PIPE Pipestone Energy Corporation

(PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to report its Q3 2021 financial and operational results, as well as provide an update on its operations.

During Q3 2021, Pipestone delivered a third consecutive record quarter with respect to production, revenue, and cash flow, underpinned by the continued efficient execution of its organic development program. Commencing in Q4 2021, the Company expects to generate significant free cash flow, with forecast annual free cash flow of $140 - $160 million in 2022 and $230 million in 2023 (US$70 WTI | C$3.50 AECO). Pipestone’s first priority use for free cash flow will be to deleverage. Additionally, the Pipestone board has formally approved its application to the TSX to commence a Normal Course Issuer Bid (“NCIB”). Subject to final TSX approval, the Company expects to begin repurchasing shares prior to the end of 2021.

THIRD QUARTER 2021 CORPORATE HIGHLIGHTS:

• In Q3 2021 Pipestone achieved record average quarterly production of 24,704 boe/d (30% condensate, 44% total liquids), a 6% quarterly increase over Q2 2021 and an 80% increase over Q3 2020. The record production was achieved despite a scheduled 10-day outage that occurred in July at one of the Company’s third-party processing plants;
• As a result of its continued production growth combined with improving commodity prices during the quarter, the Company generated record revenue of $100.2 million, more than tripling revenue from Q3 2020 of $31.7 million, and an increase of $17.9 million or 22% from Q2 2021;
• The Company realized a continued improvement in operating netback to a corporate record of $22.01/boe, an increase of 12% over Q2 2021 and a 122% increase over Q3 2020;
• The Company also achieved record adjusted funds flow from operations of $43.7 million ($0.23 per share basic and $0.16 per share fully diluted), almost a seven-fold increase of adjusted funds flow from operations of $6.4 million in Q3 2020, and an increase of $8.2 million or 23% from Q2 2021;
• The Company continued the effective execution of its 2021 capital program with 7 Montney wells drilled and rig-released and 12 wells completed during the third quarter of 2021. Total capital expenditures, including capitalized G&A, were $53.8 million during the three months ended September 30, 2021;
• The Company generated strong returns on invested capital, with Q3 2021 annualized ROCE and CROIC of 17.6% and 21.4%, respectively, as compared to a Q3 2020 annualized ROCE and CROIC of (1.3%) and 6.2%, respectively.

Subsequent to the quarter, and upon the redetermination of its Reserve Based Loan (the “RBL”), Pipestone upsized its borrowing capacity from $225.0 million to $280.0 million. The increased borrowing capacity provides ample liquidity for the current development plan and enables Pipestone the flexibility to explore other opportunities to further enhance shareholder value through accelerated shareholder return strategies or potential future M&A activity.

Pipestone Energy Corp. – Financial and Operating Highlights

	Three months ended September 30,						Nine months ended September 30,
($ thousands, except per unit and per share amounts)	2021			2020			2021			2020
Financial
Sales of liquids and natural gas	$	100,227		$	31,700		$	254,031		$	90,097
Cash from operating activities		34,225			660			86,054			31,552
Adjusted funds flow from operations (1)		43,691			6,359			107,431			29,410
Per share, basic		0.23			0.03			0.56			0.15
Per share, diluted (4)		0.16			0.02			0.38			0.11
Income (loss)		18,757			(11,486	)		16,613			(15,431	)
Per share, basic		0.10			(0.06	)		0.09			(0.08	)
Per share, diluted (4)		0.07			(0.06	)		0.06			(0.08	)
Capital expenditures		53,777			11,806			147,619			60,853
Property acquisitions		8			-			295			-
Adjusted working capital deficit (end of period) (1)							$	(31,814	)	$	(15,934	)
Bank debt (end of period)								187,724			120,477
Net debt (end of period) (1)								219,538			136,411
Undrawn credit facility capacity (end of period)								36,994			103,626
Available funding (end of period) (1)								5,180			87,692
Shareholders’ equity (end of period)								374,573			356,355
Annualized cash return on invested capital (CROIC) (1)		21.4	%		6.2	%		17.9	%		7.9	%
Annualized return on capital employed (ROCE) (1)		17.6	%		(1.3	%)		13.7	%		0.0	%
Shares outstanding (end of period)								191,801			190,572
Weighted-average basic shares outstanding		191,692			190,468			191,353			190,150
Weighted-average diluted shares outstanding (4)		280,480			273,172			279,900			272,945
Operations
Production
Condensate (bbls/d)		7,399			4,265			7,251			4,334
Other natural gas liquids (NGLs) (bbls/d)		3,434			2,196			3,133			1,923
Total NGLs (bbls/d)		10,833			6,461			10,384			6,257
Crude oil (bbls/d)		78			126			84			106
Natural gas (Mcf/d)		82,755			42,683			76,532			50,876
Total (boe/d) (2)		24,704			13,701			23,223			14,842
Condensate and crude oil (% of total production)		30	%		32	%		32	%		30	%
Total liquids (% of total production)		44	%		48	%		45	%		43	%
Benchmark prices
Crude oil – WTI (C$/bbl)	$	88.88		$	54.48		$	81.07		$	51.39
Condensate – Edmonton Condensate (C$/bbl)		89.24			51.74			81.12			47.81
Natural gas – AECO 5A (C$/GJ)		3.40			2.15			3.10			1.99
Average realized prices (3)
Condensate (per bbl)		85.30			48.24			75.89			42.67
Other NGLs (per bbl)		37.15			16.41			30.46			14.57
Total NGLs (per bbl)		70.03			37.42			62.18			34.03
Crude oil (per bbl)		74.05			44.94			67.14			35.66
Natural gas (per Mcf)		3.93			2.28			3.65			2.20
Netbacks
Revenue (per boe)		44.10			25.15			40.07			22.15
Realized (loss) gain on commodity risk
management contracts (per boe) (5)		(6.79	)		(0.31	)		(5.46	)		3.99
Royalties (per boe)		(1.70	)		(0.87	)		(1.20	)		(0.53	)
Operating expenses (per boe)		(10.94	)		(10.26	)		(10.91	)		(10.77	)
Transportation (per boe)		(2.66	)		(3.80	)		(2.67	)		(3.57	)
Operating netback (per boe) (1) (5)		22.01			9.91			19.83			11.27
Adjusted funds flow netback (per boe) (1)	$	19.22		$	5.05		$	16.94		$	7.23

	(1)	See “Non-GAAP measures” in the Advisories for a description.
	(2)	For a description of the boe conversion ratio, see “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, butane and propane).
	(3)	Figures calculated before hedging.
	(4)	Weighted-average number of diluted shares outstanding for the purpose of calculating diluted per share amounts in the 2021 periods presented includes 88,075,674 common shares that are issuable at the discretion of preferred shareholders as of September 30, 2021 for no additional proceeds to the Company. The preferred shares have a total convertible value of $74.9 million at September 30, 2021 and are convertible at $0.85 per common share. The impact of other dilutive instruments is also factored into this calculation as applicable.
	(5)	Realized (loss) gain on commodity risk management contracts reclassified to be included under operating netback for 2021, prior period figures have been adjusted to conform with current presentation.

2021 DEVELOPMENT PROGRAM UPDATE:

During November 2021, Pipestone opportunistically contracted a second drilling rig which has just completed an extended Montney drilling campaign in N.E.B.C. with a large producer. The Company will utilize the second rig to drill 3 wells at the 6-30 pad prior the end of 2021. As a result, Pipestone now expects its full year 2021 capital expenditures to be approximately $180 million, up from $170 - $175 million previously, and will exit 2021 with 9 drilled and uncompleted wells (“DUCs”).

In early November, Pipestone completed the construction and commissioning of the previously announced Veresen-owned and Pipestone-operated 12” gathering pipeline and 6-30 battery. This infrastructure ties Pipestone’s production into the 16-28 compressor station and ultimately to the Veresen Hythe gas plant. Since November 5th, production has been gradually ramping into the new facilities, with corporate production through all our midstream facilities averaging ~31,600 boe/d (33% condensate) over the past 3 days. The Company estimates that November and December 2021 aggregate corporate production will average >30,000 boe/d, with sequential quarterly growth through 2022 until throughput reaches the Company’s total currently available processing capacity of ~40,000 boe/d.

Sustained Capital Cost Performance: The 3 well 14-4 pad achieved an average drilling cost of $2.0 million per well with a pad average lateral length of 2,951 metres and completion cost of $3.4 million with a proppant intensity of 2.8 tonnes per metre. Average all-in DCE&T estimate for the 14-4 pad is $5.9 million per well.

The drilling cost on the 3 new wells at the 6-13 pad averaged $1.7 million per well with an average lateral length of 2,417 metres and completion cost of $2.8 million with a proppant intensity of 2.5 tonnes per metre. At an all-in DCE&T cost of $4.9 million per well, the 6-13 pad represents Pipestone’s lowest per well DCE&T cost delivered to date.

Strong Well Performance: The six well 15-25 pad has achieved an IP90 of 445 bbl/d wellhead condensate and 4.5 MMcf/d raw gas (condensate gas ratio “CGR” of ~100 bbl/MMcf), which is in line with type curve expectations. The three well 8-15 pad has achieved an IP180 of 510 bbl/d wellhead condensate and 3.6 MMcf/d raw gas (CGR of 142 bbl/MMcf). The three well 14-4 pad, and the three well 6-13 pad both have had initial flow tests with very encouraging early time results. Both pads were placed on production in early November, and Pipestone expects to provide additional details once longer-term production data is available.

2022 GUIDANCE & CORPORATE FORECAST UPDATE:(1)

An infographic accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/cf8f45dc-4098-4944-a336-d85febd62e7b

In 2022, Pipestone plans to spend $180 - $200 million, which includes 21 wells drilled, and 24 wells completed, equipped, and brought on production. This capital program is forecast to drive full year average 2022 production of 34,000 – 36,000 boe/d. At the guidance range midpoint, Pipestone forecasts generating cash flow of $340 million and free cash flow of $150 million at US$70 WTI | $3.50 AECO.

	2021Guidance	2022Guidance	2023Forecast
Price Forecast	US$75 WTI | $4.00 AECO | $0.80 CAD	US$70 WTI | $3.50 AECO | $0.80 CAD	US$70 WTI | $3.50 AECO | $0.80 CAD
Full Year Production (boe/d)	24,000 – 26,000	34,000 – 36,000	37,000 – 40,000
AT Cash Flow (C$ MM) (2)	$165 - $180	$330 - $350	$370
Capex (C$ MM) (3)	$180	$180 - $200	$140
Free Cash Flow (C$ MM) (2)	$(10) - $0	$140 - $160	$230
(Net Debt) / Net Cash ($MM) (2)	($180)	($30)	$200 (net cash)
LTM Debt / Cash Flow (x)	1.1x	0.2x	n.a

 

	1)	3-year plan as at November 2021, derived by utilizing, among other assumptions, historical Pipestone production performance and current capital and operating cost assumptions held flat for illustration only. Budgets and forecasts beyond 2022 have not been finalized and are subject to a variety of factors, thus forecast results for 2023 may change materially. Where a range is not provided, guidance and forecast values represent the mid-point estimate. 2021 price forecast is for Q4. Cash flow is calculated net of forecast cash taxes paid; Pipestone does not anticipate cash tax outlays at the above price forecasts until after 2023.
	2)	See “Advisories Regarding Non-IFRS Measures”. Net debt excludes convertible preferred shares as there is no cash settled liability and includes adjusted working capital deficit. Forecast net debt / net cash does not incorporate the impact of any shareholder distributions.
	3)	Capex includes all anticipated DCE&T, infrastructure and other capital expenditures, but excludes capitalized G&A.

Illustrative 2022 Free Cash Flow Allocation:

Pipestone’s first priority is to deleverage the business, with a debt target of less than $100 million, which equates to <1.0x D/CF at a US$45 WTI | $2.00 AECO ($100 million debt balance equates to a run-rate 2022E debt / cashflow of 0.3x at US$70 WTI | $3.50 AECO). Pipestone will commence an NCIB in Q4 2021 to repurchase up to 5% of its basic shares or ~10 million shares over a 12-month period from commencement. This equates to a maximum share repurchase amount of ~$40 million over the next 12 months at Pipestone’s current share price. Excess cash flow will be available for additional shareholder returns, capital to increase the long-term production plateau above 40 Mboe/d, and further debt repayment.

An infographic accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/c44b74fc-75ed-4d1d-a8a4-6a2590a8c5c6

Q3 2021 Financial Statements and Conference Call

Third quarter results are expected to be released before market open on November 10, 2021. A conference call has been scheduled for November 10, 2021 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) 953-0776International: (630) 652-5852Conference ID: 1947358

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 fully funded to grow its production from 25 Mboe/d in 2021 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 shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.

Pipestone Energy Corp. 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 press release includes references to financial measures commonly used in the oil and natural gas industry. The terms “adjusted funds flow from operations”, “cash flow”, “free cash flow”, “operating netback”, “adjusted funds flow netback”, “net debt”, “available funding”, “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 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.

Adjusted funds flow from operations

Pipestone uses “adjusted funds flow from operations” (cash from operating activities before changes in non-cash working capital and decommissioning provision costs incurred), 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 flow

“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, 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’s principal business activities prior to consideration of changes in working capital.

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 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.

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 by total production on a per-boe basis. Adjusted funds flow netback can also be determined by deducting G&A, transaction costs, cash financing expenses, 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” section above for further details.

Operating netback and adjusted funds flow netback are common metrics used in the oil and natural gas industry and are 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.

Available funding and Adjusted working capital

Available funding is comprised of adjusted working capital and undrawn portions of the Company’s RBL. Adjusted working capital 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. The available funding measure allows management and others to evaluate the Company’s short-term liquidity.

CROIC and ROCE

Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion and depreciation, adjusted for certain non-cash and extraordinary items primarily relating to unrealized gains and losses on risk management contracts. Adjusted EBITDA is used to calculate CROIC. Adjusted EBIT is calculated as adjusted EBITDA less depletion and depreciation. Adjusted EBIT is used to calculate ROCE.

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.

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: plans to accelerate capital expenditures and expected DUCs as of year-end; estimated production and increased free cash flow generation; revised 2021 production guidance and outlook; forecasted spending; guidance for 2022 and 2023, including production, capital expenditures, cash flow, free cash flow, reinvestment rate, net debt / net cash and LTDM Debt / Cash flow; plans for the repayment of debt; plans regarding a normal course issuer bid and forecast repurchases thereunder; DCE&T estimate for the 14-4 pad; timing for drilling 21 wells and completing 24 wells, and the associated cost and estimated production dates the connection date of Pipestone’s 6-30 pad to the Veresen Midstream battery and compressor station and the associated increased processing capacity; and plans to complete and equip three additional wells on the 6-30 pad.

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 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 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.

Production

References to natural gas and condensate production in this press 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 natural gas liquids (including condensate, butane and propane).

Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities as disclosed in the following table:

	Condensate(bbls/d)	Other NGLs(bbls/d)	Total NGLs(bbls/d)	Crude Oil (1)(bbls/d)	Natural Gas (2)(MMcf/d)	Total (boe/d)
Last 3 Days Nov 2021(Field Estimate)	10,430	3,790	14,222	n.m. (3)	104	31,600

      (1)   References to crude oil in production amounts are to the product type “tight oil”.      (2)   References to natural gas in production amounts are to the product type “shale gas”.      (3)   NMN – not meaningful number.