Pipestone Energy Corp. Announces Second Quarter 2023 Results, Provides an Operations Update and Transaction Update

Pipestone Energy Corp.

Development Map

Development Map

CALGARY, Alberta, Aug. 09, 2023 (GLOBE NEWSWIRE) -- (PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to report its second quarter 2023 financial and operational results, as well as an update on the previously announced proposed transaction between Pipestone and Strathcona Resources Ltd. (“Strathcona”) pursuant to which Strathcona has agreed, subject to satisfaction of certain closing conditions, to acquire all the issued and outstanding common shares of Pipestone for 100% share consideration (the “Transaction”). Pursuant to the Transaction, Strathcona and Pipestone will be amalgamated and will continue as “Strathcona Resources Ltd.” (“AmalCo”). Upon completion of the Transaction, existing Pipestone shareholders will receive approximately 9.05% of the equity in AmalCo on a fully diluted basis (approximately 8.87% basic), equating to an exchange ratio of 0.067967 AmalCo shares per Pipestone share. AmalCo is expected to become a public reporting issuer in Canada following completion of the Transaction. For further details regarding the Transaction, refer to the joint press release dated August 1, 2023 and the material change report of Pipestone in connection with the Transaction, which is or will be available under Pipestone's SEDAR+ profile at www.sedarplus.ca.

SECOND QUARTER 2023 CORPORATE HIGHLIGHTS

• During Q2 2023, Pipestone delivered strong quarterly average production of 33,143 boe/d (41% liquids), despite the impact of the Alberta Wildfires in May 2023, with June 2023 setting a monthly record of 37,327 boe/d (42% liquids). The cumulative production impact of the wildfires was approximately 11,000 boe/d in May 2023 or 3,700 boe/d in Q2 2023. Forecast 2023 production remains on track to meet the Company’s guidance range of 34,000 – 36,000 boe/d;

• The Company delivered adjusted funds flow from operations⁽¹⁾ of $53.4 million ($0.19 per basic and diluted share) in Q2 2023, which represents a decrease of $57.0 million or 52% from its Q2 2022 adjusted funds flow from operations⁽¹⁾ of $110.4 million ($0.58 per basic share and $0.39 per diluted share) in Q2 2022, as a result of weaker realized commodity prices;

• Pipestone continued to generate positive returns on invested capital with Q2 2023 annualized ROCE⁽¹⁾ and CROIC⁽¹⁾ of 17% and 9%, respectively, as compared to Q2 2022 annualized ROCE⁽¹⁾ and CROIC⁽¹⁾ of 44% and 41%, respectively, impacted by lower year-over-year commodity prices;

• The Company’s capital expenditures in 2023 were front-loaded in 2023, as a result of delineation spending, as well as to provide surety on full year production guidance. In Q1 and Q2 2023 a significant portion of the 2023 capital budget was utilized to drill 16 of 27 planned wells (59%), complete 17 of 23 planned wells (74%) and invest in various infrastructure projects. The capital investment of $170.5 million, before capitalized G&A, in the six months ended June 30, 2023, represents 67% of the full year budget (using the $255.0 million mid-point of guidance);

• Pipestone successfully renewed its reserve-based loan (“RBL”) in Q2 2023 with the $280.0 million borrowing base and available capacity maintained. The maturity date of the RBL was extended to May 30, 2025. The Company exited the second quarter of 2023 with a net debt⁽¹⁾ balance of $172.4 million (June 30, 2022 - $191.6 million) and a draw of $138.3 million against its RBL. The Company’s ratio of net debt⁽¹⁾ to annualized trailing quarter adjusted funds flow from operations⁽¹⁾ at June 30, 2023 was 0.8 times (June 30, 2022 – 0.4 times) which demonstrates the continued strength of Pipestone Energy’s financial position;

• On August 9, 2023, the Company’s board of directors declared its third quarterly dividend of $0.030 per common share, which will be payable on September 29, 2023, to shareholders of record at the close of business on September 15, 2023.

Pipestone Energy Corp. – Financial and Operating Highlights

	Three months ended June 30,						Six months ended June 30,
(CAD$ thousands, except where otherwise noted)	2023			2022			2023				2022
Financial
Sales of liquids and natural gas	$	121,346		$	210,380		$		270,355		$	363,910
Cash from operating activities		40,957			129,599				118,957			193,611
Adjusted funds flow from operations(1)		53,359			110,438				138,240			196,755
Per share, basic		0.19			0.58				0.49			1.03
Per share, diluted		0.19			0.39				0.49			0.69
Capital expenditures, including capitalized G&A		64,845			77,790				172,341			155,749
Free cash flow (deficit)(1)		(11,486	)		32,648				(34,101	)		41,006
Income and comprehensive income	$	15,240		$	82,095		$		46,122		$	109,147
Per share, basic		0.05			0.43				0.17			0.57
Per share, diluted		0.05.			0.29				0.16			0.39
Adjusted EBITDA(1)		58,826			115,044				148,173			206,083
Annualized cash return on invested capital (CROIC)(1)		9	%		41	%			15	%		37			%
Annualized return on capital employed (ROCE)(1)		17	%		44	%			21	%		39			%
Net debt(end of period)(1)							$		172,394		$	191,563
Net debt to annualized adjusted fund flow from operations for the trailing period(1)		0.8x			0.4x				0.6x			0.5x
Available funding(end of period)(1)									107,024			87,623
Dividends paid per share	$	0.03		$	-		$		0.06		$	-
Dollar amount purchased under NCIB		-			14,049				-			21,230
Number of common shares purchased under NCIB(000s)		-			2,826				-			4,311
Common shares outstanding(000s) (end of period)									279,638			188,437
Weighted-average basic shares outstanding(000s)		279,568			190,224				279,408			190,862
Weighted-average diluted shares
outstanding(000s)		282,074			285,966				281,960			286,563
Operations
Production
Condensate(bbls/d)		9,337			8,428				9,514			8,197
Other natural gas liquids (NGLs)(bbls/d)		3,978			4,137				4,209			4,000
Total NGLs(bbls/d)		13,315			12,565				13,723			12,197
Crude oil(bbls/d)		253			79				301			56
Natural gas(Mcf/d)		117,449			108,754				120,738			101,590
Total(boe/d)(2)		33,143			30,770				34,147			29,185
Condensate(mix of total production)		28	%		28	%			28	%		28			%
Total liquids(mix of total production)		41	%		41	%			41	%		42			%
Average realized prices(3)
Condensate(per bbl)	$	93.06		$	133.44		$		97.36		$	127.61
Other NGLs(per bbl)		34.20			61.18				38.27			58.44
Total NGLs(per bbl)		75.47			109.65				79.24			104.93
Crude oil(per bbl)		89.78			128.74				91.33			121.61
Natural gas(per Mcf)		2.61			8.50				3.14			7.13
Netbacks
Revenue(per boe)	$	40.23		$	75.13		$		43.74		$	68.89
Realized gain (loss) on commodity risk
management contracts(per boe)		1.00			(10.51	)			1.91			(7.89			)
Royalties(per boe)		(3.28	)		(5.96	)			(3.63	)		(5.14			)
Operating expense(per boe)		(13.57	)		(12.88	)			(13.53	)		(12.01			)
Transportation expense(per boe)		(3.87	)		(3.81	)			(3.56	)		(3.89	)
Operating netback(per boe)(1)		20.51			41.97				24.93			39.96
Adjusted funds flow netback (per boe) (1)		17.69			39.44				22.37			37.25

⁽¹⁾  See “Advisory Regarding 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”. 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.

Q2 2023 Operations Update:

Development Map

A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/6a10eed9-f3aa-45c5-b612-e8df8851fe87

During the second quarter, Pipestone continued to execute its development program. Total drilling capital was $19.6 million in the quarter. The Company drilled and rig-released a single well from the existing 14-14 pad-site located south of the Wapiti River, five additional wells at the 14-19 pad, as part of the second phase of operations, and one delineation well from its northern 15-34 pad, for a total of seven wells. The Company incurred completion costs of $26.5 million in the quarter, which includes its two southeastern delineations wells at the 11-09 pad and the 14-14 pad single well, for a total of three wells. Pipestone also invested $14.7 million in production equipment and facilities which included the equipping and tie-in of the 14-14 pad single well and a portion of the construction of a pipeline connecting the 11-09 pad to the 12-14 battery which remained in progress at the end of the quarter.

Delineation Update:

During 2023, Pipestone is spending approximately $45 million of its $245 - $265 million capital budget on high impact delineation activities, which includes four step-out wells drilled and completed, as well as significant gathering system additions. In June 2023, the Company brought the delineation well drilled off the 14-14 pad (south of the Wapiti River) on production. The well was drilled with a short lateral length of approximately 1,900 meters and has delivered an IP60 of 1.6 MMcf/d raw gas and 394 bbl/d of condensate which equates to a CGR of 241 bbl/MMcf. Future adjacent wells are expected to scale linearly to Pipestone’s typical well length of greater than 3,200 metres. In addition, the two new wells drilled and completed earlier this year off the 11-09 pad will begin flowback operations into the 12-14 battery, once the new gathering pipeline is complete in September 2023. Flowback operations on the 15-34 pad delineation well has just commenced, with meaningful production results expected over the next few months.

Transaction Update:

The Company has called a special meeting of holders of common shares (“Shareholders”) of Pipestone to be held on September 27, 2023 (the “Meeting”), to approve the Transaction. The record date for the Meeting is set as of August 25, 2023. The board of directors of Pipestone has approved the Transaction and it will recommend that Shareholders vote in favour of the Transaction at the Meeting.

Pipestone has retained Kingsdale Advisors as its strategic shareholder advisor and proxy solicitation agent in connection with the Meeting. Shareholders with questions are encouraged to contact Kingsdale Advisors by telephone at 1-877-659-1824 (North American Toll Free) or 416-623-2514 (Outside North America).

Q2 2023 Financial Results Conference Call Details:

A conference call has been scheduled for August 9^th, 2023 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time) for interested investors, analysts, brokers, and media representatives.

Please use the following participant URL to join the Q2 2023 financial results conference call: https://register.vevent.com/register/BI803001b7727c445f98bfa56893ebd7c6. 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 EO100^TM Standard for Responsible Energy Development. Pipestone shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.

Pipestone Contacts:

Dustin Hoffman Chief Operating Officer and Interim President and Chief Executive Officer (587) 392-8423 dustin.hoffman@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 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 three and six months ended June 30, 2023 dated August 9, 2023, a copy of which is available electronically on Pipestone’s SEDAR+ profile at www.sedarplus.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 Energy 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 Energy’s principal business activities prior to consideration of changes in working capital, decommissioning provision costs incurred and cash share-based compensation.

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

	Three months ended June 30,				Six months ended June 30,
($ thousands)	2023	2022			2023	2022
	$	$			$	$
Cash from operating activities	40,957	129,599			118,957	193,611
Change in non-cash working capital	12,388	(23,456	)		19,208	(1,151	)
Decommissioning provision costs incurred	14	-			75	-
Cash share-based compensation	-	4,295			-	4,295
Adjusted funds flow from operations	53,359	110,438			138,240	196,755

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 expense 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 June 30,					Six months ended June 30,
($ thousands)	2023		2022			2023		2022
	$		$			$		$
Sales of liquids and natural gas	121,346		210,380			270,355		363,910
Realized gain (loss) on commodity risk management contracts	3,020		(29,431	)		11,806		(41,684	)
Royalties	(9,899	)	(16,698	)		(22,409	)	(27,147	)
Operating expense	(40,939	)	(36,053	)		(83,619	)	(63,418	)
Transportation expense	(11,671	)	(10,660	)		(21,973	)	(20,572	)
Operating netback	61,857		117,538			154,160		211,089

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

	Three months ended June 30,					Six months ended June 30,
($ thousands)	2023		2022			2023		2022
	$		$			$		$
Cash from operating activities	40,957		129,599			118,957		193,611
Change in non-cash working capital	12,388		(23,456	)		19,208		(1,151	)
G&A expense	3,031		2,494			5,987		5,006
Cash share-based compensation	-		4,295			-		4,295
Cash financing expense	5,467		4,547			10,575		9,056
Decommissioning provision costs incurred	14		-			75		-
Realized (gain) loss on interest rate risk management contracts	-		59			(642	)	272
Operating netback	61,857		117,538			154,160		211,089
G&A expense	(3,031	)	(2,494	)		(5,987	)	(5,006	)
Cash financing expense	(5,467	)	(4,547	)		(10,575	)	(9,056	)
Realized gain (loss) on interest rate risk management contracts	-		(59	)		642		(272	)
Adjusted funds flow netback	53,359		110,438			138,240		196,755

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, cash financing expense 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 above 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 RBL. The available funding measure allows management 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 Pipestones MD&A dated August 9, 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, decommissioning provision costs incurred and cash share-based compensation, 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 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 Energy’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 June 30,				Six months ended June 30,
($ thousands)	2023	2022			2023	2022
	$	$			$	$
Cash from operating activities	40,957	129,599			118,957	193,611
Change in non-cash working capital	12,388	(23,456	)		19,208	(1,151	)
Decommissioning provision costs incurred	14	-			75	-
Cash share-based compensation	-	4,295			-	4,295
Cash flow	53,359	110,438			138,240	196,755

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 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, decommissioning provision costs incurred and cash share-based compensation less capital expenditures.

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

	Three months ended June 30,					Six months ended June 30,
($ thousands)	2023		2022			2023		2022
	$		$			$		$
Cash from operating activities	40,957		129,599			118,957		193,611
Change in non-cash working capital	12,388		(23,456	)		19,208		(1,151	)
Capital expenditures	(64,845	)	(77,790	)		(172,341	)	(155,749	)
Decommissioning provision costs incurred	14		-			75		-
Cash share-based compensation	-		4,295			-		4,295
Free cash flow	(11,486	)	32,648			(34,101	)	41,006

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. 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 Pipestones MD&A dated August 9, 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 gains and losses on interest rate risk management contracts, share-based compensation and E&E expense. Adjusted EBITDA is considered a useful measure by management to understand and compare the profitability of Pipestone Energy 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 and comprehensive income to adjusted EBITDA:

	Three months ended June 30,					Six months ended June 30,
($ thousands)	2023		2022			2023		2022
	$		$			$		$
Net income and comprehensive income	15,240		82,095			46,122		109,147
Deferred income tax expense	4,549		25,085			15,161		32,663
Financing expense	5,798		6,150			11,258		12,240
D&D expense	34,217		19,807			69,972		37,750
Share-based compensation	1,318		4,641			2,731		6,077
Unrealized (gain) loss on commodity risk management contracts	(2,296	)	(23,031	)		2,108		8,582
E&E expense	-		829			829		829
Unrealized loss (gain) on interest rate risk management contracts	-		(591	)		634		(1,477	)
Realized (gain) loss on interest rate risk management contracts	-		59			(642	)	272
Adjusted EBITDA	58,826		115,044			148,173		206,083

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 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. Also refer to the “Liquidity and Capital Resources” section of Pipestones MD&A dated August 9, 2023 for additional information.

The Company has calculated its CROIC and ROCE using annualized results for the three and six months ended June 30, 2023 and 2022 and balances as at June 30, 2023 and 2022 as follows:

	Three months ended June 30,			Six months ended June 30,
($ thousands)	2023	2022		2023	2022
	$	$		$	$
Adjusted EBITDA	58,826	115,044		148,173	206,083
Annualized Adjusted EBITDA(1)	235,304	460,176		296,346	412,166

(1)   Annualized factor 4x for the three months ended June 30, 2023 and 2022. Annualized factor 2x for the six months ended June 30, 2023 and 2022.

		As at June 30,
($ thousands)		2023		2022
		$		$
Exploration and evaluation (E&E) assets – gross carrying value		17,539		29,033
Property and equipment (P&E) – net carrying value		1,003,984		843,000
P&E – accumulated D&D		269,812		155,687
E&E assets and P&E – gross carrying value		1,291,335		1,027,720
ROU assets – net carrying value		92,401		77,850
ROU assets – accumulated depreciation		31,592		19,809
E&E, P&E and ROU assets – gross carrying value		1,415,328		1,125,379
Annualized CROIC (three months ended June 30)		17	%	41	%
Annualized CROIC (six months ended June 30)		21	%	37	%

	Three months ended June 30,					Six months ended June 30,
($ thousands)	2023		2022			2023		2022
	$		$			$		$
Adjusted EBITDA	58,826		115,044			148,173		206,083
D&D expense	(34,217	)	(19,807	)		(69,972	)	(37,750	)
Adjusted EBIT	24,609		95,237			78,201		168,333
Annualized Adjusted EBIT(1)	98,436		380,948			156,402		336,666

(1)   Annualized factor 4x for the three months ended June 30, 2023 and 2022. Annualized factor 2x for the six months ended June 30, 2023 and 2022.

		As at June 30,
($ thousands)		2023		2022
		$		$
Total assets		1,185,494		1,014,395
Total current liabilities		(110,236	)	(152,336	)
Net Assets		1,075,258		862,059
Annualized ROCE (three months ended June 30)		9	%	44	%
Annualized ROCE (six months ended June 30)		15	%	39	%

Advisory Regarding Forward-Looking Statements

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: the completion of closing of the Transaction; the expected ownership of AmalCo shares to be held by Pipestone Energy shareholders upon completion of the Transaction; the timing and satisfaction of all conditions to completing the Transaction; the anticipated timing of the shareholder meeting to approve the Transaction; the Company's expectation that it will meet the Company's guidance range for production for the remainder of 2023; the Company's ability to maintain its net debt ratio; the Company's dividend policy, the quarterly dividend rate, the amounts expected to be paid under the policy in the future and anticipated timing of payment of such dividends; expectations regarding the company's capital budget and expenditures; the ability of the Company to manage its liquidity risk through its capital structure, cash flow forecasting, available credit and commodity hedging programs; the anticipated flowback operations of the two new wells drilled and completed off the 11-09 pad upon completion; expectations regarding of funding of future expenditures and the Company’s expectations with respect to capital management and liquidity.

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 August 9, 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		condensate	Pentanes plus (C5+) separated at the field level and C5+ separated from the NGL mix at the facility level
bbls/d	barrels per day		Mcf	thousand cubic feet
boe	barrel of oil equivalent		Mcf/d	thousand cubic feed per day
boe/d	barrel of oil equivalent per day		MMcf	million cubic feet
NGL	natural gas liquids, consisting of ethane (C2), propane (C3) and butane (C4)		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
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
WTI	West Texas Intermediate