Slide 1March 29, 2018
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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• Excellent balance sheet with an estimated working capital balance of approximately $57.0 million at end of Q1 2018
• 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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investments)
• Phil Knoll President, Knoll Energy Inc. (private
consulting company)
• Norm Miller Former CEO, Corridor Resources from
1995 to 2010
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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
• Shares Outstanding (2017/12/31) Basic 88,655,299 Diluted (Avg. exercise price $0.79) 91,920,132
• Tax Pools (2017/12/31) CEE $96.7 MM CDE $55.3 MM Other $23.2 MM Total $175.2 MM
• Forecast from April 1, 2017 to March 31, 2018
Cash Flow From Operations* $7.8 MM
Field Operating Netback ($/mcf) $9.73
* 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.
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New Brunswick 195,000 Old Harry - Quebec & NL 251,000
• December 31, 2017 Reserves* MM boe PV@BT10% Proved Developed Producing 3.044 $55.1 million Total Proved 3.044 $55.1 million Total Proved plus Probable 3.776 $63.5 million
• Reserve Life* Years
Proved Developed Producing 22 Total Proved 22 Total Proved plus Probable 28
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**Reserve Report dated February 2, 2018 prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2017.
2018 Contingent Resources Report*
Flow NPV (MM$C)
Flow NPV (MM$C)
Low Estimate 9.7 41 1.7 $17.0
Best Estimate 15.9 56 2.7 $26.8
High Estimate 20.3 71 3.5 $37.5
*Contingent Resource Report dated February 2, 2018 prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2017. See
disclosure notes regarding Contingent Resources at the end of the presentation.
• 44.0 BCF of Unrisked
Reserves valued @ BT10% effective December 31, 2017* Proved Developed Producing $0.62 Probable Developed Producing $0.09 Total Reserve Value $0.71
Estimated Working Capital (2018/03/31)** $0.64
Total Net Asset value per basic share $1.35
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• Reserve Report dated February 2, 2018 prepared by GLJ Petroleum effective December 31, 2017.
87% of Corridor’s reserve value is in the Proved Developed Producing Category
McCully Field Production Optimization Strategy
• To take advantage of the premium winter pricing at AGT, since 2015, Corridor has strategically shut-in production during the summer/fall months. The resulting build-up in reservoir pressure yielded flush production (see next slide) during winter months when natural gas prices at AGT are typically higher
• 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 its winter pricing premium as a component of this strategy
• Corridor implemented its optimization strategy again in 2017/18 by shutting-in the vast majority of its production on April 1, 2017. Corridor recommenced full field production in December 2017.
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Higher
production
rates
13.6mmscf/d
Flush
production
periods
Strategic
shut-in
periods
Note: 2015 historical production forecast included for flush reference and does not represent future plans. 9
Press Release
USD/CAD exchange rate 1.25 USD/CAD
Average daily natural gas production* 3.0 mmscfpd
Field operating netback $ 10.8 million
Cash flow from operations** $ 7.8 million
Field operating netback per mscf $ 9.73/mscf
Cash flow from operations** per mscf $ 7.02/mscf
Working capital (as of March 31, 2018) $ 57.1 million
Capital Expenditures (for the year 2017) $ 3.6 million
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Market Guidance (April 1, 2017 to March 31, 2018)
* Average daily natural gas production for the 12 month period is inclusive of a shut-in of the vast majority of production from April 2017 to December 2017. **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.
Understanding Corridor’s Premium 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 Provinces’ Natural Gas Market
• The Maritimes’ primary gas supply has historically been fully sourced from Sable Island and, since 2013, Deep Panuke,
• By 2017, flow on M&NP pipeline had reversed, with the Maritimes sourcing a portion of its gas supply the USA*
• Sable Island decommissioning began in late 2017 and is expected to be completed in 2020**
• The Operator for Deep Panuke has filed an application to start abandonment and only produces seasonally*
• When Sable Island and Deep Panuke are fully offline, besides McCully, the Maritimes gas demand will need to be sourced from the USA or Canaport
• 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
12 *Source: Jim Magill and Eric Brooks, S&P Global Platts Gas Daily, March 21, 2018 **Source: Jim Magill, S&P Global Platts Gas Daily, November 9, 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 Henry Hub in the winter months
• Winter peaks exceed $US10.00/mmbtu
• January 2018 averaged over $US15.00/mmbtu
*Nymex and Algonquin Basis (i.e. AGT) prices are daily settlement for January 23, 2018 as provided by Intercontinental Exchange (ICE) NG LD1 Futures and NG Basis LD1 for IF Futures.
-$2
$0
$2
$4
$6
$8
$10
$12
$14
Nymex Henry Hub AGT Differential AGT Yearly Average Price
Two High Impact Prospects
Old Harry
• One of the largest Canadian East Coast offshore geological structures
• 43,000 acre potential oil prospect
New Brunswick
potential while demonstrating prudent financial management
Old Harry Offshore Potential
• One of the largest undrilled geological structures in Eastern Canada (43,000 acres/67 sq miles) under simple four-way closure
• Several direct hydrocarbon indicators identified: satellite seepage slicks, frequency anomalies, amplitude anomalies, and AVO anomalies
• Over 1,000 km of modern 2-D seismic
• Basin modeling indicates light oil (~55 API) was initially generated and could be filling the structure
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• Corridor recently purchased a multi-client CSEM survey over the Newfoundland side of Old Harry. Data acquisition was completed November 2017.
• Recording instruments were placed on the sea bottom and an electro-magnetic (EM) source was towed behind a vessel (see right).
• Signals from the EM source traveled through the rock formations to the receivers. Anomalously resistive layers (hydrocarbons) typically stand-out against a non-resistive background (see figure upper right).
• A positive CSEM anomaly in a sand/shale sequence may provide confidence of the existence of hydrocarbon bearing sands.
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Newfoundland Side of Old Harry
Old Harry Go Forward Plan
• Final processing and analysis of the CSEM data expected by April 30, 2018
• Corridor is reprocessing 760 km of its proprietary 2D seismic to incorporate into an integrated geotechnical model; expected to be completed by May 30, 2018
• If the results of the geotechnical model results are positive, Corridor intends to increase its efforts to secure a joint venture partner to drill an exploratory well (estimated cost of ~$US45 MM*).
• Corridor to provide a shareholder update of its go forward plans by end of May, 2018
* Estimate as of April 2017
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Canada-Newfoundland and Labrador Offshore
exploration and development activities can be
safely undertaken
until January 2021
New Brunswick Assets
• 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
NB
NS
PEI
• 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
15 kilometers of gathering system
32 producing wells from 11 well pads
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NB
NS
PEI
• 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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1000
2008 2010 2012 2014 2016 2018 M o n th
ly P
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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
~180 mcf/d
0
500
1000
1500
2000
2500
3000
3500
4000
1
10
0 1 2 3 4 5 6 7 8 9 10
W e llh
( p s i)
Flow Time (days)
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• Pursue a termination of the hydraulic fracturing moratorium
• If the moratorium is lifted, secure joint venture capital funding to undertake a pilot program as follows:
Drill 5 vertical evaluation wells
Recomplete 3 existing wells
Complete with high volume water fracture stimulations
Identify “sweet spots” and drill a second round of horizontal wells – up to 5 wells
Establish production and reserves for type curves for vertical versus horizontal wells
Optimize completion techniques
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
• Continue with a disciplined approach to identify opportunities for deploying Corridor’s surplus working capital
Corridor has sustainability combined with tremendous upside potential
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• 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 efforts to obtain joint venture partners and next steps in respect of the Old Harry and Frederick Brook properties; characteristics of Corridor’s properties, benefits of by implementing optimization strategies; continuing to advance government and stakeholder relations; continue with a disciplined approach to identify opportunities for deploying Corridor’s surplus working capital; exploration and development plans (including drilling an exploratory well at Old Harry and a pilot program in the Frederick Brook shale) including timing of such plans; the benefits of the CSEM data and 2D seismic processing over the Old Harry structure; market conditions (including natural gas demand and pipeline development projects and capacity); expectations of natural gas prices and premiums at AGT and the Maritimes market; field operating netbacks; production; expected revenues from hedging agreements; royalties; expenses; cash flow from operations; capital expenditures and estimates; working capital estimates; and the U.S. Canada exchange rate.
• Statements relating to “reserves” and “contingent 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 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. 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 the Corporation and its shareholders.
• Forward-looking statements are based on the Corporation's current beliefs as well as assumptions made by, and information currently available to, the Corporation 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 the Corporation's forward sales contracts and 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 the Corporation’s Annual Information Form for the year ended December 31, 2017. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive.
• Certain of the forward-looking statements in this press release may constitute "financial outlooks" as contemplated by National Instrument 51-102 - Disclosure Obligations, including information related to projected cash flow from operations, revenues, expenses, capital expenditures and working capital, which are provided for the purpose of forecasting the financial position of Corridor as at March 31, 2018. Please be advised that the financial outlook in this presentation may not be appropriate for purposes other than the one stated above.
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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Contingent Resources
• Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as “contingent resources” the estimated discovered recoverable quantities associated with a project in the early evaluation stage. In the case of the McCully Field, the significant contingency was the imposition by the New Brunswick Government of a moratorium on hydraulic fracturing in 2015. Contingent resource estimates are prepared independently from the consideration of commercial risks. On this basis, it is expected that, as the contingencies are removed and, in the absence of new technical or economic data, the contingent resource estimates associated with the development project would move directly to the corresponding reserves confidence classification.
• Contingent resources are classified based on project maturity. The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of Corridor’s contingent resources are classified as development on hold. Development on hold means there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Significant uncertainty exists with the continuation of the Government of New Brunswick’s moratorium on hydraulic fracturing. Removal of the moratorium sooner would positively affect the value estimates, whereas extension of the moratorium would negatively affect the estimates. For greater certainty, no assurance can be given that the moratorium will be lifted.
• There are three classifications of contingent resources estimates: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate; a 90% probability that the quantities actually recovered will equal or exceed the low estimate and a 10% probability that the quantities actually recovered will equal or exceed the high estimate.
• Contingent resources are considered too uncertain with respect to the chance of development to be classified as reserves. Chance of development is defined as the probability of a project being commercially viable. GLJ has estimated the chance of development for the project at 36% based on the multiplication of an economic factor (1.0), a technology factor (1.0), a plan development factor (0.9) and other contingency factor (0.4).
• The net present value of future net revenue attributable to the contingent resources does not represent the fair market value of the contingent resources. Estimated abandonment and reclamation costs have been included in the evaluation.
• There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Corridor will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve the implied assessment, based on certain estimates and assumptions, that the contingent resources described exists in the quantities predicted or estimated and that the contingent resources can be profitably produced in the future. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.
• An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. The estimate includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized. The net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources.
• The Contingent Resources Report provides estimates of Corridor’s interests in contingent resources from a future development project at the McCully Field. The Contingent Resources Report assumes the New Brunswick Government moratorium on hydraulic fracturing will be lifted and a development project will begin in 2021. However the New Brunswick Government announced on May 27, 2016 its decision to continue the moratorium for an indefinite period. In the event the moratorium is lifted and Corridor is permitted to conduct the development project, the Contingent Resources Report contemplates that Corridor would drill new wells using standard technology and that these new wells, and existing wellbores requiring completion, would be hydraulically fractured. The project is based on a development study utilizing detailed geological, engineering and economic information for the project with estimated future development capital costs. Furthermore, in the event the moratorium is lifted, GLJ has acknowledged that the contingent resources would meet the technical qualifications for the classification of reserves.
• For more information regarding Corridor’s Contingent Resources, readers should refer to the Corporation’s Annual Information Form for the year ended December 31, 2017.
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