common shares purchased under NCIB(000s)		1,189			949			8,649			949
Common shares outstanding(000s) (end of period)								278,949			191,446
Weighted-average basic shares outstanding(000s)		274,029			192,033			210,967			191,525
Weighted-average diluted shares outstanding(000s)		276,530			282,530			213,560			281,656
Operations
Production
Condensate(bbls/d)		9,833			8,481			8,785			7,561
Other Natural Gas Liquids (NGLs)(bbls/d)		4,027			3,978			3,948			3,346
Total NGLs(bbls/d)		13,860			12,459			12,733			10,907
Crude oil(bbls/d)		218			44			93			74
Natural gas(Mcf/d)		118,428			96,718			109,581			81,620
Total(boe/d)(2)		33,816			28,623			31,090			24,584
Condensate and crude oil(% of total production)		30	%		30	%		29	%		31	%
Total liquids(% of total production)		42	%		44	%		41	%		45	%
Average realized prices(3)
Condensate(per bbl)		109.11			95.68			118.15			81.49
Other NGLs(per bbl)		46.53			44.30			53.81			34.61
Total NGLs(per bbl)		90.92			79.27			98.20			67.11
Crude oil(per bbl)		98.99			89.13			106.83			70.45
Natural gas(per Mcf)		6.19			5.17			6.60			4.10
Netbacks
Revenue(per boe)		59.59			52.12			63.78			43.61
Realized loss on commodity risk management contracts(per boe)		(0.89	)		(8.45	)		(4.57	)		(6.34	)
Royalties(per boe)		(7.74	)		(2.58	)		(6.53	)		(1.60	)
Operating expenses(per boe)		(12.87	)		(13.01	)		(12.63	)		(11.52	)
Transportation(per boe)		(3.51	)		(3.02	)		(3.66	)		(2.77	)
Operating netback(per boe)(1)		34.58			25.06			36.39			21.38
Adjusted funds flow netback(per boe)(1)	$	32.04		$	22.37		$	33.75		$	18.54

(1)  See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.(2)  For a description of the boe conversion ratio, see “Advisories Regarding Oil and Gas Information – Basis of Barrel of Oil Equivalent” advisory. References to crude oil in production amounts are to the product type “tight oil” and references to natural gas in production amounts are to the product type “shale gas”. References to total liquids include oil and natural gas liquids (including condensate, pentane, butane, propane and ethane).(3)  Figures calculated before hedging.

Operations Update

In late February, Pipestone commenced drilling on its 11-09 eastern delineation pad, with the first of two new wells rig released and the second well currently drilling. These wells are the first to be drilled south of the Wapiti River and are the easternmost locations drilled, since 2018. The first well on this pad was drilled to a total depth of ~7,000m in 13 days, with the entire 4,400m lateral section completed in a single bit run. Completions will commence immediately after rig release of the second well, followed by extended flow tests. This summer, the Company plans to install a new gathering pipeline to tie the 11-09 pad into Pipestone’s existing 12-14 battery.

Flow back operations commenced in late February on the recently completed six well pad at 11-05. After approximately seven days of flowback, the average rate of all six wells is meeting type curve expectations at 3.6 MMcf/d raw gas and 480 bbls/d condensate (condensate-gas-ratio (“CGR”) of 133 bbl / MMcf). Completions operations have also begun on four wells recently drilled at the 2-31 pad, with a second set of four wells at the 2-25 pad slated to follow shortly thereafter. By April 2023, the Company will have increased its producing well count by 14 since December 31, 2022.

Updated 2023 Guidance and 2024 Outlook

2023 production guidance of 34,000 - 36,000 boe/d and capital spend guidance of $245 - $265 million remains consistent as previously announced in November 2022. However, as a result in the reduction in commodity prices, Pipestone’s 2023 guidance and 2024 outlook pricing has been reduced to US$80 WTI and $3.00 AECO which results in a reduction of the Company’s projected cash flow(1) and free cash flow(1). The revised 2023 guidance and 2024 outlook are detailed in the table below.

(1)   See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.

	Prev. 2023Guidance		2023 GuidanceUpdate		2024ForecastUpdate
Price Forecast	US$85 WTI$0.75 CAD | $4.00 AECO		US$80 WTI | $0.74 CAD$3.00 AECO
Full Year Production (boe/d)	34,000 – 36,000		34,000 – 36,000		40,000 – 42,000
AT Cash Flow(1) ($MM)	$400 - $430		$330 - $350		$345(net of ~$40 MM in cash taxes)
Capex ($MM)	$245 - $265		$245 - $265		$220
Free Cash Flow(1) ($MM)	$135 - $165		$75 - $95		$125
Base Dividend ($MM)	$32		$32		$32
(Net Debt)(1) / Net Cash ($MM)	Pipestone is targeting a run-rate net debt(1) of $100 million
LTM Debt / Cash Flow(1) (x)

(1)   See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.

Shareholder Returns

Pipestone remains committed to delivering meaningful returns to shareholders. On November 9, 2022, the Company declared an inaugural quarterly dividend of three cents per common share, which will be paid on March 31, 2023 to shareholders of record at the close of business on March 15, 2023. In addition to the quarterly base dividend, Pipestone expects to allocate a substantial portion of its future free cash flow(1) to share buybacks. With respect to its previously announced intention to launch a substantial issuer bid, Pipestone expects to provide an update to investors in the near term.

(1)   See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.

The table below outlines the expected cash flow(1) generation of the Company in 2023 at various commodity prices and details the expected prioritized uses of this cashflow from left to right.

A table accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/df5e2c38-63b7-4351-91ba-1c1575340064

Regulatory Filings:

Pipestone has filed its year-end 2022 audited financial statements, management’s discussion and analysis (“MD&A”), and 2022 annual information form on SEDAR, as well as posted these documents on its website at www.pipestonecorp.com.

Q4 2022 and Full Year 2022 Financial Results Conference Call

Fourth quarter and full year 2022 results are expected to be released before markets open on March 8, 2023. A conference call has been scheduled for March 8, 2023 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time) for interested investors, analysts, brokers, and media representatives.

Conference Call Details:

Please use the following participant URL to register for the Q4 and full year 2022 financial results conference call: https://register.vevent.com/register/BIf2529ca87a7949c8bece6d62670b175b. This registration link can also be found on the Company’s website at www.pipestonecorp.com. This link will provide each registrant with a toll-free dial-in number and a unique PIN to connect to the call.

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 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 EO100TM Standard for Responsible Energy Development. Pipestone shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.

Pipestone Contacts:

Paul WanklynPresident and Chief Executive Officer(587) 392-8407paul.wanklyn@pipestonecorp.com	Craig NieboerChief Financial Officer(587) 392-8408craig.nieboer@pipestonecorp.com
Dan van KesselVP Corporate Development(587) 392-8414dan.vankessel@pipestonecorp.com

Advisory Regarding Non-GAAP Measures

Non-GAAP measures

This news release includes references to financial measures commonly used in the oil and natural gas industry. The terms “adjusted funds flow from operations”, “operating netback”, “adjusted funds flow netback”, “available funding”, “adjusted working capital”, “cash flow”, “free cash flow”, “net debt”, “adjusted EBITDA”, “CROIC” and “ROCE” 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 Non-GAAP measures section of Pipestone’s MD&A for the year ended December 31, 2022 dated March 8, 2023, a copy of which is available electronically on Pipestone’s SEDAR profile at www.sedar.com.

Management of the Company believes the presentation of 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.

Adjusted funds flow from operations

Pipestone uses “adjusted funds flow from operations” (cash from operating activities before changes in non-cash working capital, cash share-based compensation and decommissioning provision costs incurred, if applicable), a measure that is not defined under IFRS. Adjusted funds flow from operations 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 adjusted funds flow from operations 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 prior to consideration of changes in working capital, cash share-based compensation and decommissioning provision costs incurred.

The following table reconciles cash from operating activities to adjusted funds flow from operations:

	Three months endedDecember 31,				Year endedDecember 31,
($ thousands)	2022	2021			2022		2021
	$	$			$		$
Cash from operating activities	96,119	71,810			378,805		157,864
Change in non-cash working capital	3,535	(12,814	)		(225	)	8,341
Cash share-based compensation	-	-			4,295		-
Decommissioning provision costs incurred	85	(69	)		85		153
Adjusted funds flow from operations	99,739	58,927			382,960		166,358

Operating netback and adjusted funds flow netback

Operating netback 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.

The following table details the calculation of operating netback on a total dollar basis:

	Three months ended December 31,					Year ended December 31,
($ thousands)	2022		2021			2022		2021
	$		$			$		$
Sales of liquids and natural gas	185,405		137,264			723,755		391,295
Realized (loss) gain on commodity risk management contracts (1)	(2,766	)	(22,255	)		(51,886	)	(56,881	)
Royalties	(24,766	)	(6,784	)		(74,107	)	(14,366	)
Operating expense	(40,053	)	(34,259	)		(143,302	)	(103,400	)
Transportation expense	(10,910	)	(7,957	)		(41,582	)	(24,869	)
Operating netback	107,607		66,009			412,878		191,779

The following table reconciles cash from operating activities to operating netback:

	Three months endedDecember 31,					Year endedDecember 31,
($ thousands)	2022		2021			2022		2021
	$		$			$		$
Cash from operating activities	96,119		71,810			378,805		157,864
Change in non-cash working capital	3,535		(12,814	)		(225	)	8,341
G&A expense	2,701		2,342			10,926		7,897
Cash share-based compensation	-		-			4,295		-
Cash financing expense	5,714		4,469			19,535		16,486
Decommissioning provision costs incurred	85		(69	)		85		153
Realized (gain) loss on interest rate risk management contracts	(547	)	271			(543	)	1,038
Operating netback	107,607		66,009			412,878		191,779
G&A expense	2,701		2,342			10,926		7,897
Cash financing expense	5,714		4,469			19,535		16,486
Realized (gain) loss on interest rate risk
Management contracts	(547	)	271			(543	)	1,038
Adjusted funds flow netback	99,739		58,927			382,960		166,358

Adjusted funds flow netback reflects adjusted funds flow from operations on a per-unit-of-production basis and is determined by dividing adjusted funds flow from operations by total production on a per-boe basis. Adjusted funds flow netback can also be determined by deducting G&A, transaction costs, cash financing expense, adding financing income and adjusting for realized gains/losses on interest rate risk management contracts on a per-unit-of-production basis from the operating netback. Refer to “Financial and Operating Results” and “Netback Analysis” sections of the MD&A dated March 8, 2023 for further details on the inputs and calculation of operating netback and adjusted funds flow netback on a per-unit-of-production basis.

Operating netback and adjusted funds flow netback are common metrics used in the oil and natural gas industry and are used by the Company’s 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. These measures should not be considered an alternative to or more meaningful than cash from operating activities defined under IFRS.

Adjusted working capital and available funding

Available funding is comprised of adjusted working capital and undrawn portions of the Company’s credit facility. The available funding measure allows management of the Company and others to evaluate the Company’s short-term liquidity. Adjusted working capital is a non-GAAP measure and is comprised of current assets less current liabilities on the Company’s consolidated statement of financial position and excludes the current portion of risk management contracts and lease liabilities. Adjusted working capital should not be considered an alternative to, or more meaningful than, working capital as defined under IFRS. Also refer to the “Liquidity and Capital Resources” section of the MD&A dated March 8, 2023 for additional information and reconciliations.

Cash flow

Cash flow is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital, cash share-based compensation and decommissioning provision costs incurred, and is not defined under IFRS. 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 of the Company uses 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 prior to consideration of changes in working capital, cash share-based compensation and decommissioning provision costs incurred.

The following table reconciles cash from operating activities to cash flow:

	Three months ended December 31,				Year ended December 31,
($ thousands)	2022	2021			2022		2021
	$	$			$		$
Cash from operating activities	96,119	71,810			378,805		157,864
Change in non-cash working capital	3,535	(12,814	)		(225	)	8,341
Cash share-based compensation	-	-			4,295		-
Decommissioning provision costs incurred	85	(69	)		85		153
Cash flow	99,739	58,927			382,960		166,358

Free cash flow

Free cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities as determined in accordance with IFRS as an indicator of financial performance. Free cash flow is presented to assist management of the Company and investors in analyzing operating performance by the business and how much cash flow is available for deleveraging and / or shareholder returns in the stated period after capital expenditures have been incurred. Free cash flow equals cash from operating activities plus the change in non-cash working capital and cash share-based compensation less capital expenditures.

The following table reconciles cash from operating activities to free cash flow:

	Three months endedDecember 31,					Year endedDecember 31,
($ thousands)	2022		2021			2022		2021
	$		$			$		$
Cash from operating activities	96,119		71,810			378,805		157,864
Change in non-cash working capital	3,535		(12,814	)		(225	)	8,341
Cash share-based compensation	-		-			4,295		-
Decommissioning provision costs incurred	85		(69	)		85		153
Capital expenditures	(29,603	)	(39,219	)		(245,727	)	(186,838	)
Free cash flow	70,136		19,708			137,233		(20,480	)

Net debt (cash)

Net debt (cash) is a non-GAAP measure that equals bank debt outstanding plus adjusted working capital deficit and excluding dividends payable ($8.4 million accrued at December 31, 2022, which relates to the $0.030 per common share dividend declared on November 9, 2022, which is payable on March 31, 2023, to shareholders of record at the close of business on March 15, 2023). Net debt is considered to be a useful measure in assisting management and investors to evaluate Pipestone Energy’s financial strength. Also refer to the “Liquidity and Capital Resources” section of the MD&A dated March 8, 2023 for additional information and reconciliations.

Adjusted EBITDA, CROIC and ROCE

Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion and depreciation, adjusted for other non-cash and extraordinary items including unrealized gains and losses on risk management contracts, realized losses on interest rate risk management contracts, share-based compensation and exploration and evaluation expense. Adjusted EBITDA is considered a useful measure by management of the Company to understand and compare the profitability of Pipestone to other companies excluding the effects of capital structure, taxation and depreciation. Adjusted EBITDA is not defined under IFRS and therefore may not be comparable with the calculation of similar measures by other entities and should not be considered an alternative to, or more meaningful than, income (loss) and comprehensive income (loss). Adjusted EBITDA is also used to calculate CROIC. Adjusted EBIT is calculated as adjusted EBITDA less depletion and depreciation. Adjusted EBIT is used to calculate ROCE.

The following table reconciles income (loss) and comprehensive income (loss) to adjusted EBITDA:

	Three months ended December 31,				Year ended December 31,
($ thousands)	2022		2021		2022		2021
	$		$		$		$
Net income and comprehensive income	53,437		51,307		220,117		67,920
Deferred income tax expense	13,301		15,315		64,082		22,524
Financing expense	8,298		6,018		27,070		22,815
Unrealized (gain) loss on interest rate risk management contracts	425		(671	)	(1,073	)	(1,677	)
Realized loss on interest rate risk management contracts	(547	)	271		(543	)	1,038
D&D expense	35,170		18,560		93,686		66,014
E&E expense	725		-		2,383		1,658
Share-based compensation	812		846		8,336		3,506
Unrealized (gain) loss on commodity risk management contracts	(6,715	)	(27,979	)	(12,106	)	84
Adjusted EBITDA	104,906		63,667		401,952		183,882

CROIC is determined by dividing adjusted EBITDA by the gross carrying value of the Company’s oil and gas assets at a point in time. For the purposes of the CROIC calculation, the net carrying value of the Company’s exploration and evaluation assets, property and equipment and ROU assets, is taken from the Company’s consolidated statement of financial position, and excludes accumulated depletion and depreciation as disclosed in the financial statement notes to determine the gross carrying value.

ROCE is determined by dividing adjusted EBIT by the carrying value of the Company’s net assets. For the purposes for the ROCE calculation, net assets are defined as total assets on the Company’s consolidated statement of financial position less current liabilities at a point in time.

CROIC and ROCE allow management of the Company and others to evaluate the Company’s capital spending efficiency and ability to generate profitable returns by measuring profit or loss relative to the capital employed in the business.

The Company has calculated its CROIC and ROCE using annualized results for the years ended December 31, 2022 and 2021 and balances as at December 31, 2022 and 2021 as follows:

	Three months ended December 31,		Twelve months ended December 31,
($ thousands)	2022	2021	2022	2021
	$	$	$	$
Adjusted EBITDA	104,906	63,667	401,952	183,882
Annualized Adjusted EBITDA(1)	419,624	254,668	401,952	183,882

(1)  Annualized factor 4x for the three months ended December 31, 2022 and 2021. Annualized factor 1.0x for the twelve months ended December 31, 2022 and 2021

		As at December 31,
($ thousands)		2022			2021
		$			$
Exploration and evaluation (E&E) assets – gross carrying value		17,278		29,752
Property and equipment (P&E) – net carrying value		894,851		723,952
P&E – accumulated D&D		206,115		122,779
E&E assets and P&E – gross carrying value		1,118,244		876,483
ROU assets – net carrying value		98,389		82,692
ROU assets – accumulated depreciation		25,317		14,967
E&E, P&E and ROU assets – gross carrying value		1,241,950		974,142
Annualized CROIC (three months ended December 31)		34	%	26		%
Annualized CROIC (twelve months ended December 31)		32	%	19		%

	Three months ended December 31,				Twelve months ended December 31,
($ thousands)	2022		2021		2022		2021
	$		$		$		$
Adjusted EBITDA	104,906		63,667		401,952		183,882
D&D expense	(35,170	)	(18,560	)	(93,686	)	(66,014	)
Adjusted EBIT	69,736		45,107		308,266		117,868
Annualized Adjusted EBIT(1)	278,944		180,428		308,266		117,868

(1)   Annualized factor 4x for the three months ended December 31, 2022 and 2021. Annualized factor 1.0x for the twelve months ended December 31, 2022 and 2021.

		As at December 31,
($ thousands)		2022			2021
		$			$
Total assets		1,098,133		886,168
Total current liabilities		(100,380	)	(94,287		)
Net Assets		997,753		791,881
Annualized ROCE (three months ended December 31)		28	%	23		%
Annualized ROCE (twelve months ended December 31)		31	%	15		%

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 for drilling and completions operations on the 11-09 pad; expected timing for completions operations on the 2-31 and 2-25 pads; the Company’s intention to install a new gathering pipeline to tie the 11-09 pad into the existing 12-14 battery and the timing thereof; the expected timing of increasing the Company’s producing well count; expectations regarding the Company’s 2023 and 2024 guidance and forecast for each of production, cash flow, capital expenditures/development plans, free cash flow, base dividend, net debt and net cash flow; the Company's dividend policy, the quarterly dividend rate, the funding of such dividends, the amounts expected to be paid under the policy and anticipated timing of payment of such dividends; the potential timing of the previously announced substantial issuer bid and the terms thereof; the Company’s ability to produce cash flow at various commodity prices; and the Company’s intention to direct free cash flow to deleveraging towards its run-rate net debt target and to share buybacks.

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, NGLs and natural gas prices with current commodity price forecasts; 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 of the Company'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 manage the Company's 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. Additional risks, uncertainties and other factors are discussed in the MD&A dated March 8, 2023 and in Pipestone’s annual information form dated March 8, 2023, copies of which are available electronically on Pipestone’s SEDAR profile at www.sedar.com.

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.

Advisories Regarding Oil and Gas Information

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.

Initial Production Rates and Short-Term Test Rates

Any references in this news release to test rates of production or initial production rates for certain wells over short periods of time (i.e. IP90 and other short-term periods), 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. Initial production rates indicate the average daily production over the indicated daily period.

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. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Pipestone. Accordingly, Pipestone cautions that the test results should be considered to be preliminary.

Production

References to natural gas and condensate production in this news release refer to the shale gas and natural gas liquids (which includes condensate), respectively, product types as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. References to liquids include tight oil and NGLs (including condensate, butane and propane).

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.

Abbreviations

The following summarizes the abbreviations used in this document:

Crude Oil, Condensate and other Natural Gas Liquids			Natural Gas
bbl	barrel		Mcf	thousand cubic feet
bbls/d	barrels per day		Mcf/d	thousand cubic feed per day
boe	barrel of oil equivalent		MMcf	million cubic feet
boe/d	barrel of oil equivalent per day		Mcf/d	thousand cubic feet per day
NGL	natural gas liquids, consisting of ethane (C2), propane (C3) and butane (C4)		GJ	Gigajoule; 1 Mcf of natural gas is about 1.05 GJ
condensate	Pentanes plus (C5+) separated at the field level and C5+ separated from the NGL mix at the facility level		MMcf/d	million cubic feet per day

Other Abbreviations
Adjusted working capital	working capital (current assets less current liabilities), excluding financial derivative instruments and lease liabilities
AECO	the AECO Hub, a natural gas storage facility located in Suffield and Countess, Alberta, part of the NOVA Pipeline System
C$	Canadian dollars
CROIC	cash return on invested capital
D&D	depletion and depreciation
E&E	exploration and evaluation
EBIT	earnings before interest and taxes
EBITDA	earnings before interest, taxes, depreciation and amortization
G&A	general and administrative
GAAP	generally accepted accounting principles
IFRS	International Financial Reporting Standards
NCIB	normal course issuer bid
P&E	property and equipment
Q1	first quarter ended March 31st
Q2	second quarter ended June 30th
Q3	third quarter ended September 30th
Q4	fourth quarter ended December 31st
ROCE	return on capital employed
ROU	right-of-use
TSX	Toronto Stock Exchange
US$	United States dollars
WTI	West Texas Intermediate