Cequence Energy Ltd. Restructured and Focused July 27, 2018 TSX:CQE 1

Cequence Energy Ltd. Restructured and Focused July 27, 2018 TSX:CQE 1

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 20 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

Previous Transitioning RESTRUCTURED & FOCUSED $60 million 9.7% Unsecure senior notes Matures Oct 3, 2018 $60 million 5% 2 nd lien term loan (1) Matures Oct 3, 2022 Equity financing in process $5 million to $8.6 million rights offering (2) CDE eligible Q1 18: 6,970 boe/d 17% liquids June 18 field estimates: (3) 6,850 boe/d 28% liquids 1. Closing and refinancing of the $60 million term loan is conditional upon closing of the Rights Offering 2. Rights Offering is backstopped at $5 million and is anticipated to close on September 13, 2018 3. Includes the north east British Columbia assets that did not close (previously announced April 19, 2018) TSX:CQE 3

RESTRUCTURED DEBT 2 nd lien secured $60 million term loan @ 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 36.8 million warrants at $0.10 / common share Standard intercreditor agreement in place $7 million Senior Credit Facility Senior Credit Facility extended to September 28, 2018 with a commitment by the lender to May 2019 No amounts drawn at June 30, 2018 (excluding $1.5 million in letters of credit) TSX:CQE 4

RIGHTS OFFERING EQUITY RAISE $5 million minimum gross proceeds Up to $8.6 million if full participation 142.8 to 245.5 million additional shares Equity Rights Offering Up to 245.5 million rights being offered Rights offering at $0.035/share $5 million backstopped by Insiders Proceeds to be used for Dunvegan oil development drilling Equity qualifies for Canadian Development Expense flow through Pro-forma common shares at June 30, 2018 245.5 million outstanding 388.3 to 491 million post Rights Offering Dilutive equity instruments 36.8 million warrants @ $0.10 13 million options @ $0.56 TSX:CQE 5

2018 GUIDANCE REINVEST IN DUNVEGAN OIL PRESERVE MONTNEY UPSIDE $2.8 million per year interest savings Minimum $5 million equity raise (000 s, except per share and per unit references) Revised Year Ended December 31, 2018 Average production, boe/d (1) 6,850 Funds flow from operations ($) (2) 17,000 Funds flow from operations per share (2) 0.06 Exploration and development expenditures, ($) 19,500 Operating and transportation costs ($/boe) 14.50 G&A costs ($/boe) 2.60 Royalties (% revenue) 6 Crude WTI (US$/bbl) 65.40 Natural gas AECO (Cdn$/GJ) 1.50 Period end, net debt ($) (3) 66,500 Weighted average basic shares outstanding (4) 287,800 Incremental 6 net Dunvegan wells over next 12 months (1) Average production estimates on a per BOE basis are comprised of 76% natural gas and 24% oil and natural gas liquids. (2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. (3) Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the aggregate principal amount of the senior notes and is calculated based on the minimum standby commitment of $5 million received (4) Weighted average basic shares outstanding is based on the minimum standby commitment of $5 million received and 142,857,000 of incremental shares issued on September 13, 2018. Assuming that the rights offering is fully subscribed for at $8.6 million and 245,528,000 of incremental common shares are issued the weighted average shares would be 318,177,000. TSX:CQE 6

REINVEST IN DUNVEGAN OIL PRESERVE MONTNEY UPSIDE Improving Netback Lower interest & operating cost Increased oil & liquids weighting: 24% up from 17% in first quarter 2018 Large Recognized Inventory 79.0 net booked Montney locations Expanding Dunvegan oil inventory 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

SIMONETTE DUNVEGAN OIL PLAY 06-06 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 2015 2 nd and 3 rd converted late 2017 Positive early response on oil rates and GORs 10-09 16-08 16 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, 26.5 net locations remaining (2) Solution gas gathered to Cequence/KANATA 13-11 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 20. 2. Remaining locations are internal company estimates based on current development plans and subject to change. TSX:CQE 8

12-14 11-14 Dunvegan 2017 YE Bookings (1) (2) PUD (Drilled) PUD Probable Unbooked Locations Planned Drills through H1 2019 SIMONETTE DUNVEGAN LIGHT OIL INVENTORY 04-08 vertical 100% WI lands IP30: 45 BOPD 05-06 vertical delineation 9m gross interval 15-04 100% CQE 09-11 50% CQE 5-7 facility 2,000 bbls/d 740 Hp Compressor Progress to Date: Drilled 3.0 (2.0 net) wells on stream end-march The 3 new wells averaged 601 bbl/operating day per well in May 15-04 (100% CQE) June 2018: 893 bbl/calendar day (19.7 operating days); 12-14 (50% CQE) June 2018: 363 bbl/calendar day (20 operating days) 11-14 (50% CQE) Service rig on location. Expect online the end of July 09-11 hz: produced 105 Mbbl + 745 MMcf in first year 103/04-08 vertical completion & 05-06 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, 2017. (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 9

15-04 04-11 Fish in lateral SIMONETTE DUNVEGAN LIGHT OIL PERFORMANCE & METRICS June producing days (month 3): 102/15-04 19.7 days; 12-14 20 days; 11-14 0 days Strong Well Results 2017/2018 actual costs $4.5 MM/well: 2100 m laterals, 39 frac stages (20% more fracs than historical) 6 of 7 wells at or above production model. 09-11 paid out in Q4 2017 (less than 300 days) Battery connection in July 2017 has improved operational run times & netbacks by more than $5/boe Began moving liquids through 50% CQE owned 13-11 facility for additional production flexibility $65 US WTI, $2.50/GJ CDN 2,000 m well Costs (Drill, Complete, Equip) ($MM) $4.5 $4.0 Drilling Results IP365 Production Rate (bbl/d) 220 220 Reserves (MBOE) 540 540 Economic Indicators F&D ($/BOE) $8.33 $7.41 1st Yr Netback ($/boe) $34.50 $34.50 Recycle Ratio 4.1 4.7 ROR (%) 150% 190% Payout (years) 0.9 0.8 NPV10% ($MM) $6.9 $7.3 Production Efficiency ($/boe-365) $10,150 $9,000 TSX:CQE 10

03/04-08 VERTICAL VS KAYBOB VERTICAL WITH HORIZONTAL OFFSETS Simonette Kaybob South Vertical to Horizontal Production Analog CQE 04-08 vertical well completed in Q3-2017 04-08 vertical producing at or above analog Kaybob verticals DE-RISKING WEST INVENTORY Average offset Kaybob Hz s: 1,400 m, 18-20 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 04-08 vertical well 11

Montney: 140m Thick SIMONETTE MONTNEY 100/11-16-061-27W5M Nordegg Historical CQE Hz placement Upper Montney 1 st Lower Montney placement Lower Montney Paleozoic BIG RESOURCES All zones 121 MMboe proved plus probable booked reserves (1) Montney 3.8 TCF gross Montney resource-in-place (2) PDP: 8.3 MMboe LARGE INVENTORY TP: 49.6 MMboe 51 gross (48.0 net) wells $156.7 MM NPV10% 2P: 100.6 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 45-100 bbl/mmcf 16-33 Montney: IP 365 897 boe/d (22% liquids) 2017 Montney: IP30 840 boe/d (36% liquids) 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, 2017. (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 Third party Lower Montney approximately 180 bbl oil per producing day from 1,100 m lateral. Pump optimization occurring. Typical Montney laterals 2,500 to 3,000+ meters TSX:CQE 12

CEQUENCE SIMONETTE UPPER MONTNEY WEST AREA CHARACTERIZATION Double the condensate rate vs the historical type curves Condensate rate 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 1.Type curves are internally generated, see definitions on page 20. TSX:CQE 13

2,500 m Mean Well (1) 2017 West Montney 16-33 - 3% GORR (50 bbl/mmcfd C5) $65 WTI, $2.50/GJ CDN Parameters Length (m) 2,500 2,850 3,050 Costs (Drill, Complete, Equip) Total ($MM) $7.7 $8.0 $8.6 COMMERCIAL INVENTORY TORQUE TO INCREASING GAS PRICES Drilling Results IP30 Production Rate (MMcf/d) 6.0 3.4 6.8 Reserves (MBOE) 1,120 845 1,500 ORGIP (Bcf) 6.0 3.5 8.0 Economic Indicators F&D ($/BOE) $6.88 $9.47 $5.73 1st Yr Netback ($/boe) $21.60 $31.50 $23.90 Recycle Ratio 3.1 3.3 4.2 ROR (%) 35% 40% 85% Payout (Years) 2.0 2.0 1.2 NPV10% ($M) $4.6 $5.7 $11.7 Production Efficiency ($/boed-365) $11,600 $16,300 $9,600 Mean booked well length increased 25% to 2,500 m (79.0 net wells) New Western wells provide commercial inventory of 50 potential net locations (2) Western lands have strong value with torque to gas & liquid prices $0.50/GJ increase in gas price improves Mean (1) ROR to greater than 50% and adds $1.8 million NPV10% 15+% capital improvements can be realized with steady program (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 Assumes NGTL transport 2017 onward of $0.20/GJ GORR range from 0% to 12.5% (2) Internal estimate based on 300m interwell spacing TSX:CQE 14

2018 & 2019 GUIDANCE REINVEST IN DUNVEGAN OIL PRESERVING MONTNEY UPSIDE (000 s, except per share and per unit references) Year Year Ended Ended 31-Dec-18 31-Dec-19 Average production, boe/d (1) 6,850 6,800 Funds flow from operations ($)(2) 17,000 22,000 Funds flow from operations per share(2) (4) 0.06 0.06 Exploration and development expenditures ($) 19,500 20,000 Operating and transportation costs ($/boe) 14.50 14.00 G&A costs ($/boe) 2.60 2.00 Royalties (% revenue) 6 8 Crude WTI (US$/bbl) 65.40 62.25 Natural gas AECO (Cdn$/GJ) 1.50 1.60 Period end, net debt ($) (3) 66,500 64,000 Weighted average basic shares outstanding(4) 287,800 388,400 (1) Average production estimates on a per BOE basis are comprised of 76% natural gas and 24% oil and natural gas liquids in 2018 and 73% natural gas and 27% oil and natural gas liquids for 2019. (2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. (3) Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the aggregate principal amount of the senior notes and is calculated based on the minimum standby commitment of $5 million received less estimated costs of $125,000. (4) Weighted average basic shares outstanding is based on the minimum standby commitment of $5 million received and 142,857,000 of incremental shares issued on September 13, 2018. Assuming that the rights offering is fully subscribed for at $8.6 million and 245,528,000 of incremental common shares are issued the weighted average shares would be 318,177,000 and 491,056,000 for December 31, 2018 and 2019 respectively and funds flow from operations would be $0.05 and $0.04 for December 31, 2018 and 2019 respectively. TSX:CQE 15

WHY OWN CQE? Restructured $60 million term debt maturing 2022 saving $2.8 million per year Equity raise adding highly commercial Dunvegan oil inventory on 100% CQE lands Improved Corporate gas price with Dawn, Ontario marketing contract commenced April 1, 2018 Large recognized Montney Resource provides torque to improving gas prices Major facilities & infrastructure in place. (1) Volumes include north east B.C. (2) Q2 represents field production estimates from April 1, 2018 to June 30, 2018. Actual financial volumes may vary. TSX:CQE 16

APPENDIX TSX:CQE 17

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 2016-200 MMcf/d 13-11 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. 2016 60% 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 2017 10,850 GJ/d firm capacity to Dawn effective April 1, 2018 320 MMcfd metering capacity Pembina liquid terminals in close proximity to 13-11-62-27W5 Facility TSX:CQE 18

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 19

FORWARD- LOOKING STATEMENTS OR INFORMATION AND DEFINITIONS 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 timing and proceeds of the rights offering, the Canadian Development Expense eligibility of the expenses to be incurred using the proceeds of the rights offering; the timing and terms of the refinance of Cequence s $60 million of unsecured notes; the Company s lender s support for the extension and the new borrowing base of the senior credit facility; 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 forwardlooking 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 Company s lender s support for the extension and the new borrowing base of the senior credit facility; the ability of the Company to satisfy the conditions precedent to the 2nd lien term loan and any other closing conditions relating to 2nd lien term loan or the extension of the senior credit facility; 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 www.sedar.com. 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 20

www.cequence-energy.com 1400, 215 9 th Ave S.W. Calgary AB T2P 1K3 Phone: 403-229-3050 Fax: 403-229-0603 Contacts: Todd Brown CEO tbrown@cequence-energy.com Don Archibald Executive Chairman darchibald@cequence-energy.com TSX:CQE TSX:CQE 21