Cequence Energy Ltd. Restructured and Focused January 2019 TSX:CQE 1

Transcription

1 Cequence Energy Ltd. Restructured and Focused January 2019 TSX:CQE 1

2 Summary of Forward-Looking Statements or Information FORWARD- LOOKING INFORMATION AND DEFINITIONS Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. This information relates to future events or future performance of the Company. Investors are cautioned that reliance on such information may not be appropriate for making investment decisions. Many factors could cause the Company s actual results, performance or achievements to vary from those described herein. The forward-looking information contained in this presentation is expressly qualified by this and other cautionary statements set forth in the continuous disclosure record of the Company. The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent ( boe ) using 6,000 cubic feet of natural gas as equal to one barrel of oil unless otherwise stated. The term barrel of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This value ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value. See slide 21 for additional advisories. Non-GAAP Measurements References are made to terms commonly used in the oil and gas industry, including operating netback, net debt, and funds flow from (used in) operations. Operating netback is not defined by IFRS in Canada and is referred to as a non-gaap measure. Operating netback equals per boe revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze the operating performance of its assets and operating areas, to compare results to peers and to evaluate drilling prospects. Net debt is a non-gaap measure that is calculated as working capital (deficiency) less the principal value of senior notes. For this calculation, Cequence uses the principal value of the senior notes rather than the carrying value on the statement of financial position as it reflects the amount that will be repaid upon maturity. Cequence uses net debt as it provides an estimate of the Company s assets and obligations expected to be settled in cash. Funds flow from (used in) operations is a non-gaap term that represents cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. The Company evaluates its performance based on earnings and funds flow from (used in) operations. The Company considers funds flow from (used in) operations a key measure as it demonstrates the Company s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company s calculation of funds flow from (used in) operations may not be comparable to that reported by other companies. Non-GAAP financial measures do not have a standardized meaning prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other users. TSX:CQE 2

3 (000 s, except per share and per unit references) Common shares outstanding (Dec 31, 2018) 24,553 CORPORATE SUMMARY November to December 2018 trading range $0.55 to $0.98 Estimated year end, net debt (1) ($) $70,950 $60,000 Term (2) Market Capitalization ($0.70/share) $17,170 Insider ownership 13.30% Q4 WELLS FUNDED WITH $8.6 MM CDE RAISE Forecast 2018 production (3) 6,500 Forecast 2018 funds flow from operations $13,700 Estimated 2018 exploration & development capital $20,000 $8,600 CDE raise 2018 Net wells 4.0 Reserves P + P, December 31, MMBoe Tax Pools (Sept 30, 2018) $609,770 Non-Capital Losses (included above) $313, Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the aggregate principal amount of the term loan 2. Term debt is 5% annual interest rate maturing in October average production estimates on a per BOE basis are comprised of 77% natural gas and 23% oil and natural gas liquids 2018 commodity prices included above average $65.40 WTI US/bbl, AECO price of $1.50 CAD/GJ TSX:CQE 3

4 Previous Transitioned RESTRUCTURED & FOCUSED $60 million 9.7% Unsecure senior notes Matured Oct 3, 2018 $60 million 5% 2 nd lien term loan (1) Matures Oct 3, 2022 Equity financing complete $8.6 million rights offering (2) CDE for oil wells Q1 18: 6,970 boe/d 17% liquids Q3 2018: 6,734 boe/d 27% liquids 1. Closed refinancing of the $60 million term loan Sept. 13 th, Rights Offering funds collected September 13 th, 2018 and 12.3 million (245.5 million pre-consolidation) shares issued. All Corporate shares were consolidated on a 20:1 basis October 24, 2018 TSX:CQE 4

5 STRATEGY REINVEST IN DUNVEGAN OIL PRESERVE MONTNEY UPSIDE 2019 SPEND WITHIN CASHFLOW Improving Netback Lower interest & operating cost Increased oil & liquids weighting: 27% Q up from 17% in first quarter 2018 Large Recognized Inventory 79.0 net booked Montney locations Expanding highly commercial Dunvegan oil inventory Encouraging results from nearby other Montney benches Improved Well Performance Well design improvements: Strong Dunvegan oil results above analog averages Montney netback initiatives have improved economics Infrastructure & Marketing Infrastructure in place. No significant facility costs required 50% owned Simonette gas processing facility Firm egress for natural gas production Gas price diversification to Dawn market TSX:CQE

6 SIMONETTE DUNVEGAN OIL PLAY All 3 Pools have similar OOIP/section ranges of 6-15 MMBOE Simonette & Karr on primary solution gas drive Kaybob South operator has initiated a pilot secondary recovery waterflood scheme 1 st Hz producer converted to injector late nd and 3 rd converted late 2017 Positive early response on oil rates and GORs gross (14.5 net) sections identified with oil development 40 o API oil Internal estimate of ~80 MMbbls OOIP (1) net to Cequence 30.5 total net locations, 24.5 net locations remaining (2) Solution gas gathered to Cequence/KANATA gas plant Infrastructure synergy with Montney development Expect 8-10% recovery on primary and up to 20% recovery on waterflood 1. Original oil in place (OOIP) is equivalent to DPIIP for purposes of this presentation. See page Remaining locations are internal company estimates at YE 2018 based on current development plans and subject to change. TSX:CQE 6

7 Dunvegan 2017 YE Bookings (1) (2) PUD (Drilled) PUD Probable Unbooked Locations Q Rig Releases Planned Drills through H SIMONETTE DUNVEGAN LIGHT OIL INVENTORY vertical 100% WI lands IP30: 45 BOPD vertical delineation 9m gross interval % CQE % CQE 5-7 facility 2,000 bbls/d 740 Hp Compressor Progress to Date: Q Drilled 2.0 (2.0 net) wells, on stream end of December. IP30 results will be available when achieved 3 gross (2.0 net) Q wells are above internal Corporate model (100% CQE): 155 mstb in 275 calendar days Q wells and through permanent facilities January 10 th, /04-08 vertical completion & vertical log extend play West on 100% WI lands Unbooked locations (2) - 100% Cequence working interest with anticipated lower gas oil ratios (1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, (2) Proved undeveloped and probable locations are derived from the Company s December 31, 2017 reserves evaluation as prepared by GLJ Petroleum Consultants. Unbooked locations are internal estimates based on the Company s prospective acreage. Unbooked locations do not have attributed reserves and there is no certainty that if drilled these locations would result in additional oil and gas reserves or production. TSX:CQE 7

8 15-04 DUNVEGAN OIL COMMERCIAL AT CURRENT STRIP Strong Well Results CQE averages: $4 to $4.5 MM/well: 2,000 m lateral, frac stages (2X more fracs than historic analogs) 6 of 7 wells at or above production model , 15-04, each paid out in under one year Began moving liquids through 50% CQE owned facility for additional production flexibility $60 US WTI, $1.50/GJ CDN, $10 US Diff 2,000 m well Costs (Drill, Complete, Equip) ($MM) $4.5 $4.0 Drilling Results IP365 Production Rate (bbl/d) Reserves (MBOE) $8.30 $ % 1.8 $3.1 10,150 $7.40 $ % 1.3 $3.6 9,000 Economic Indicators F&D ($/BOE) 1st Yr Netback ($/boe) Recycle Ratio ROR (%) Payout (Years) NPV10% ($M) Production Efficiency ($/boed-365) 1.Type curves are internally generated, see definitions on page 21. TSX:CQE 8

9 Capital Sensitivity DUNVEGAN OIL SENSITIVITIES TO CAPITAL AND COMMODITY PRICE Internal CQE 2,000 m well model $60 WTI US/bbl, $10 US/Edmonton differential, $0.75 CAD/US exchange $1.50 CAD/GJ AECO MRF Alberta Crown Royalties Price Sensitivity Internal CQE 2,000 m well model $10 US/Edmonton differential, $0.75 CAD/US exchange $4 million well cost MRF Alberta Crown Royalties TSX:CQE 9

10 03/04-08 VERTICAL VS KAYBOB VERTICAL WITH HORIZONTAL OFFSETS Simonette Kaybob South Vertical to Horizontal Production Analog CQE vertical well completed in Q vertical producing at or above analog Kaybob verticals DE-RISKING WEST INVENTORY Average offset Kaybob Hz s: 1,400 m, frac stages, 0.2T/m CQE target: 2,000+ m, 40 frac stages, 0.6 T/m Kaybob scaled up for length and frac intensity (approx. 2 X) similar to CQE 2,000 m model Supports inventory proximal to vertical well 10

11 Montney: 140m Thick SIMONETTE MONTNEY 100/ W5M Nordegg Lwr Mont Producer Historical CQE Hz placement Upper Montney Lwr Mont Spud Oct st Lower Montney placement Lower Montney Paleozoic BIG RESOURCES All zones 121 MMboe proved plus probable booked reserves (1) Montney 3.8 TCF gross Upper Montney resource-in-place (2) PDP: 8.3 MMboe LARGE UPPER MONTNEY INVENTORY TP: 49.6 MMboe 51 gross (48.0 net) wells $156.7 MM NPV10% 2P: MMboe 86 gross (79.0 net) wells $327.6 MM NPV 10% Booked at 300 m inter-well spacing WEST DEVELOPMENT AREA Liquid yields of bbl/mmcf 21 sections of analogous western lands 50 potential net wells at 300 m spacing, (3) largely unbooked for reserves (1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, (2) See Forward-Looking Information and Definitions on page 20 for definition of DPIIP and total resource, Upper Montney only. DPIIP effective December 21, 2016, not re-evaluated in 2017 (3) Internal estimate based on 300 m inter-well spacing OTHER MONTNEY ACTIVITY INCREASING Recent third parties drilling Lower & Middle Montney benches nearby 2 Lower Montney wells drilled in Simonette - both monobore (no intermediate casing) 7-15 producing 180 bbls/d oil from approximately 1,100 m lateral Lower Montney well: 2,260 m lateral rig released Nov 2018 TSX:CQE 11

12 CEQUENCE SIMONETTE UPPER MONTNEY WEST AREA CHARACTERIZATION Condensate yield 2X historical Higher netback production LIQUIDS-RICH Liquids sales 98% high-value pentanes plus COST-EFFICIENT Less than 15 ppm H 2 S: $0.30/mcf lower treating cost EXPANDED INVENTORY West area inventory unbooked Encouraging Lower Montney test well with less expensive drilling on CQE land block 1.Type curves are internally generated, see definitions on page 21. TSX:CQE 12

13 $60 WTI, $2.50/GJ CDN, $10/bbl diff Costs (Drill, Complete, Equip) ($MM) East Montney (1) West Montney $8.0 $8.0 LARGE INVENTORY WITH TORQUE TO INCREASING GAS PRICES Drilling Results IP30 Production Rate (MMcf/d) Reserves (MBOE) 1,650 1,050 ORGIP (Bcf) Economic Indicators F&D ($/BOE) $4.80 $7.60 1st Yr Netback ($/boe) $18.10 $26.90 Recycle Ratio ROR (%) 57% 50% Payout (Years) NPV10% ($M) $7.9 $7.1 Production Efficiency ($/boed-365) $8,100 $13,200 Mean booked well length 2,500 m (79.0 net wells) Western wells provide commercial inventory of 50 potential net locations (2) Western lands have strong value with torque to liquid prices Eastern lands have strong torque to increasing gas prices Successful 3 rd Party monobore wells expect $1 million less per well with steady program (no intermediate casing and shorter drilling times) (1) Assumes 30 Bbls/MMcf of NGL s and condensate Includes 5% GORR, Opex $2.50 per Boe incremental, $0.27/mcf midstream capital fee excluded Assumes NGTL transport of $0.20/GJ, AECO gas price 5% GORR illustrative. Actual GORR range from 0% to 12.5% (2) Internal estimate based on 300m interwell spacing TSX:CQE 13

14 Capital Sensitivity UPPER MONTNEY ECONOMIC SENSITIVITIES TORQUE TO GAS PRICES ABOVE $2.25 CAD/GJ Internal CQE East & West models $60 WTI US/bbl, $10 US/Edmonton differential, $0.75 CAD/US exchange $2.50 CAD/GJ AECO Price Sensitivity Internal CQE East & West models $10 US/Edmonton differential, $0.75 CAD/US exchange $8 million well cost TSX:CQE 14

15 HEDGING & MARKETING Contract Type Volume Price GJ/d Cdn$ GAS 2019 January 1, 2019 March 31, 2019 Swap 5,000 $4.60/GJ DAWN 2019 January 1, 2019 March 31, 2019 Swap 2,500 $5.57/GJ DAWN 2019 April 1, 2019 June 30, 2019 Swap 2,500 $3.10/GJ DAWN 2019 April 1, 2019 June 30, 2019 Swap 2,500 $3.30/GJ DAWN 2019 July 1, 2018 September 30, 2019 Swap 2,500 $3.04/GJ DAWN OIL Volume Price bbl/d Cdn$ 2019 January 1, 2019 December 31, 2019 Swap 200 $89.83/bbl 2019 January 1, 2019 December 31, 2019 Swap 200 $80.75/bbl April 1, 2018: 10,850 GJ/d contract to Dawn, Ontario (10 year). 1/3 of Corporate gas 35 MMcfd of NGTL firm service commenced December 2017 to March 31, TSX:CQE 15

16 WHY OWN CQE? Restructured $60 million term debt maturing Oct 2022 saving $2.8 million per year in interest Equity raise converting highly commercial Dunvegan oil inventory on 100% CQE lands Large recognized Upper Montney resource with torque to increasing gas prices Recent nearby 3 rd party activity in other Montney benches could expand Cequence opportunities Improved Corporate gas price with Dawn, Ontario marketing contract commenced April 1, 2018 Major facilities & infrastructure in place with excess capacity TSX:CQE 16

17 APPENDIX TSX:CQE 17

18 Cequence Alliance Meter Station Capacity 120 MMcf/d Pembina Lator Truck Terminal CQE 9-10 Field Compressor SIMONETTE EGRESS MAJOR INFRASTRUCTURE BUILT Proposed Pembina Simonette Terminal Alliance/Aux Sable Deep Cut Plant Chicago, Illinois NGTL meter station- March MMcf/d Facility Curr. capacity -Compression 100 MMcf/d -Refrigeration 120 MMcf/d -Cond stabilization 4,500 bpd Company Infrastructure 120 MMcfd refrigeration plant (50% WI) on-stream Jan % available capacity Sales gas heat content 41.7 GJ/e3m3 (1,120 Btu/scf) All major gathering system built Multi-well pad sites built or acquired for entire drilling inventory ½-cycle economics applicable Production Egress Dual connection to NGTL and Alliance pipeline systems 35,000 mcf/d firm capacity on NGTL effective December ,850 GJ/d firm capacity to Dawn effective April 1, MMcfd metering capacity Pembina liquid terminals in close proximity to W5 Facility TSX:CQE 18

19 RESTRUCTURED DEBT 2 nd lien secured $60 million term 5% $7 million undrawn Senior Credit Facility $2.8 million per year interest savings $60 million Term Loan Maturity is October 3, 2022 Annual interest rate of 5% Interest rate increases to 10% if annual funds flow from operations exceeds $40 million 1.84 million warrants at $2.00/ common share issued to lender Standard intercreditor agreement in place $7 million Senior Credit Facility Senior Credit Facility extended to May 2019 No amounts drawn at Sept 30, 2018 (excluding $1.5 million in letters of credit) TSX:CQE 19

20 MANAGEMENT AND BOARD Management Team Todd Brown CEO Kevin Nielsen Contract Interim CFO Dave Robinson VP Ex and Chief Geologist Chris Soby VP Land and Corporate Development Erin Thorson Controller Board of Directors Don Archibald Executive Chairman Peter Bannister Todd Brown Howard Crone Executive VP Brian Felesky Daryl Gilbert TSX:CQE 20

21 FORWARDLOOKING STATEMENTS OR INFORMATION AND DEFINITIONS Forward Looking Information: Certain statements included in this presentation constitute forward-looking statements or forward-looking information (collectively, forward-looking information ) under applicable securities legislation. Certain information included in this presentation also constitutes future-oriented financial information ( FOFI ) under applicable securities legislation. Such forward-looking information and FOFI is provided for the purpose of providing information about management s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking information typically contains statements with words such as anticipate, believe, expect, plan, intend, estimate, propose, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information and FOFI concerning Cequence in this presentation may include, but is not limited to, statements or information with respect to: guidance, forecasts and related assumptions;, the Canadian Development Expense eligibility of the expenses incurred using the proceeds of the Company s 2018 rights offering; expected production growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and future reserves; hedging objectives; business strategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs and results thereof; future net debt and funds flow; commodity pricing and expected royalties; costs associated with operating in the oil and natural gas business; and future production levels, including the composition thereof. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that the expectations reflected in such forward-looking information and FOFI are reasonable; however, undue reliance should not be placed on forward-looking information or FOFI because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of operating the Company s business; the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Forward-looking information and FOFI is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking information and FOFI. These risks and uncertainties may cause actual results to differ materially from the forward-looking information and FOFI. The material risk factors affecting the Company and its business are described in the Company s Annual Information Form which is available at SEDAR at The forward-looking information and FOFI contained in this presentation is made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this presentation are expressly qualified by this cautionary statement. Discovered Petroleum Initially in Place ( DPIIP ) Resources in Place and Contingent Resources: DPIIP is equivalent to discovered resources and is defined in the Canadian Oil and Gas Evaluation Handbook ( COGEH ) as 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. Contingent Resources are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be economically 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. The Contingent Resources estimates and the DPIIP estimates are estimates only and the actual results may be greater or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources except to the extent identified as proved or probable reserves. Cequence has presented certain type curves and well economics which are based on the Company s historical production in the Simonette development area, in addition to production history from analogous Montney and Dunvegan developments located in close proximity. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining the success of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty that Cequence will ultimately recover such volumes from the wells it drills. TSX:CQE 21

22 1400, th Ave S.W. Calgary AB T2P 1K3 Phone: Fax: Contacts: Todd Brown CEO tbrown@cequence-energy.com Don Archibald Executive Chairman darchibald@cequence-energy.com TSX:CQE TSX:CQE 22