Corporate Presentation

Transcription

1 Corporate Presentation April 2019 All forward looking statements in this Corporate Presentation are qualified in their entirety by the "Forward Looking Information" on slides

2 Why Invest in Corridor Excellent balance sheet with an estimated working capital balance of $63.4 million at the end of March 2019 Excellent cash flow generating capability with forecast cash flow from operations (1) of $10.7 million from November 1, 2018 to March 31, 2019 Superior field operating netback per boe due to industry leading natural gas pricing at Algonquin City-Gates (AGT) Long life reserves with minimal future development capital and predictable, low decline natural gas production (~10% annually) Solid fundamental core value with exposure to high impact prospects Flexibility to take advantage of its balance sheet strength to act on counter-cyclical opportunities 1) 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 year ended December 31,

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 (2019/02/28) Basic 88,924,465 Diluted (Avg. exercise price $0.79) 92,369,965 Tax Pools (2018/12/31) CEE CDE Other Forecast from November 1, 2018 to March 31, 2019 Cash Flow From Operations (1) $99.7 MM $44.8 MM $21.5 MM $166.0 MM $10.7 MM Field Operating Netback ($/boe) $ ) 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, 2018 Gross Reserves* MM boe NPV@BT10% Proved Developed Producing $52.2 million Total Proved $52.2 million Total Proved plus Probable $60.7 million Reserve Life* Years Proved Developed Producing 21 Total Proved 21 Total Proved plus Probable 27 *Reserve Report dated March 1, 2019 prepared by GLJ Petroleum Consultants Ltd. effective December 31,

6 Net Asset Value Per Basic Share Reserves BT10% effective December 31, 2018* Proved Developed Producing $0.59 Probable Developed Producing $0.09 Total Reserve Value $0.68 Estimated Working Capital (2019/03/31) $0.71 Total Net Asset value per basic share $ % of Corridor s reserve value is in the Proved Developed Producing Category Reserve Report dated March 1, 2019 prepared by GLJ Petroleum effective December 31,

7 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 yields flush production during winter months when natural gas prices at AGT 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. Corridor implemented its optimization strategy again in 2018 by shutting-in all of its production starting in May 2018 and resuming partial production in November 2018 with full production to resume in December

8 Flush Production after a shut-in period when AGT prices are higher Corridor Net Gas Production Gas Rate 2015 Continuous Forecast Corridor Net Gas Rate (mmscf/d) 10 1 May mmscf/d Strategic shut-in periods Flush production periods Jan mmscf/d Jan-2007 Jan-2008 Jan-2009 Jan-2010 Jan-2011 Jan-2012 Jan-2013 Jan-2014 Jan-2015 Jan-2016 Jan-2017 Jan-2018 Jan-2019 Jan-2020 Jan-2021 Higher production rates preserved for winter peak pricing Note: 2015 historical production forecast included for flush reference and does not represent future plans. Daily Corridor production history updated to include April 30,

9 Hedging Program Period Winter 2018/2019 1) Average Volume (mmbtu/d) Price ($US/mmbtu) Dec Mar ,500 $7.40 Dec Mar ,500 $7.90 December ,500 $10.35 January ,500 $12.72 February ,500 $12.50 Winter 2019/2020 Dec Mar ,500 $9.00 1) These hedges represent approximately 70% of Corridor s estimated production from December 1, 2018 to March 31, 2019 and secure an estimated $9.1 million out of an estimated $12 million of total revenue during this period. (Estimated total revenue is based on unhedged production volumes being sold at an average estimated strip pricing at AGT of $US8.97/mmbtu from December 1, 2018 to March 31, 2019) 9

10 Shut-in Strategy Results Winter Shut-in Duration months FOI (est.) Continuous Production Case $, millions FOI (Actual) Shut-in Case $, millions Produced Volume (Actual) Mscf Deferred Volume (Estimate) Mscf 2017/ $8.4 $ / $7.3 $ / $6.7 $ Total $22.4MM $24.5MM 4.8 BCF 1.8 BCF Strategic summer/fall shut-ins of the McCully Field have been conducted since 2015 at durations ranging from three to eight months. All three shut-in periods were successful at securing field operating netback (FOI) near to or greater than the forecast continuous production case. In total, the three shut-ins deferred an estimated 1.8 BCF of gas for future sales, while earning an estimated $2.1 million more FOI than would have resulted from forecast continuous production. In 2017/18, superior winter pricing generated the most FOI from the least amount of produced volumes of any of the past three years. The 1.8 BCF in deferred volume is nearly equal to one full year of typical continuous production! 10

11 Market Guidance (November 1, 2018 to March 31, 2019) AGT average natural gas price USD/CAD exchange rate Average net 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, 2019) Capital Expenditures (for the year 2018) Forecast $8.85US/mmbtu 1.26 USD/CAD $10.92/mscf 8.7 mmscfpd $ 11.8 million $ 10.7 million $ 9.8/mscf $ 9.0/mscf $ 63.4 million $ 4.1 million *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. 11

12 Nov. 1, 2018 Mar. 31, 2019 Market Guidance Winter Pricing Premiums Expected to offer Superior Netbacks November 1 - March 31 Forecast Natural gas sales (net of transportation) $ 13,583 Realized financial derivatives gain (546) Other revenues 359 Royalties (417) Production expense (1,220) Field operating netback $ 11,759 Natural gas production per day (mmscfpd) 8.7 Barrels of oil equivalent per day (boepd) Average net natural gas price realized ($/mscf) $ Natural gas revenues ($/boe) $ Realized financial derivatives gain ($/boe) (2.74) Other revenues ($/boe) 1.80 Royalties ($/boe) (2.10) Production expense ($/boe) (6.13) Field operating netback ($/boe) $ General and administrative expenses ($/boe) (7.02) Interest, foreign exchange gains and other ($/boe) Cash flow from operations * ($/boe) $ thousands of dollars except $/boe 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. 12

13 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 to the USA Production from Sable Island and Deep Panuke was permanently terminated at the end of 2018 Now that Sable Island and Deep Panuke are fully offline, besides McCully production, 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 13

14 AGT Futures Pricing Strong for the Foreseeable Future AGT futures pricing* is expected to remain robust to 2024 Annual average price to 2024 is US$4.60/mmbtu Significant premiums over Nymex Henry Hub in the winter months Winter peaks exceed US$9.50/mmbtu Gas Price (US$/mmbtu) $14 $12 $10 $8 $6 $4 $2 $0 Nymex Strip Pricing (USD$/mmbtu) March 20, 2019 Nymex Henry Hub AGT Differential AGT Yearly Average Price -$2 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 Jan-24 Apr-24 Jul-24 Oct-24 *Nymex and Algonquin Basis (i.e. AGT) prices are daily settlement for March 20, 2019 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 considerable 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 15

16 New Brunswick Assets 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 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) total unrisked undiscovered unrecoverable petroleum-initiallyin-place* NB NS PEI * For definition of petroleum-initially-in-place see forward looking information 16

17 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 15 kilometers of gathering system 32 producing wells from 11 well pads NB NS PEI 17

18 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 m to 4,000 m Potential for vertical or horizontal development A hydraulic fracturing moratorium currently exists, but indications are the new NB Government may rescind it in our core area 18

19 Frederick Brook Shale Production History 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 Monthly Production Rate (mcf/d) 1000 F-58 Shale Production Stable Rate 180 mcf/d Increasing flush with each field shut-in 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 19

20 Frederick Brook Shale Development Potential Next Steps Pilot Project Pursue a termination of the hydraulic fracturing moratorium If the moratorium is lifted, secure joint venture capital funding to undertake a pilot program which could consist of: 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 20

21 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 21

22 Old Harry Go Forward Plan 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 land tenure s term and status is such that conducting a 3-D program before the expiry of the lease is not currently viable Corridor plans to formally request regulatory relief and certainty for its land tenure, in particular for Quebec, which covers roughly 2/3rds of the Old Harry structure All further capital and technical work has been suspended If we obtain regulatory relief and certainty, Corridor would resume its search for a joint venture partner. 22

23 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 Attract third parties to joint venture on our exploration prospects with renewed emphasis on Frederick Brook shale in anticipation of the potential removal of hydraulic fracturing moratorium Corridor has sustainability combined with tremendous upside potential 23

24 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 production optimization strategy, maximizing cash flow and value of the McCully assets, nurturing constructive government and stakeholder relations, attracting third parties to joint ventures on exploration projects and identifying opportunities for deploying Corridor s surplus working capital; exploration and development plans, including the Frederick Brook pilot project, and conducting a 3D seismic over and drilling a well at Old Harry, and the timing and costs of such plans; characteristics of Corridor s properties; the benefits of implementing optimization strategies (estimates of field operating income and deferred production as a result of Corridor s optimization strategy); market conditions (including natural gas demand and pipeline development projects and capacity); and expectations of natural gas prices and premiums at AGT and the Maritimes market; natural gas production; natural gas sales, realized financial derivatives loss, cash flow from operations; capital expenditures and estimates; rates of decline; reclassification of contingent resources to reserves. 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 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, Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. Oil 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. 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. 24

25 Forward Looking Information Resources "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. The Frederick Brook Resource Study dated March 1, 2017 and effective December 31, 2016 and reconfirmed in December 31, 2018 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. For more information regarding Corridor s reserves and contingent resources, readers should refer to Corridor s Annual Information Form for the year ended December 31,