Corporate Presentation

November 2019

All forward looking statements in this Corporate Presentation are qualified in their entirety by the "Forward Looking Information" on slides 25 - 26

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Why Invest in Corridor

• Uniquely positioned with significant cash on its balance sheet and a low decline producing natural gas asset that generates free cash flow:

Working capital balance of $62.1 million at the end of Q3 2019, which is forecast to increase to $69.3 million ($0.79 per basic share) by the end of Q1 2020(1)

Long life reserves with minimal future development capital and predictable, low decline natural gas production (~6% annually) with exposure to premium priced natural gas market at Algonquin City Gates (“AGT-CG”)

Forecast Field Operating Netback(2) of $9.4 million from April 1, 2019 to March 31, 2020(1)

• Corridor is currently undertaking a formal strategic review process to explore a wide range of options to ascertain if it can take advantage of its relative strength, with a focus on increasing shareholder value(3)

(1) As per corporate guidance in Corridor’s press release dated November 12, 2019 (“November Guidance”)(2) Field Operating Netback is a non-IFRS measure. See "Non-IFRS Financial Measures" in Corridor’s MD&A for the nine months ended September 30, 2019. (3) See Corridor press release dated October 31, 2019. 2

Board of Directors

• J. Douglas Foster, LL.B., Chairman President, Fostco Holdings

(private investments) Former Partner, Bennett Jones

LLP

• Phil Knoll President, Knoll Energy Inc.

(private consulting company) Former CEO, Corridor

Resources from 2010 to 2015

• Norm Miller Former CEO, Corridor

Resources from 1995 to 2010

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• Steve MoranPresident and CEO, Corridor

ResourcesFormerly President and CEO of

Bellamont Exploration Ltd.

• Jim McKee, CPA, CAIndependent BusinessmanFormerly Senior Vice President,

Corporate Development, Trican Well Service Ltd. and Managing Director, Investment Banking, RBC Dominion Securities

• Martin Fräss-EhrfeldChairman, AVE Capital Limited,

provider of advisory services to the Children's Investment Fund (UK) LLP

Corporate Snapshot

• Stock Symbol – TSX CDH• Shares Outstanding (2019/10/31) Basic 88,147,005 Diluted (Avg. exercise price $0.79) 91,636,671

• Tax Pools (2019/09/30) CEE $99.9 MM CDE $40.4 MM Other $19.8 MM

$160.1 MM• Forecast for period from April 1, 2019 to March 31, 2020(1)

Cash Flow From Operations(2) $7.4 MM Field Operating Netback ($/mscf) $6.93

(1) See November Guidance(2) Cash flow from operations is a non-IFRS financial measure. Cash flow from operations represents net earnings adjusted for non-cash items

including depletion, depreciation and amortization, deferred income taxes, share-based compensation and other non-cash expenses. 4

Land and Reserves

• Undeveloped Land (net acres) 446,000 New Brunswick 195,000 Old Harry - Quebec & NL 251,000

• December 31, 2018 Gross Reserves(1) MM boe NPV@BT10% Proved Developed Producing 3.008 $52.2 million Total Proved 3.008 $52.2 million Total Proved plus Probable 3.715 $60.7 million

• Reserve Life(1) Years Proved Developed Producing 21 Total Proved 21 Total Proved plus Probable 27

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(1) Reserve Report dated March 1, 2019 prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2018.

Net Asset Value Per Basic Share

Reserves valued @ BT10% effective December 31, 2018(1)

Proved Developed Producing $0.59 Probable Developed Producing $0.10 Total Reserve Value $0.69

Working Capital (2019/09/30) $0.70

Total Net Asset value per basic share $1.39

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(1) Reserve Report dated March 1, 2019 prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2018.

86% of Corridor’s reserve value is in the Proved Developed Producing Category

ForecastAGT-CG average natural gas price $3.99US/mmbtu USD/CAD exchange rate 1.30 USD/CADAverage net natural gas price realized $8.85/mscfAverage daily production (calendar day)(1) 3.7 mmscfpdField operating netback $ 9.4 millionCash flow from operations(2) $ 7.4 millionField operating netback per mscf $ 6.93/mscfCash flow from operations(2) per mscf $ 5.44/mscfWorking capital (as of March 31, 2020) $ 69.3 millionCapital Expenditures (for the year 2019) $ 1.1 million

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Market Guidance(April 1, 2019 to March 31, 2020)

(1) Calendar day average production reflects ~7 months of a full field shut-in, the producing day average equates to 7.7 mmcsfpd(2) Cash flow from operations is a non-IFRS financial measure. Cash flow from operations represents net earnings adjusted for non-cash items including depletion, depreciation and amortization, deferred income taxes, share-based compensation and other non-cash expenses.

2019/2020 Hedging Program

PeriodAverage Volume

(mmbtu/d)Price

($US/mmbtu)Winter 2019/2020 Nov. 8 – Nov. 30, 2019 2,500 $4.85Dec. 2019 – Mar. 2020 2,500 $9.00Dec. 2019 – Mar. 2020 2,500 $7.12

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• Hedges represent approximately 55% of Corridor’s estimated production from November 8, 2019 to March 31, 2020 and is expected to secure approximately $6.8 million of revenues.

AGT-CG Futures Pricing Strong Pricing for the Foreseeable Future

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• AGT-CG futures pricing(1) is expected to remain robust to 2024

• Winter peaks range from US$8.40/mmbtu to US$11.00/mmbtu

• Annual average price to 2024 is > US$4.00/mmbtu

• Significant premiums over Nymex Henry Hub in the winter months

(1) Nymex and Algonquin Basis (i.e. AGT - CG) prices are daily settlement for November 8, 2019 as provided by Intercontinental Exchange (ICE), NG LD1 Futures and NG Basis LD1 for IF Futures.

Production Optimization Strategy

• To take advantage of the premium winter pricing at AGT-CG, since 2015, Corridor has strategically shut-in its McCully field production during the summer/fall months. The resulting build-up in reservoir pressure yields flush production during winter months when natural gas prices at AGT-CG are typically higher (see next slide)

• Corridor’s production optimization objectives are threefold: • Generate a similar field operating income with less produced volume than

a continuous production scenario;• Extend reserve life; and • Preserve higher field deliverability rates

• Corridor enters into hedges to protect its winter pricing premium as a component of this strategy.

• Consistent with this strategy, Corridor shut-in all of its production starting on May 1, 2019 and resumed partial production on November 8, 2019 with a ramp-up to full production planned starting in early December 2019.

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Net

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Corridor Net Gas ProductionGas Rate 2015 Continuous Forecast

Flush Production after shut-in’s Timed to capture AGT-CG peak winter pricing

May 2015

6.7mmscf/d

Jan 2019

12.4mmscf/dFlush

productionperiods

Strategic shut-in periods

Note: 2015 historical production forecast included for flush reference and does not represent future plans. 11

Higher production

rates preserved for winter

peak pricing

Q1 2019 Highlights (main producing quarter after shut-in)

• Achieved an industry top decile cash flow from operations netback of $55.92/BOE

• Cash flow from operations of $7.55 million(1)

• Production of 9.0 mmscfpd• The realized gains on financial derivatives increased Corridor’s sales price in Q1 2019 by $3.51/mscf to an average of $10.51/mscf

(1) Cash flow from operations is a non-IFRS financial measure. Cash flow from operations represents net earnings adjusted for non-cash items including depletion, depreciation and amortization, deferred income taxes, share-based compensation and other non-cash expenses. See “Non-IFRS Financial Measures” in Corridor’s MD&A for the three months ended March 31, 2019

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Q1 2019 Netback AnalysisSuperior Netbacks - Key Winter Production Period

Three months endedMarch 31

thousands of dollars except $/boe 2019 2018Natural gas sales $ 5,670 $ 11,506Realized financial derivatives gain (loss) 2,846 (1,078)Other revenues 339 329Royalties (159) (384)Transportation expense (0) (78)Production expense (746) (702)Field operating netback $ 7,950 $ 9,593Natural gas production per day (mmscfpd) 9.0 9.9Barrels of oil equivalent per day (boepd) 1,500 1,653Average natural gas price ($/mscf) $ 7.00 $ 12.90Natural gas revenues ($/boe) $ 42.00 $ 77.36Realized financial derivatives gain (loss) ($/boe) 21.08 (7.25)Other revenues ($/boe) 2.51 2.22Royalties ($/boe) (1.18) (2.59)Transportation expense ($/boe) (0) (0.52)Production expense ($/boe) (5.53) (4.72)Field operating netback ($/boe) $ 58.88 $ 64.50General and administrative expenses ($/boe) (4.46) (4.09)Interest, foreign exchange gains and other ($/boe) 1.50 4.44Cash flow from operations ($/boe) * $ 55.92 $ 64.85

•Cash flow from operations is a non-IFRS measure. Cash flow from operations represents net earnings adjusted for non-cash itemsincluding depletion, depreciation and amortization, deferred income taxes, share-based compensation and other non-cash expenses.See "Non-IFRS Financial Measures" in Corridor’s MD&A for the three months ended March 31, 2019.

Shut-in Strategy Results

Strategic summer/fall shut-ins of the McCully Field have been conducted since 2015 at durations ranging from three to eight months.

All four shut-in periods were successful at securing field operating netback (FOI) near to or greater than the forecast continuous production case.

In total, the four shut-ins deferred an estimated 2.6 BCF of gas for future sales, while earning an estimated $4.1 million more FOI than would have resulted from forecast continuous production.

The 2.6 BCF in deferred volume is more than one full year of typical continuous production!

Winter Shut-inDuration months

FOI (est.)Continuous Production

Case $, millions

FOI (Actual)Shut-in Case

$, millions

Produced Volume (Actual)

Mscf

Deferred Volume

(Estimate)Mscf

2018/2019 6.5 $9.4 $11.4 1465 822

2017/2018 8 $8.4 $10.8 1153 940

2016/2017 3 $7.3 $7.2 2025 234

2015/2016 6 $6.7 $6.5 1635 600

Total $31.8MM $35.9MM 6.3 BCF 2.6 BCF

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Atlantic Canada Natural Gas Supply Shortage

Deep Panukeproduction

permanently shut-in

May 2018

Sable production

permanently shut-in

Dec 2018Atlantic Canada DemandAverage ~150 mmscf/d

Supply shortfall

140mmscf/d

Corridor’s McCully Field Production10mmscf/d

• The Maritimes’ primary gas supply has historically been Sable Island and Deep Panuke

• The majority of the supply now flows north from the USA

• Natural Gas in the Maritimes is traded at a premium to AGT-CG.

• Corridor’s assets are uniquely situated to capture this market opportunity

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Two High Impact Prospects

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New Brunswick

• Frederick Brook Shale

• Unconventional gas prospect

• Regulatory hurdles exist, currently under a hydraulic fracturing moratorium

Old Harry • One of the

largest Canadian East Coast offshore geological structures

New Brunswick195,000 Net Acres

Old Harry251,000Net Acres

Focused on de-risking two high-impact prospects with considerable upside potential while demonstrating prudent financial management

New Brunswick Assets

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• Approximately 195,000 net acres• McCully natural gas production:

Hiram Brook formation produces from conventional tight sandstone reservoirs

59 BCF produced to date • Daily net flush production

deliverability of 10-14 mmscf/d• Frederick Brook has substantial

unconventional shale resource potential: Black, hydrocarbon rich shale that

is up to 1100 m thick 52.7 tscf gross (48.2 tscf net) best

estimate total unriskedundiscovered unrecoverable petroleum-initially-in-place(1)

NB

NS

PEI

*(1) Resources study dated March 1, 2017 and re-affirmed March 1, 2019 prepared by GLJ Petroleum Consultants Ltd. For definition of petroleum-initially-in-place see “Oil and Gas Disclosure – Resources” on slide 26.

Corridor’s New Brunswick Facilities at McCully

• Natural Gas Facilities (100% WI) include: Gas Plant - processing

capacity of 35 mmcf/d 49 km of 8” transmission line

to Maritimes and Northeast Pipeline with 75 mmcf/d capacity

15 kilometers of gathering system

32 producing wells from 11 well pads

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NB

NS

PEI

Frederick Brook Shale

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• 13 wells drilled into the Frederick Brook shale to date

• Frederick Brook shale mapped over wide area –in excess of 20 kilometers laterally

• Depth to top Frederick Brook ranges from 1,600 m to 4,000 m

• Potential for vertical or horizontal development

• A Provincial-wide hydraulic fracturing moratorium currently exists, but NB Government undertaking a process to potentially exempt Corridor's lands

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F-58 Shale Production

Frederick Brook Shale Production History

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• F-58 production at ~180 mcf/d for several years (1.65 Bcf 2P EUR, GLJ)

• Very flat production curve with annual decline <2%

• 2014 wells have proved productivity and reserves

• All producing Frederick Brook wells have small single fracs to date

• G-41 well in Elgin tested up to 12 mmcf/d (1200psi WHP)

• Encountered interbedded sands with high deliverability

• Potential to occur elsewhere in field

Stable Rate180 mcf/d

05001000150020002500300035004000

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G-41 Upper Zone TestsTest 1 - Gas RateTest 2 - Gas RateTest 1 - WHPTest 2 - WHP

12mmscf/d

4mmscf/d

Increasing flush with each field shut-in

Frederick Brook Shale Development Potential Next Steps

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• Continue to advocate for an end to the hydraulic fracturing moratorium on our exploration licences

• Seek clarity on the overall regulatory process, consistent with other oil and gas jurisdictions

• Once regulatory matters have been resolved, initiate a process to market the Frederick Brook to potential joint venture partners.

Potential Delineation Wells Potential Pipeline

Old Harry Offshore Potential

• One of the largest undrilled geological structures in Eastern Canada (43,000 acres/67 sq miles) under four-way closure

• Several direct hydrocarbon indicators identified: satellite seepage slicks, frequency anomalies, amplitude anomalies, and AVO anomalies

• Over 1,000 km of modern 2-D seismic

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Old Harry Go Forward

• Corridor has determined that a 3-dimensional (3-D) seismic survey over the entire structure (i.e. Both Newfoundland and Quebec) is necessary to adequately de-risk the prospect.

• Corridor’s request for an extension of Exploration Licence 1153 in Newfoundland waters has been denied by the C-NLOPB.

• Corridor’s land tenure on the Quebec side of Old Harry structure continues indefinitely, though activity in Quebec oil and gas waters are prohibited as they are not specifically provided for via regulation.

• Corridor has suspended all further capital and technical work.

• Corridor expects Exploration Licence 1153 to expire on January 15, 2021 without undertaking any further exploration activities.

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Strategic Priorities

• Maximize cash flow and value of McCully assets by implementing optimization strategies unique to the Northeast U.S. and Maritimes gas markets

• Nurture constructive government and stakeholder relations in our key plays and operating areas

• Once the New Brunswick moratorium on hydraulic fracturing is lifted and the regulatory process becomes clear and is consistent with other oil and gas jurisdictions, undertake a marketing process to attract third parties to joint venture on our Frederick Brook shale prospect

• Complete a comprehensive strategic review to explore a wide range of options to ascertain if it can take advantage of its unique position of relative strength, with a focus on increasing shareholder value

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Forward Looking Information • This presentation contains certain forward-looking statements and forward-looking information (collectively referred to herein as "forward-looking statements") within

the meaning of Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking information typically contains statements with words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should", “assume” or similar words suggesting future outcomes. In particular, this presentation contains forward-looking statements pertaining to the following: Corridor's business plans and strategies, including its undertaking of a strategic review process, adopting a production optimization strategy (including shutting-in production), maximizing cash flow and value of the McCully assets, nurturing constructive government and stakeholder relations (advocating the lifting of the hydraulic fracturing moratorium and more clarityon regulatory regime in New Brunswick), attracting joint venture parties for the Frederick Brook shale, and the benefits of such strategies; exploration and development plans, including marketing the Frederick Brook and conducting a 3D seismic over Old Harry; characteristics of Corridor’s properties; rates of decline and future development costs; market conditions (including natural gas demand and pipeline capacity); expectations regarding the hydraulic fracturing moratorium in New Brunswick; expectations of natural gas prices and premiums; natural gas production, natural gas sales, USD/CAD exchange rate, cash flow from operations; field operating netbacks, capital expenditures in 2019, and working capital as at March 31, 2020.

• Statements relating to “reserves” and “resources” are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

• The forward-looking statements contained in this presentation are made as of the date hereof and Corridor does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based (including any development plans or plans to find joint venture partners to develop properties) will in fact be realized. Actual results will differ, and the difference may be material and adverse to Corridor and its shareholders.

• Forward-looking statements are based on Corridor’s current beliefs as well as assumptions made by, and information currently available to, Corridor concerning anticipated financial performance, business prospects, strategies, regulatory developments, future natural gas and oil commodity prices, exchange rates, future natural gas production levels, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market natural gas successfully to current and new customers, the impact of increasing competition, the ability to obtain financing on acceptable terms, the ability to add production and reserves through development and exploration activities, and the terms of agreements with third parties such as Corridor’s hedging contracts. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties (both general and specific) and risks that forward-looking statements will not be achieved. These factors include, but are not limited to, risks associated with oil and gas exploration, development and production, operational risks, development and operating costs, substantial capital requirements and financing, volatility of natural gas and oil prices, government regulation, environmental, hydraulic fracturing, third party risk, dependence on key personnel, co-existence with mining operations, availability of drilling equipment and access, variations in exchange rates, expiration of licenses and leases, reserves and contingent resource estimates, trading of common shares, seasonality, disclosure controls and procedures and internal controls over financial reporting, competition, conflicts of interest, issuance of debt, title to properties, hedging, information systems, litigation and aboriginal land and rights claims. Further information regarding these factors may be found under the heading "Risk Factors" in Corridor’s Annual Information Form for the year ended December 31, 2018. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive.

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Oil and Gas DisclosureOIL AND GAS DISCLOSURE

Barrels of oil equivalent• The term "BOE" refers to barrels of oil equivalent. All calculations converting natural gas to crude oil equivalent have been made using a ratio of six MSCF of natural gas to one

barrel of crude equivalent. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six MSCF of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Reserves• Reserves data in this presentation has been estimated by GLJ Petroleum Consultants Ltd. (“GLJ”) in its report dated March 1, 2019 with a preparation date of February 14, 2019

and an effective date of December 31, 2018 setting forth certain information relating to certain natural gas, shale gas and natural gas liquids reserves of Corridor's properties, specifically the McCully Field, and the net present value of the estimated future net revenues associated with such reserves.

Resources• The total unrisked undiscovered unrecoverable petroleum-initially- in-place was estimated by GLJ its resource study dated March 1, 2017 and effective December 31, 2016 and

reconfirmed in March 2019, (the “Frederick Brook Resource Study”), which provides a best estimate of 52.7 tscf gross lease (48.2 tscf net to Corridor’s working interest) of total unrisked undiscovered unrecoverable PIIP in respect of the Frederick Brook Shale in New Brunswick. The probability that the quantity actually in place is equal to or greater than the estimate is 50%. This estimate was determined using probabilistic methods consistent with the COGE Handbook. Gross rock volumes estimates were derived from geophysical interpretation of seismic data and distributions for petrophysical parameters were derived from available log data. The estimates and distributions were then input and analyzed in a probabilistic model to account for uncertainty of the in-place volumes. The Frederick Brook Resource Study does not estimate quantities of petroleum that may become recoverable in the future. The volumes are not classified further than total PIIP, as an established technology for commercial development has yet to be demonstrated, and there is not a development plan with which recoverable volumes can be associated. Significant uncertainties exist for the project due to political and regulatory risk, timing, availability of capital, development area uncertainty, and inability to determine appropriate technical and commercial feasibility. As the resources cannot be placed in a classification other than PIIP, they are unrisked. The substantial in-place resources and the high working interest position of Corridor are the most significant positive factors related to the estimate of PIIP. The development of resource plays such as the Marcellus and Utica in the Northeast United States may provide a substantial natural gas supply to the New Brunswick region, following the expected reversal of the M&NP pipeline. This supply may suppress the commercial viability of Frederick Brook shale.

• "total petroleum initially-in-place" or "PIIP", the equivalent of "total resources", refers to that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

• "undiscovered petroleum initially-in-place", the equivalent of "undiscovered resources", refers to that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially-in-place is referred to as prospective resources, the remainder as unrecoverable.

• "undiscovered unrecoverable petroleum initially-in-place", the equivalent of "undiscovered unrecoverable resources", means that portion of undiscovered petroleum initially-in-place which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

• For more information regarding Corridor’s reserves and resources, readers should refer to Corridor’s Annual Information Form for the year ended December 31, 2018.

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