Corporate Presentation

August 2017

All forward looking statements in this Corporate Presentation are qualified in their entirety by the "Forward Looking Information" on slide 24.

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Why Invest in Corridor

• Excellent balance sheet with an estimated working capital balance in excess of $50.0 million

• Long life reserves with minimal future development capital and predictable, low decline natural gas production (~10% annually)

• Superior field operating cash flow netback per boe due to industry leading natural gas pricing at Boston Algonquin City Gates (AGT)

• Solid fundamental core value with exposure to two high impact prospects in Eastern Canada

• Flexibility to take advantage of its balance sheet strength to act on counter-cyclical opportunities in Western Canada

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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

• Robert Penner, CPA, CA Independent Consultant Formerly Senior Tax Partner, KPMG LLP

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• Steve Moran President and CEO, Corridor Resources Formerly President and CEO of Bellamont

Exploration Ltd.

• Jim McKee, CPA, CA Independent Businessman Formerly Senior Vice President, Corporate

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

• Martin Fräss-Ehrfeld Chairman, AVE Capital Limited, provider of

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

Corporate Snapshot

• Stock Symbol – TSX CDH

• Shares Outstanding (2017/03/31) Basic 88,655,299 Diluted (Avg. exercise price $0.78) 92,053,467

• Q1 - 2017 Cash Flow From Operations* $3.7 MM

• Q1 - 2017 Field Operating Netback ($/boe) $39.49

• Tax Pools (2017/03/31) CEE $93.9 MM CDE $61.7 MM Other $23.2 MMTotal $178.8 MM

* 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, 2017.

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Land and Reserves

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

• December 31, 2016 Reserves* MM boe PV@BT10% Proved Developed Producing 2.67 $43.3 million Total Proved 2.75 $45.8 million Total Proved plus Probable 3.45 $54.1 million

• Reserve Life* Years Proved Developed Producing 21 Total Proved 21 Total Proved plus Probable 26

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**Reserve Report dated March 1, 2017 prepared by GLJ Petroleum Consultants effective December 31, 2016.

Net Asset Value Per Basic Share

Reserves valued @ BT10% effective December 31, 2016*

Proved Developed Producing $0.49 Proved Undeveloped $0.03 Probable Developed Producing $0.09 Total Reserve Value $0.61

Working Capital (@ 2017/08/11) $0.58

Total Net Asset value per basic share** $1.19

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* Reserve Report dated March 1, 2017 prepared by GLJ Petroleum effective December 31, 2016. ** Excludes any potential value for undeveloped lands and interests in Anticosti Hydrocarbons L.P..

80% of Corridor’s reserve value is in the Proved Developed Producing Category

Q1 2017 Highlights

• Achieved an industry top decile cash flow from operations of $34.20/BOE, a 26% increase over Q1 2016

• Increased Corridor’s cash flow from operations to $3.683 million in Q1 2017 from $3.353 million in Q1 2016, despite 24% lower average natural gas prices at AGT and 12% lower production rates in Q1 2017 versus Q1 2016

• Corridor achieved these results through a combination of:

successful financial hedges in place during Q1 2017, which resulted in a realized gain of $1.094 million;

a reduction in transportation expenses of $927 thousand from $1.355 million in Q1 2016 to $428 thousand in Q1 2017 as a result of a forward sales agreement to the local Maritime market as opposed to the New England Market; and

higher Canada/US currency exchange gains in Q1 2017

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Q1 2017 Netback AnalysisSuperior Netbacks

Three months ended March 31

thousands of dollars except $/boe (2) 2017 2016Natural gas sales $ 4,166 $ 6,314Realized financial derivatives gain 1,094 -Other revenues 301 181Royalties (92) (137)Transportation expense (428) (1,355)Production expense (789) (717)Field operating netback $ 4,252 $ 4,286Natural gas production per day (mmscfpd) 7.2 8.1Barrels of oil equivalent per day (boepd) 1,196 1,354Average natural gas price ($/mscf) $ 6.45 $ 8.54Natural gas revenues ($/boe) $ 38.69 $ 51.25Realized financial derivatives gain ($/boe) 10.16 -Other revenues ($/boe) 2.80 1.47Royalties ($/boe) (0.86) (1.11)Transportation expense ($/boe) (3.97) (11.00)Production expense ($/boe) (7.33) (5.82)Field operating netback ($/boe) $ 39.49 $ 34.79General and administrative expenses ($/boe) (6.05) (5.85)Interest, foreign exchange gains and other ($/boe) 0.76 (1.73)Cash flow from operations ($/boe) * $ 34.20 $ 27.21

•Cash flow from operations is a non-IFRS 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, 2017.

Understanding Corridor’sPremium Natural Gas Market

• Corridor’s production connected to Maritimes and Northeast Pipeline (MN&P)

• Corridor's gas is priced at Algonquin City-gates (“AGT”)

• There is typically a shortage of natural gas supply capacity for the winter months

• No new major pipeline expansions are anticipated

• Futures market expecting the premium AGT winter pricing to continue to at least 2023

• Sable Island is reaching economic limit rapidly, this will exacerbate the shortfall

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Shifting Maritime Province’s Natural Gas Market

• The Maritime’s primary gas supply has historically been sourced from Sable Island and since 2013, Deep Panuke

• Sable Island nearing end of life, decommissioning is expected to begin in 2018 and take 2 years to complete*

• Deep Panuke experiencing production issues and may not last much longer

• Gas will eventually need to be sourced from USA or Canaport LNG to fulfill demand

• Prices in the Maritimes are already trading at a premium to AGT and expected to go higher once offshore production ends

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

10* Source: Brett Bundale, The Canada Press, April 26, 2017

AGT Futures Pricing Strong for the Foreseeable Future

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• AGT futures pricing* is expected to remain robust to 2023

• Significant premiums over Nymex in the winter months

• Winter peaks still expected to exceed $8.50 US/mmbtu

• Annual average price to 2023 is $4.39 USD/mmbtu

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Nymex Henry Hub AGT Differential AGT Yearly Average Price

*Nymex and Algonquin Basis (i.e. AGT) prices are daily settlement for May 1, 2017 as provided by Intercontinental Exchange (ICE)NG LD1 Futures and NG Basis LD1 for IF Futures.

McCully Field Production Optimization Strategy

• To take advantage of the premium winter pricing at AGT, over the past two years Corridor has strategically shut-in production during the summer/fall months. The resulting build-up in reservoir pressure yielded flush production during winter months (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 employs hedges to protect our winter pricing premium as a component of this strategy. Currently we have 2500 mmbtu/d hedged at $7.40 USD/mmbtu from Dec. 1, 2017 to Mar. 31, 2018

• Corridor has implemented it’s optimization strategy again in 2017/18 by shutting-in the vast majority of its production on April 1, 2017

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Corridor Net Gas Production

Gas Rate Original 2015 Forecast

Production Optimization Strategy

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Strategic shut-in periods

Flush production periods

Higher production rates preserved

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

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

• 43,000 Acre potential oil prospect

* See footnotes on page 19

New Brunswick195,000 Net Acres

Old Harry251,000Net Acres

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

Old Harry Offshore Potential

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

• Basin modeling indicates light oil (~55 API) was initially generated and could be filling the structure

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Controlled Source Electro-Magnetic (CSEM) Survey

• Corridor is planning on purchasing a multi-client CSEM survey over the Newfoundland side of Old Harry. Data acquisition is planned for fall 2017, pending regulatory approvals and survey ship availability.

• Survey time 7-10 days, plus mob/demob time.

• Recording instruments are placed on the sea bottom and an electro-magnetic (EM) source is towed behind a vessel (see right).

• Signals from the EM source travel through the rock formations to the receivers. Anomalously resistive layers (hydrocarbons) will stand-out against a non-resistive background (see figure upper right).

• Modelling shows Old Harry to be an ideal candidate for CSEM imaging.

• A positive CSEM anomaly in a sand/shale sequence provides confidence of hydrocarbon bearing sands.

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CSEM Survey:Newfoundland Side of Old Harry

Old Harry Go Forward Plan

• If the CSEM results are positive, Corridor intends increase efforts to secure a joint venture partner to drill an exploratory well (as of April 2017, estimated at ~$US45 MM)

• Corridor successfully secured a re-issuance of lease EL-1105, commencing in January 2017 for a 4 year term (now EL-1153)

• Strategic Environmental Assessment published by Canada-Newfoundland and Labrador Offshore Petroleum Board in May 2014 concluded that exploration and development activities can be safely undertaken

• Quebec and Canada expected to proceed with mirror legislation to provide for a joint management mechanism that would allow for operations in Quebec waters to begin in a timely matter

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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

54.4 BCF produced to date up to y/e 2016

• Current productive capacity up to ~10 mmcf/d net (flush volumes)

• Frederick Brook has substantial unconventional shale resource potential: Black, hydrocarbon rich shale

that is up to 1100 m thick• Regulatory hurdles exist, currently

under a hydraulic fracturing moratorium

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Corridor’s New Brunswick Facilities at McCully

• Natural Gas Facilities (100% WI) include:

Gas Plant - processing capacity of 35 mmcf/d

50 km of 8” transmission line to Maritimes and Northeast Pipeline

15 kilometers of gathering system

32 producing wells from 11 well pads

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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 to 4,000 m

• Potential for vertical or horizontal development

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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 past 9 years (1.65 Bcf 2P EUR, GLJ)

• Very flat production curve with annual decline <2% annually

• 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

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Frederick Brook Shale Development Potential Next Steps

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• Work towards removal of the hydraulic fracturing moratorium

• Drill 5 vertical evaluations wells• Complete with high volume

water fracture stimulations• Identify “sweet spots” and drill

a second round of horizontal wells

• Establish production and reserves for type curves for vertical versus horizontal wells

• Optimize completion techniques

• Reduce costs, optimize results

Potential Delineation Wells Potential Pipeline

Strategic Priorities

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

• Continue to advance government and stakeholder relations, social responsibility and regulatory agendas in our plays

• Seek opportunities for joint ventures for Old Harry and the Frederick Brook Shale

• Take advantage of Corridor’s balance sheet strength to act on counter-cyclical opportunities in Western Canada

Corridor has sustainability combined with tremendous upside potential

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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; characteristics of Corridor’s properties, maximizing cash flow and value of McCully assets by implementing optimization strategies; continuing to advance government and stakeholder relations; social responsibility and regulatory agendas; seeking opportunities for joint ventures for Old Harry and the Frederick Brook Shale; taking advantage of Corridor’s balance sheet strength to act on counter-cyclical opportunities in Western Canada; exploration and development plans (including the acquisition of the CSEM), including timing of such plans; the benefits of the CSEM data; pipeline development projects and capacity; benefits and timing of pipeline development, natural gas production; potential regional supply basins; expectations of natural gas prices and premiums at AGT and the Maritimes market; daily production, field operating netbacks; expected revenues from hedging agreements; strategic priorities; cash flow from operations; capital expenditures and estimates; working capital estimates; and, the U.S. Canada exchange rate.

• Statements relating to “reserves” 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.

• 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 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, forward sale agreements, as well as assumptions made by, and information currently available to Corridor, including information concerning anticipated financial performance, business prospects, strategies, regulatory developments, 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. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. Unknown risks and uncertainties include, but are not limited to: risks associated with oil and gas exploration, substantial capital requirements and financing, prices, markets and marketing, government regulation, third party risk, environmental, hydraulic fracturing, dependence on key personnel, co-existence with mining operations, availability of drilling equipment and access, risks may not be insurable, variations in exchange rates, expiration of licenses and leases, reserves and resources estimates, development and/or acquisition of oil and natural gas properties, trading of common shares, seasonality, competition, management of growth, conflicts of interest, issuance of debt, title to properties and hedging. Further information regarding these factors and additional factors may be found under the heading "Risk Factors" in the Annual Information Form for the year ended December 31, 2016. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive.

• The forward-looking statements contained in this presentation are made as of the date hereof and the Company 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.

Oil and Gas Disclosure

• 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.

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