Corporate Presentation

Transcription

1 Corporate Presentation November 2017 All forward looking statements in this Corporate Presentation are qualified in their entirety by the "Forward Looking Information" on slide 25. 1

2 Why Invest in Corridor Excellent balance sheet with a working capital balance of approximately $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 2

3 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 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 Robert Penner, CPA, CA Independent Consultant Formerly Senior Tax Partner, KPMG LLP 3

4 Corporate Snapshot Stock Symbol TSX CDH Shares Outstanding (2017/09/30) Basic 88,655,299 Diluted (Avg. exercise price $0.78) 92,053,467 Tax Pools (2017/09/30) CEE CDE Other Total Forecast from April 1, 2017 to March 31, 2018 Cash Flow From Operations* $94.0 MM $55.2 MM $23.3 MM $172.5 MM $4.1 MM Field Operating Netback ($/boe) $51.71 * 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

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

6 Net Asset Value Per Basic Share Reserves 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 (2017/09/30) $0.56 Total Net Asset value per basic share $ % of Corridor s reserve value is in the Proved Developed Producing Category * Reserve Report dated March 1, 2017 prepared by GLJ Petroleum effective December 31,

7 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 (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 (see slide 9). Corridor has implemented its optimization strategy again in 2017/18 by shutting-in the vast majority of its production on April 1, Corridor expects to partially recommence production in November 2017, with a significant ramp-up in production expected in December

8 Production Optimization Strategy Corridor Net Gas Production Gas Rate Original 2015 Forecast Flush production periods 10 Higher production rates preserved 1 Dec-06 Dec-07 Dec-08 Dec-09 Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15 Dec-16 Dec-17 MMSCF/D Dec-18 Dec-19 Dec-20 Strategic shut-in periods Note: 2015 historical production forecast included for flush reference and does not represent future plans. 8

9 Winter 2017/2018 Hedging Program Average Volume Period (mmbtu/d) Price ($US/mmbtu) Dec Mar ,500 $7.400 Dec Feb ,500 $7.826 These hedges represent approximately 48% of Corridor s estimated production from December 1, 2017 to March 31, 2018 and secure $4.8 million out of an estimated $9.8 million of total revenue during this period.* * Estimated total revenue is based on unhedged production volumes being sold at an average strip pricing at AGT of $US7.40/mmbtu 9

10 Market Guidance (April 1, 2017 to March 31, 2018) AGT average natural gas price USD/CAD exchange rate Average natural gas price realized Average daily natural gas production* Field operating netback Cash flow from operations** Field operating netback per mscf Cash flow from operations** per mscf Working capital (as of March 31, 2018) Capital Expenditures (for the year 2017) Press Release (Oct. 11, 2017) $4.24US/mmbtu 1.24 USD/CAD $9.50/mscf 2.9 mmscfpd $ 7.1 million $ 4.1 million $ 6.8/mscf $ 3.9/mscf $ 53.5 million $ 3.7 million * Average daily natural gas production for the 12 month period is inclusive of a shut-in of the vast majority of production from April 1, 2017 to November 30, **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. 10

11 Q Netback Forecast Winter Pricing Premiums offer Superior Netbacks Three months ended March Forecast Natural gas sales $ 7,245 $ 4,166 Realized financial derivatives gain - 1,094 Other revenues Royalties (224) (92) Transportation expense (322) (428) Production expense (573) (789) Field operating netback $ 6,383 $ 4,252 Natural gas production per day (mmscfpd) Barrels of oil equivalent per day (boepd) 1,196 Average natural gas price ($/mscf) $ 9.78 $ 6.45 Natural gas revenues ($/boe) $ $ Realized financial derivatives gain ($/boe) Other revenues ($/boe) Royalties ($/boe) (1.82) (0.86) Transportation expense ($/boe) (2.61) (3.97) Production expense ($/boe) (4.64) (7.33) Field operating netback ($/boe) $ $ General and administrative expenses ($/boe) (5.47) (6.05) Interest, foreign exchange gains and other ($/boe) Cash flow from operations * ($/boe) $ $ thousands of dollars except $/boe (2) 2018 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. 11

12 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 12

13 Shifting Maritime Province s Natural Gas Market The Maritimes 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 * Source: Brett Bundale, The Canada Press, April 26,

14 AGT Futures Pricing Strong for the Foreseeable Future 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 $4.33 USD/mmbtu Gas Price (US$/mmbtu) $10 $8 $6 $4 $2 $0 -$2 Nymex Strip Pricing (USD$/mmbtu) October 20, 2017 Nymex Henry Hub AGT Differential AGT Yearly Average Price Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 *Nymex and Algonquin Basis (i.e. AGT) prices are daily settlement for October 20, 2017 as provided by Intercontinental Exchange (ICE) NG LD1 Futures and NG Basis LD1 for IF Futures. 14

15 Two High Impact Prospects Focused on de-risking two high-impact prospects with tremendous upside potential while demonstrating prudent financial management New Brunswick Frederick Brook Shale Unconventional gas prospect Regulatory hurdles exist, currently under a hydraulic fracturing moratorium New Brunswick 195,000 Net Acres Old Harry 251,000 Net Acres Old Harry One of the largest Canadian East Coast offshore geological structures 43,000 Acre potential oil prospect 15

16 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 16

17 Controlled Source Electro- Magnetic (CSEM) Survey Corridor is purchasing a multi-client CSEM survey over the Newfoundland side of Old Harry. Data acquisition is expected to be completed by mid- November 2017 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. Final processing and analysis of the CSEM data expected in Q1, 2018 CSEM Survey: Newfoundland Side of Old Harry 17

18 Old Harry Go Forward Plan If the CSEM results are positive, Corridor intends to increase efforts to secure a joint venture partner to drill an exploratory well (as of April 2017, estimated at ~$US45 MM) Corridor s Exploration License term in effect until January 2021 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 18

19 New Brunswick Assets 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 NB NS PEI 19

20 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 NB NS PEI 20

21 Frederick Brook Shale 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 21

22 Frederick Brook Shale Production History 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 Monthly Production Rate (mcf/d) F-58 Shale Production 1000 ~180 mcf/d Gas Rate (mmscf/d) 10 1 G-41 Upper Zone Tests 4000 Test 1 - Gas Rate Test 2 - Gas Rate 12mmscf/d 3500 Test 1 - WHP 3000 Test 2 - WHP mmscf/d Flow Time (days) Wellhead Pressure (psi) 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 22

23 Frederick Brook Shale Development Potential Next Steps Pilot Project Pursue a termination of the hydraulic fracturing moratorium 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 Potential Delineation Wells Potential Pipeline Establish production and reserves for type curves for vertical versus horizontal wells Optimize completion techniques 23

24 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 24

25 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 efforts to obtain joint venture partners and next steps in respect of the Old Harry and Frederick Brook properties; characteristics of Corridor s properties, the value of McCully assets by implementing optimization strategies; continuing to advance government and stakeholder relations; 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 and drilling or recompleting wells at Old Harry and the Frederick Brook shale) including timing of such plans; the benefits of the CSEM data; pipeline development projects and capacity; benefits and timing of pipeline development, potential regional supply basins; 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 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, expiration of the terms of leases and exploration licences; as well as assumptions made by, and information currently available to Corridor, including information concerning anticipated financial performance, capital cost; 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, 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. 25