2015 Corporate Presentation

May 2015

Corporate Profile

• Stock Symbol – TSX

• Shares Outstanding (2015/04/30) Basic Diluted (Avg. exercise price $1.27)

• Q1 2015 Average production rate

• Q1 2015 Positive working capital

• Q1 2015 Operating cash flow

• Q1 2015 Corporate Netback ($/boe)

• Net Asset Value* (per basic share) Reserves @P+P BT10% (2014/12/31) Working Capital (@ 2015/03/31)

Total

* Excludes undeveloped land value

CDH

88,621,96692,106,132

1,156 boepd

$ 27.9 MM

$ 7.6 MM

$73.13

$1.27$0.31$1.59

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Land and Reserves

• Undeveloped Land (net acres) New Brunswick Anticosti - Quebec Old Harry - Quebec & NL

• December 31, 2014 Reserves (GLJ) Proved Developed Producing Total Proved Total Proved plus Probable

• Decline Rate Proved Proved + Probable

• RLI Proved Proved + Probable

778,000195,000332,000251,000

PV@BT10%MM BOE ($mm)

3.6 $58.2 7.7 $69.2

11.2 $112.9

13.3%/yr11.7%/yr

17 years25 years

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2015 Guidance

• 2015 Production Capacity(1)

• 2015 Cash Flow from Operations

• 2015 Corporate netback ($/boe)

• 2015 Capital Expenditures McCully Old Harry Anticosti* (carried) Corporate Total

• 2015 Year End Working Capital

* Anticosti Hydrocarbons LP 2015 Capital Program (Gross)

1,125 boepd

$8.7 MM

$35.15

$0.4 MM$1.8 MM

$0 MM$0.2 MM$2.4 MM

$27.2 MM

~$13 MM

(1) Reflects corporate production capacity, 2015 production budget is 680 boepd as Corridor has elected to shut-in certain wells for a period from May 1, 2015 to October 31, 2015 as set forth in a press release dated May 1, 2015.

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Board of Directors

• J. Douglas Foster, LL.B., Chairman President of Fostco Holdings (private investments) Former Partner Bennett Jones LLP

• Phill Knoll President of Knoll Energy Inc. (a private consulting company) Former CEO, Corridor Resources from 2010 to 2015

• Norm Miller Former CEO Corridor Resources from 1995 to 2010

• Robert Penner, C.A. Independent Consultant Prior thereto, Senior Tax Partner with KPMG LLP

• Mike Seth Independent Consultant Prior therero, President and Managing Director, McDaniel and Associates

• James McKee Senior Vice President, Corporate Development, Trican Well Service Ltd. Formerly Managing Director, Investment Banking of RBC Dominion Securities

• Martin Fräss-Ehrfeld Chairman of AVE Capital Limited, provider of advisory services to the Children's Investment Fund (UK) LLP

• Steve Moran President and CEO, Corridor Resources Formerly President and CEO of Bellamont Exploration Ltd. 5

Three World Class Prospects

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

* See Disclaimer and forward looking statement

Anticosti (Quebec)330,000 Net Acres

Old Harry251,000Net Acres

New Brunswick195,000 Net Acres

Anticosti• Liquids-Rich

Shale• 31 bboe

gross 6.7 bboe net undiscovered resources (Sproule best estimate*)

• Up to $100 MM program funded by third parties

• Corridor has 21.67% in Anticosti Hydrocarbon L.P.

New Brunswick

• Frederick Brook Shale

• 67 TCF gross discovered unrecoverable resources of shale gas(GLJ best estimate*)

Old Harry • One of the

largest Canadian East Coast offshore geological structures

• 43,000 Acre potential oil prospect

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Anticosti IslandLiquids-Rich Macasty Shale

• Stratigraphic equivalent to Ohio Utica shale

• 30.7 bboe gross undiscovered resources (6.65 bboe net) (Sproule best estimate*)

• Over 1.5 million gross acres licensed (~ 0.3 million net acres)

• Anticosti Hydrocarbon L.P.

Corridor - 21.67%

Corridor carried for up to $100 MM (gross) in exploration costs

Quebec Government is a partner – contributing up to $55.0 MM to project

* See Disclaimer and forward looking statements 7

Anticosti Macasty versus Ohio Utica shale

• Anticosti Island is large enough to cover the productive Utica shale trend.

• Similar to Ohio, Anticosti is in thermal window for oil, liquid rich gas and dry gas

• Oil window is < 1.1 Ro, liquid-rich gas is between 1.1 and 1.4 and dry gas is > 1.4

• Pay thickness, total organic carbon, and clay content are similar in Anticosti and Ohio

• Both contain light oil and NGL’s

• Current production from Ohio Horizontal Wells*: 748 producing wells 1.6 Bcf/d 35,540 bbls/d of oil

Utica Shale Liquids Trend withOverlay of Anticosti Island

* Ohio Dept. of Natural Resources Q4, 2014 8

Anticosti Hydrocarbon L.P. Capital Program Highlights

• Corridor’s cost is carried for 15 stratigraphic coreholes and up to 3 horizontal wells with multi-staged fracture completions

• During 2014, 5 stratigraphic coreholes drilled. Results encouraging

• 10 additional coreholes planned for 2015

• 3 horizontal wells planned to be drilled and fracture stimulated in 2016

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Anticosti Coring Results to Date

• Eight core intersections of the Macasty have been completed since 2012

• Mature source rock with residual Total Organic Carbon (TOC) levels which, on a qualitative scale, are ranked as very good to excellent

• Hydrocarbon concentrations in the rock (S1) which, on a qualitative scale, are ranked as very good

• Porosity that is within an expected range

• Permeability values that indicate the probability of producing hydrocarbons based on comparisons with similar source rocks in productive shales

Macasty Core from Chicotte Corehole

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New Brunswick Assets

• Approximately 195,000 net acres• McCully Natural gas production: productive capacity of 9 mmcf/d

gross (6.5 mmcf/d net)

• Hiram Brook produces from conventional tight sandstone reservoirs

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

up to 1100 m thick 67 TCF (59 TCF net) discovered

unrecoverable resources within assessed area (GLJ best estimate*)

NB

NS

PEI

* See Disclaimer and forward looking statements 11

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 M&NP

Gathering system (15 km of pipe)

32 producing wells from 11 well pads

NB

NS

PEI

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Northeast USAPremium Natural Gas Markets

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

• MN&P connected to premium Northeast U.S. marketCorridor 2014 Average NG

Sale Price - $8.59/mcf (CDN)Corridor winter 2014/15

average NG sale price $13.85/mcf (CDN)

2500 mmbtu/d hedge in place for Nov 2015 to March 2016 at US$9.25/mmbtu

• Expect premium winter market to continue to at least 2018/19

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Connecting Appalachian Gas to the Maritimes

• Numerous greenfield pipelines proposed

• Expect completion by 2018/2019

• M&NP is bi-directional, will be reversed in time

• Significant tolls on new Appalachian pipelines will result in high NG prices for New Brunswick

• Corridor anticipates a $3/mmbtu (CDN) premium to US NE Markets for New Brunswick natural gas

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Long Term East Coast LNG Market Potential for NB Gas

• Connecting Appalachian gas to MN&P (est. 2018/19) will open up LNG export potential on East Coast of Canada.

• Multiple proposals for East Coast LNG Export terminal Canaport facility (Repsol) Bear Head LNG (LNG Ltd.) Melford LNG (Hiranandani

Group) Goldboro LNG (Pieridae)

• Corridor’s lands are ideally positioned to supply LNG export projects

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Frederick Brook ShaleResources Estimates

• Resource estimate (67 TCF gross, GLJ best estimate*) conducted over wide area (120,000 acres)

• Up to 600 bcf/section (GLJ best estimate) due to gross interval up to 1,100 m thick

• Potential for vertical or horizontal development

• 13 wells drilled into FB shale to date

• FB mapped over wide area – potential for at least 1,400 well locations**

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

* See Disclaimer and forward looking statements ** based on vertical wells and 80 acre spacing 16

Frederick Brook ShaleGas tested over 20 KM extent• FB shale is widespread and shale

interval is up to 1100 m thick• 4 producing wells in McCully, 3 of

which came on-stream January, 2015

• 2 Elgin wells flow-tested gas• 6 wells producing or tested gas

from separate stratigraphic intervals

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Frederick Brook Shale Production History

• F-58 production at ~180 mcf/d for past 7 years (1.65 Bcf 2P EUR)

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

• New wells have proved productivity and reserves

• All producing FB wells have small single fracs to date

F-58 Frederick Brook Daily Production

• G-41 in Elgin tested up to 12 mmcf/d

• encountered interbedded sands with high deliverability

• Potential to occur elsewhere in field

2007 2008 2009 2010 2011 2012 2013 2014 2015

1000

100

Mon

thly

Pro

duct

ion

Rat

e (m

cf/d

)

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The high regional stress profile and well geometry was not fully considered during frac design and led to delamination of the shale or “pancake fractures”

This led to very poor connectivity with the wellbore

Frac design should be optimized to create more connected fracture networks taking regional stress and well orientation into account

• The 2010 frac program performed in two Elgin horizontal wells did not appear to create an effective completion

• Despite the productive G-41 a few hundred meters away, tremendous gas shows during drilling, and much larger completions, the Apache B-41 fracs were not successful

• Based on a consensus of third party expert consultants and Corridor’s technical staff:

Apache B-41 Well

Corridor G-41 Well

Upper Frederick

Brook Shale

Frederick Brook Completion Design

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Frederick Brook Comparison to Glacier Field (Alberta) Montney Producers

• Corridor’s F-58 well shows comparable IP rates to average vertical Glacier, Alberta wells

• Glacier vertical wells decline rapidly, F-58 decline rates are very low indicating large resource in place

• F-58 cumulative production exceeds average Glacier vertical well

* See Disclaimer and forward looking statements 20

Frederick Brook Comparison to Glacier Field (Alberta) Montney Producers

• Technological advancements over a number of years in the Glacier Field have resulted in increased daily average gas rates

• Similar technology advancements in the Frederick Brook could result in comparable daily average gas rates

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Frederick Brook Shale Development Potential Next Steps

• Work through government moratorium for next 12 months

• Look for Joint Venture partner• Develop next stage of pilot

program Drill 6-10 regional vertical wells Complete with high volume water

fracture stimulations Identify “sweet spots” Establish production and reserves Optimize completion techniques Reduce costs, optimize results Consider horizontal wells for future

programs

Potential Delineation Wells Potential Pipeline

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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

*

* Hibernia producing area outline shown for illustrative purposes only. Canada Newfoundland Offshore Petroleum Board (1996) estimates Hibernia’s original-oil-in-place at 1.39 billion barrels. As Corridor understands, this estimate of “original-oil-in-place” is equivalent to “discovered resources”. This disclosure is for illustrative purposes only and does not constitute an evaluation of resources under National Instrument 51-101 – Standard of Disclosure for Oil and Gas Activities. See “Resources Disclaimer” 23

Controlled Source Electro-Magnetic (CSEM) Survey

• Corridor is purchasing a multi-client CSEM survey on the west coast of Newfoundland (Est. $1.8mm)

• 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.

• Survey time 5-10 days, plus mob/demob time. Survey expected to be acquired in the fall 2015.

CSEM Survey:Newfoundland Side of Old Harry

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Old Harry Go Forward Plan

• In the market for a JV partner to drill an exploratory well (estimated $US55 MM)

• Corridor intends to use CSEM technology to confirm hydrocarbons

• Regulator published Strategic Environmental Assessment in May 2014 and it concludes that exploration and development activities can be safely undertaken

• Quebec Gov’t supports exploration of Old Harry prospect pending completion of impact studies and negotiations with Federal Gov’t in 2015

• Quebec and Canada are proceeding with a joint offshore accord to allow exploration and development

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Strategic Priorities

Corridor has sustainability combined with tremendous upside potential:

• Maximize cash flow and value of McCully assets

• Optimize strong pricing for gas production in Northeast U.S. market

• Emphasize Corridor’s strategic location advantage for LNG export facilities

• Influence progress on Anticosti Hydrocarbons L.P. coring program in Summer/Fall 2015 and 3 horizontal well tests in 2016

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

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

• Take advantage of Corridor’s balance sheet strength and add new growth projects to our inventory

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Disclaimer

Forward Looking Information Disclosure

• 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", or similar words suggesting future outcomes. In particular, this presentation contains forward-looking statements pertaining to the following: the potential and characteristics of Corridor's properties; Corridor's and Anticosti Hydrocarbon L.P.’s business plans and strategies, including strategic priorities; potential for LNG export; pipeline projects and capacity; natural gas production; potential regional supply basins; prices (including premiums) of natural gas; reserves and resources; support and treatment under governmental regulatory regimes; and exploration and development plans.

• 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, including the agreements governing the Anticosti Hydrocarbon L.P. as well as assumptions made by, and information currently available to Corridor, including information 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. 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, 2014. 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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Disclaimer (cont’d)

Resources Disclosure

• "discovered resources" is equivalent to “discovered petroleum initially-in-place, and refers to that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves, and contingent resources; the remainder is unrecoverable.

• "undiscovered resources" refers to those quantities of petroleum that are 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 resources carry discovery risk. There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of undiscovered petroleum initially-in-place at this time.

• "discovered unrecoverable petroleum initially-in-place", the equivalent of "discovered unrecoverable resources", refers to that portion of discovered 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;

• Resources do not constitute, and should not be confused with, reserves. Actual reserves and resources will vary from the reserve and resource estimates, and those variations could be material. There is no certainty that it will be economically viable to produce any portion of the resources.

• The resources assessment referred to in Slides #6, #11 & #16 was completed by GLJ Petroleum Consultants Ltd. effective June 1, 2009, as modified on March 25, 2014, setting forth certain information regarding discovered unrecoverable resources of Corridor's interests in the Frederick Brook shale formation. The best estimate is the value that best represents the expected outcome with no optimism or conservatism. There is no certainty that it will be commercially viable to produce any portion of these discovered resources.

• The reserves estimates referred to in Slides #2 & #3 was prepared by GLJ dated February 18, 2015 with an effective date of December 31, 2014 setting forth certain information relating to certain natural gas, crude oil and natural gas liquids reserves of Corridor properties, specifically the McCully Field and the Caledonia Field, and the net present value of the estimated future net reserves associated with such reserves.

• The resources assessment referred to in Slides #6 and #7 was prepared by Sproule Associates Limited effective June 1, 2011, as modified November 19, 2013 and updated effective as of April 30, 2015 setting forth certain information regarding total petroleum initially-in-place of the Macasty shale formation on Anticosti Island. The best estimate reflects the probability that the quantity actually in place is equal to or greater than the estimate is 50%. These resources are reported as Bboe to reflect uncertainty of hydrocarbon type across the island. A recovery project cannot be defined for this volume or undiscovered resources. There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any of these resources.

• For further information on Corridor's resources and reserves, see the Annual Information Form for the year ended December 31, 2014.

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