PIPE Pipestone Energy Corporation

(PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to provide an update on its production and operations, as well as report its year-end 2020 independent reserves evaluation prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) with an effective date of December 31, 2020 (the “McDaniel Report”).

Since inception, Pipestone has continued to demonstrate leadership in combining capital cost efficiencies with highly productive wells in the condensate-rich Alberta Montney play. This is reflected in the past year’s significant growth in reserve volumes and continued reduction in future development costs (“FDC”).

2020 Reserve Highlights:

• Pipestone delivered 71% growth in Proved Developed Producing (“PDP”) reserves with a strong recycle ratio of 2.0 times(1). This was achieved during a very challenging year for industry cashflows and capital spending with WTI averaging ~US$39 per barrel and significant volatility in condensate differentials.
• The Company also increased Proved plus Probable reserve volumes by 24% to 228 MMboe, while the associated FDC decreased 16% to $936 million.

Recent Operations Highlights:

• Record Production Volumes: Q4 2020 production averaged 17,734 boe/d (31% condensate, 44% total liquids), the highest quarterly production since inception, and January 2021 production averaged approximately 20,211 boe/d (33% condensate, 46% total liquids);
• 2020 Production Guidance Achieved: 2020 production averaged 15,570 boe/d (30% condensate and 43% total liquids) during our first full year of meaningful operations versus guidance of 15,000 – 16,000 boe/d;
• Lower Montney Test: In January 2021, Pipestone brought on-stream a new Lower Montney well at the 3-12 pad. The 100/05-14-71-8W6 well is 10 km north of our first Lower Montney test and achieved an IP30 rate of 3.3 MMcf/d of raw natural gas and 573 bbl/d of wellhead condensate with an average CGR of 175 bbl/MMcf. This well result is very encouraging and de-risks Lower Montney drilling in the surrounding acreage. This result will be factored into our stacked bench development approach going forward;
• Eastern Step Out Well: In December 2020, Pipestone brought on-stream the 100/03-16-71-7W6 well, previously drilled and completed in 2017, on our 14-4 pad, approximately 5 km east of our main gathering pipeline corridor. The well was drilled in the Montney ‘B’ formation with a short 1,800 metre lateral length. This well produced at an IP60 of 3.0 MMcf/d of raw natural gas and 329 bbl/d of wellhead condensate with an average CGR of 109 bbl/MMcf. These initial results are an important economic validation for our eastern acreage and additional wells from this pad are being incorporated into the development plan;(1) 2020 annual production volumes, capital expenditures and operating netbacks referenced throughout this press release are unaudited.
• Continued Capital Efficiency Gains: The most recent three well pad at 8-15, with an average lateral length of ~3,100 metres, achieved a new pacesetter cost for drilling and completions on a per metre and per tonne placed basis.

Operations Update:

Updated Pipestone Capital Program Map:

A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/350664c8-dd36-4ddb-872f-b102dbf587e1

Production & Facilities:

During Q4 2020, production averaged 17,734 boe/d (31% condensate, 44% total liquids)(1), a quarterly record for Pipestone. During January 2021, production averaged approximately 20,211 boe/d (33% condensate, 46% total liquids)(1) based on field estimates as the six well 3-12 pad was gradually brought on production during the month. January 2021 is the first month Pipestone has exceeded the 20,000 boe/d milestone. In addition to the Lower Montney well previously mentioned at 3-12, the five new Montney B wells are producing at type curve expectations.

(1) See “Advisories” for a further breakdown of constituent production components.

The wellsite facilities for the drilled and completed three well 8-15 pad is currently under construction with expected start-up prior to the end of February.

Additionally, on January 15, 2021 Pipestone commissioned its water disposal and enhanced flow-splitting facility at 3-12. This facility increases Pipestone’s fluid handling capacity while removing existing bottlenecks within the Pipestone gathering system. The facility also enhances the Company’s flexibility to direct flow between different processing facilities and will reduce operating costs.

Drilling & Completions:

Pipestone continues to demonstrate cost reductions in its drilling and completions program. During Q4 2020, the Company completed six wells on its 3-12 pad for an average cost of $3.1 million (2,650 metre lateral length & 2.4 T/M proppant loading). Including the pad-site facilities, all-in DCE&T costs for this pad are $5.4 million per well.

Our most recent pad at 8-15 drilled in late 2020 had an average lateral length of 3,094 metres at a drilling cost of $2.2 million per well. The three wells were completed in January utilizing a proppant intensity of 2.5 T/M for a capital cost of $3.2 million per well. The 8-15 pad is a new pacesetter for Pipestone at a drilling cost of $378 per metre drilled ($711 per lateral meter), and a completion cost of $438 per tonne of proppant placed. Going forward, Pipestone expects to increase the average lateral length of its development wells to approximately 3,000 metres from a previous typical well length of approximately 2,500 metres.

Year-End 2020 Reserve Results:

Key Highlights from the Year-End 2020 McDaniel Report include:

• Proved Developed Producing (“PDP”) reserves increased by 71% from 18.5 MMboe to 31.7 MMboe and achieved a Finding & Development (“F&D”) cost of $5.40/boe, driving a 2020 PDP recycle ratio of 2.0x;
• Total Proved (“1P”) reserves increased by 19% from 112.5 MMboe to 134.0 MMboe and total Proved + Probable (“2P”) reserves increased by 24% from 183.6 MMboe to 227.7 MMboe;
• Decrease in 1P FDC of 19% from $790 million to $640 million, and a ~16% decrease in 2P FDC from $1,114 million to $936 million; F&D costs for these categories are not applicable because of the decrease in FDC;
• Go-forward estimated Undeveloped 1P F&D cost (FDC / Undeveloped Reserves) of $6.33/boe ($8.95/boe at YE 2019) and Undeveloped 2P F&D cost of $5.03/boe ($7.28/boe at YE 2019) reflect the significant reductions in well costs achieved during 2020; and
• Utilizing a 10% discount rate at a flat price deck (US$50/bbl WTI, C$2.50/GJ AECO, $0.785 CADUSD, no inflation), Pipestone estimates a Proved Developed NAVPS of $0.41 per share, a 1P NAVPS of $2.14 per share, and a 2P NAVPS of $3.66 per share.

		December 31, 2020(1)			December 31, 2019(2)
2P Reserve Volumes (Working Interest)		Amount	Weight		Amount	Weight		Change
Condensate / Oil	Mbbls	65,323	29	%	63,553	35	%	3	%
Other NGLs	Mbbls	30,382	13	%	23,354	13	%	30	%
Total Natural Gas Liquids	Mbbls	95,705	42	%	86,907	47	%	10	%
Shale Gas	MMcf	791,801	58	%	580,069	53	%	37	%
Total	Mboe	227,672	100	%	183,585	100	%	24	%
Proved Developed Producing	Mboe	31,735	14	%	18,529	10	%	71	%
Proved Developed Non-Producing	Mboe	1,258	1	%	6,789	4	%	-81	%
Proved Undeveloped	Mboe	100,984	44	%	87,177	47	%	16	%
Total Proved	Mboe	133,977	59	%	112,495	61	%	19	%
Probable	Mboe	93,695	41	%	71,091	39	%	32	%
Total Proved + Probable	Mboe	227,672	100	%	183,585	100	%	24	%

(1) Volumes calculated using the 3 Consultant (“3C”) Average Price Deck as of January 1, 2021. The 3C Price Deck includes pricing forecasts from McDaniel, GLJ Petroleum Consultants, and Sproule.(2) Volumes calculated using the 3C Average Price Deck as of January 1, 2020.

2020 Independent Reserves Evaluation:

McDaniel conducted an independent Reserves Evaluation effective December 31, 2020, which was prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101. The Reserves Evaluation was based on a 3C forecast pricing and foreign exchange rates at January 1, 2021 as outlined in this press release.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. In addition to the information disclosed in this news release, more detailed information will be included in Pipestone Energy’s annual information form for the year ended December 31, 2020, which will be available on the Company’s website at www.pipestonecorp.com and on SEDAR at www.sedar.com on or before March 31, 2021.

Company Gross (before royalties) Working Interest Reserves

	2020 Year-End Reserves (Working Interest)(1)
			Natural Gas	Total
	Tight Oil	Shale Gas	Liquids(2)	Company
Reserve Category	(Mbbl)	(MMcf)	(Mbbl)	(Mboe)
Proved
Developed Producing	26	116,852	12,234	31,735
Developed Non-Producing	-	4,308	540	1,258
Undeveloped	-	341,324	44,096	100,984
Total Proved	26	462,484	56,870	133,977
Total Probable	11	329,317	38,798	93,695
Total Proved + Probable	37	791,801	95,668	227,672

(1) Volumes calculated using the 3C Average Price Deck as of January 1, 2021.(2) Natural Gas Liquids includes condensate volumes. Booked 2P condensate volumes are 65,287 Mbbls as at December 31, 2020.

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

	Before Income Taxes
$C Millions	Discount Factor (% / Year)
Reserve Category	0%			5%			10%			15%			20%
Proved
Developed Producing	$405			$344			$299			$266			$241
Developed Non-Producing	$18			$15			$13			$12			$11
Undeveloped	$1,166			$803			$576			$425			$321
Total Proved	$1,589			$1,612			$888			$703			$573
Probable	$1,316			$776			$503			$352			$260
Total Proved + Probable	$2,904			$1,938			$1,391			$1,055			$833

(1) Calculated using the 3C Average Price Deck as of January 1, 2021.

Future Development Capital and F&D Costs:

FDC reflects McDaniel’s best estimate of what it will cost to bring Pipestone Energy’s proved and probable developed and undeveloped reserves on production. Changes in forecasted FDC occur annually as a result of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, and changes in service costs. Undiscounted 2P FDC at December 31, 2020 decreased by $178 million relative to December 31, 2019, to total $936 million. The year-over-year decrease is driven primarily by capital efficiency improvements related to drilling and completions activities.

			Total Proved
	Total Proved		+ Probable
Year	(C$MM)		(C$MM)
2021	$143		$143
2022	$127		$127
2023	$154		$154
2024	$114		$114
2025	$103		$124
Remainder Thereafter	$0		$274
Total FDC Undiscounted	$640		$936
Total FDC Discounted (10%)	$518		$681

2020 F&D Costs | Recycle Ratio
Proved Developed Producing
Reserve Additions	Mboe	18,889
2020 Capital Expenditures (Estimated)	$MM	$102
F&D per boe	$/boe	$5.40
2020 Operating Netback (Estimated)(1)	$/boe	$10.95
Recycle Ratio		2.0x
Total Proved
Reserve Additions	Mboe	27,165
2020 Capital Expenditures (Estimated)	$MM	$102
2020 Change in FDC	$MM	($150		)
F&D per boe	$/boe	($1.75		)
2020 Operating Netback (Estimated) (1)	$/boe	$10.95
Recycle Ratio		n.m.
Proved + Probable
Reserve Additions	Mboe	49,770
2020 Capital Expenditures (Estimated)	$MM	$102
2020 Change in FDC	$MM	($178		)
F&D per boe	$/boe	($1.52		)
2020 Operating Netback (Estimated) (1)	$/boe	$10.95
Recycle Ratio		n.m.

(1) 2020 Operating Netback (unaudited) is calculated as revenue less realized hedging gains / (losses), less royalties, and less operating and transportation costs. Operating Netback is a non-GAAP measure, see “Advisories” for further details.

1P / 2P Future Undeveloped F&D Costs(1)
Proved Undeveloped
1P Future Development Capital	$MM	$640
Proved Undeveloped Reserves	Mboe	100,984
1P F&D	$/boe	$6.33
Proved + Probable
2P Future Development Capital	$MM	$936
Proved + Probable Undeveloped Reserves	Mboe	185,981
2P F&D	$/boe	$5.03

(1) Excludes FDC in the PDNP category, which was ~$0.8 million as at December 31, 2020.

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

	As at December 31, 2020
	3C Price			Flat Price
$C Millions	Forecast			Deck(1)
2P Reserves, Before-Tax NPV10%	$1,391			$1,211
(-) Abandonment Obligations (Estimated)	($9)			($9)
(-) Mark-to-Market of Hedges(2)	($6)			($6)
(-) Net Debt (Estimated)(3)	($170)			($170)
= Implied Net Asset Value	$1,206			$1,026
Fully Diluted Shares Outstanding (millions)(4)	280			280
Net Asset Value per Share ($/share)	$4.30			$3.66

Note: The above Net Asset Value excludes any additional land value for ~86 net sections of unbooked undeveloped land.

(1) Flat Price Deck utilizes US$50 per barrel WTI, C$2.50 per GJ AECO, and $0.785 CADUSD exchange rate with no future inflation. (2) Hedges include commodity price hedges as at December 31, 2020. (3) Net debt represents bank debt and the addition of working capital and is a non-GAAP measure. See “Advisories” for further details (4) Assumes full dilutive impact of all outstanding warrants, stock options, RSUs, and PSUs, as well as the estimated convertible preferred share balance as at December 31, 2020.

Q4 2020 and Full Year 2020 Financial ResultsConference Call March 10, 20219:00 a.m. MT (11:00 a.m. ET)

Pipestone Energy will host a conference call on March 10, 2021, starting at 9:00 a.m. MT (11:00 a.m. ET). To participate please dial toll free in North America (866) 953-0776 or International (630) 652-5852 and enter 7587763 when prompted. An archived recording of the conference call will be available shortly after the event and will be available until March 19, 2021. To access the replay please dial toll free in North America (855) 859-2056 or International (630) 652-5852 and enter 7587763 when prompted. The conference call will also be archived on the Pipestone Energy Corp website.at www.pipestonecorp.com.

Pipestone Energy Corp.

Pipestone Energy 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 15.6 Mboe/d in 2020 to 34 Mboe/d (midpoint) in 2022, while maintaining a conservative leverage profile. Beginning in 2022, the Company expects to generate annual free cash flow above growth and maintenance expenditures. Pipestone Energy 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 Energy shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.

Pipestone Energy 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 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 Energy may derive therefrom).

In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: additional wells planned for Pipestone’s pad 14-4; completion date for gathering line to Veresen gas plant; on-stream date for pad 8-15; plans for the 2021 capital program; expectations around flow between operating facilities and a reduction of operating costs; an increase in lateral length of its development wells; reserves values and financial returns; FDC and F&D costs; forecasted pre-tax net asset value; expected production growth while maintaining a conservative leverage profile; and expectations to generate free cash flow above growth and maintenance expenditures.

Information and statements regarding Pipestone Energy’s reserves also are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves exist in the quantities predicted or estimated and can be profitably produced in the future.

With respect to the forward-looking statements contained in this news release, Pipestone Energy 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’s and Pipestone Oil’s historical businesses and operations and realize financial, operational and other synergies from the combination transaction completed on January 4, 2019; Pipestone Energy’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 Energy’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 Energy’s future production levels and amount of future capital investment, and their consistency with Pipestone Energy’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone Energy’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone Energy’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone Energy's reserves and other resources; Pipestone Energy’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 Energy’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 Energy’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone Energy conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations to which Pipestone Energy 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 Energy 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 Energy’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 Energy’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 11, 2020 and in Pipestone Energy’s annual information form dated March 17, 2020, copies of which are available electronically on Pipestone Energy’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. 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 Energy 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.

Advisory Regarding Non-GAAP Measures

This news release contains references to “net debt”, “operating netback”, and “free cash flow” which are terms commonly used in the oil and natural gas industry but without any standardized meaning or method of calculation prescribed by International Financial Reporting Standards (“IFRS”) or applicable law. Accordingly, Pipestone Energy’s determination of these metrics may not be comparable to similar measures presented by other issuers.

“Net debt” is a non-GAAP measure that is calculated as long-term debt plus adjusted working capital deficit. 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 financial derivative instruments and the current portion of lease liabilities.

“Operating netback” is a non-GAAP measure that is calculated on a per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales, after adjusting for realized commodity financial derivative instrument gains or losses.

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

“Free cash flow” should not be considered an alternative to, or more meaningful than, cash flow – 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 in the stated period. Free cash flow equals cash flow less capital less capital expenditures.

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.

This presentation contains certain other oil and gas metrics, including DCE&T (drilling, completion, equip and tie-in costs), recycle ratio, F&D and net asset value (or NAVPS), which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. DCE&T includes all capital spent to drill, complete, equip and tie-in a well. Recycle ratio means operating netback divided by F&D costs for the particular reserves category. The calculation of F&D costs includes all exploration and development capital for the year plus the change in future development capital for the year. This total capital including the change in the future development capital is divided by the change in reserves for the year. Net asset value has been calculated based on the estimated net present value of all future net revenue from our reserves, before income taxes, as estimated by McDaniel effective December 31, 2020, see “Pre-Tax Net Asset Value” for more information.

CGR

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

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(bbl/d)	Other NGLs(bbl/d)	Total NGLs(bbl/d)	Crude Oil(1)(bbl/d)	Natural Gas(2)(Mcf/d)	Total (boe/d)
2020 Average Production	4,626	2,002	6,628	102	53,039	15,570
Q4 2020 Average Production	5,493	2,235	7,728	93	59,479	17,734
January 2021(Field Estimate)	6,479	2,709	9,188	103	65,523	20,211

(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”.

Initial Production Rates

This news release includes disclosure on initial production (IP) rates for certain wells. These initial production rates are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Initial production 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 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.