The New Frontera October 2017

Transcription

1 The New Frontera October 2017

2 Advisories This presentation contains forward-looking statements. All statements, other than statements of historical fact that address activities, events or developments that Frontera Energy Corporation (the Company or Frontera ) believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates or assumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration and development plans and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and natural gas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes in equity markets; perceptions of the Company's prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates or has investments; uncertainties relating to the availability and costs of financing needed in the future; the uncertainties involved in interpreting drilling results and other geological data; and the other risks disclosed under the heading "Risk Factors" in the Company's annual information form dated March 14, 2017 filed on SEDAR at Any forwardlooking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein. In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this presentation due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbon. This presentation contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected capital expenditures, production levels, oil prices and G&A), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management s best estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise. The Company discloses several financial measures in this presentation that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS") (including operating and consolidated Netback and operating and consolidated EBITDA). These measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IRFS. For more information, please see the Company s 2017 Management s Discussion and Analysis dated August 8, 2017 filed on SEDAR at All reserves estimates contained in this presentation were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ) and included in the F1 Report filed on SEDAR. Additional reserves information as required under NI can also be found on SEDAR, under the: (i) Forms F2 Report on Reserves Data by Independent Qualified Reserves Evaluator completed by each of RPS and D&M dated February 27, 2017; and (ii) Form F3 Report of Management and Directors on Oil and Gas Disclosure dated March 14, All reserves presented are based on forecast pricing and estimated costs effective December 31, 2016 as determined by the Company s independent reserves evaluators. The Company s net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources have an associated chance of development (economic, regulatory, market and facility, corporate commitment or political risks). The estimates herein have not been risked for the chance of development. There is no certainty that the Contingent Resources will be developed and, if they are developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the Contingent Resources. It is not an estimate of volumes that may be recovered. Actual recovery is likely to be less and may be substantially less or zero. The values in this presentation are expressed in United States dollars and all production volumes are expressed net of royalties, unless otherwise stated. 2

3 Corporate Snapshot The New Frontera Capital Structure Shares Outstanding (FEC on TSX) (1) Market Cap (1) Cash and Cash Equivalents (2)(3) Long-term Debt (B+ Rated) (3) Minority Interest (3) Enterprise Value ~50MM ~$1,750MM ~$540MM / ~$439MM ~$250MM ~$112MM ~$1,572MM 2017 Operating Expectations Guidance Production (boe/d) 70,000-75,000 Operating EBITDA Capital Expenditures $275-$300MM $250-$300MM Wells Drilled Workovers / Well Services Reserves (December 31, 2016) (4) Proved (boe) Probable (boe) Total Proved + Probable (boe) NPV 10 After Tax (5) NI Basis 117MM 53MM 170MM $1,917MM Q2 17 Production Mix Natural Gas 53% Light & Medium Oil 9% 72.4 Mboe/d 2016 Net 2P Reserves (4) Natural Gas 42% Light & Medium Oil 1 As at September 30, Gross cash balance includes restricted cash current ($34MM) and non-current ($67MM) 3 As at June 30, Prepared by: RPS Energy Canada Ltd. and DeGolyer and MacNaughton. Not shown: Natural Gas Liquids (42 Mbbl) 5 Net present value of future net revenue after deducting future income taxes (discounted at 10%) of the Company s total proved plus probable reserves 8% 170 MMboe 3 38% 50% Heavy Oil Heavy Oil

4 Second Quarter 2017 Operational & Financial Highlights Strong EBITDA and Cash Flow in Excess of Capital Expenditures Q2 17 Q1 17 Average Net Production (1) 72,370 boe/d 72,524 boe/d Revenue $299MM $317MM Operating EBITDA (2,3) $87MM $92MM Combined Realized Price $46.28/boe $45.95/boe Operating Cost (2) $26.53/boe $25.91/boe Operating Netback (3) $19.75/boe $20.04/boe Cash Netback (3) $13.53/boe $12.57/boe Capital Expenditures $36MM $38MM General & Administrative $4.05/boe $4.34/boe Net (loss) income (1) ($52MM) $8MM PRODUCTION / REVENUE / PRICE Flat production helped by increased light and medium oil from Peru, offset by declines in natural gas production in Colombia. Despite Brent oil prices being 6.9% lower quarter over quarter, tighter oil quality differentials, impact of hedges and light and medium oil growth helped realized price improve. OPERATING COST Increased marginally as a result of reactivation costs in Peru. GENERAL & ADMINISTRATIVE Continue to target sub $4 per boe G&A costs as restructuring costs diminish going forward. STRONG CASH FLOW AND EBITDA PERFORMANCE Cash netback increase by 4% due to lower fees paid on suspended pipeline capacity and lower G&A. Cash Netbacks Improve, Focused Capex Maintains Production 1 Net after royalties 2 Excluded Bicentenario off-time 3 Non-IFRS Measures. See Advisories. 4

5 Well Recompletions Drive Improved Capital Efficiencies Cost Effective Production Additions Drilling Activity January February March April May June Q3 (F) Q4 (F) 2017 Drilling Program Development Locations Workovers and Well Services 3 Exploration Wells (Potential 5 with Success) Inactive Well Inventory Provides Future Opportunities Based on Location, Economics, Oil Quality, Oil Price Development Workover Well Service Ability to Keep Production Flat in 1H 2017 Driven by Workover and Well Service Activities Significant Opportunity of Reactivations in Peru, Pending Contract Renegotiation New Approach to Drilling and Completions which is Expected to Deliver Better Initial Rates, Add Reserves, and Lower Costs Active Well Count January February March April May June 5

6 2017 Guidance Reflects Comprehensive Asset Review 2%-9% Exit to Exit Production Growth, Balanced Capex and EBITDA 2017 Capital Expenditures Forecasts Budgeted Capital Expenditures $250 - $300MM Other Forecasts Operating EBITDA (1) $275 - $300MM Maintenance & Development Drilling $170 - $175MM Estimated Total Exit Production 70-75Mboe/d Facilities & Infrastructure $50 - $60MM Brent Oil Price Assumption $50/bbl Exploration Expenditures $30 - $65MM Benchmark Price Differential $7 - $7.50/bbl Increased Operating EBITDA Guidance, Balanced with Capital Expenditures 1 Non-IFRS measure: See Advisories 6

7 The New Frontera Strategy Balance Returns on Invested Capital, Growth, Oil Mix, and Geographies Returns Focused Development of Assets Key Asset Areas: Deep Llanos Central Llanos Heavy Oil at Quifa and CPE-6 Peru Exploration Upside Key Prospects: Guatiquia (Alligator 1x) Block 192 Llanos 25 Orito A Limestone Strategic Near Term Catalysts High Impact: Contract Renegotiations (Peru, Pipeline Tariffs, Reduced Commitments/Liabilities) Continued Portfolio Optimization (Midstream, Power Assets) Strategic: EBITDA Expansion Through Cost Control and Improved Operational Discipline Improved Capital Efficiencies Through Operational Execution 7

8 Strategic Review of Assets Portfolio Enhancement: Detailed Reservoir Study During the second quarter of 2017, consistent with the new progressive and disciplined approach to capital allocation, the Company made the strategic decision to slow down production volumes and focus its resources on conducting reservoir studies to enhance the value of our portfolio over the long term. Outcomes impacted the following producing blocks: Quifa SW and Cajua Reservoir studies were commenced to optimize the placement of future development wells and evaluate the potential for more efficient well designs (multi-laterals). The Company will be moving from 2 rigs at the end of the second quarter to 6 rigs by the end of 2017; Guatiquia To ensure prudent reservoir management, reservoir studies were undertaken to optimize the locations of injector wells for pressure maintenance. The first injector well in the Ardilla Field will be drilled in the fourth quarter of 2017 in conjunction with the acceleration of the development drilling; CPI Blocks (Orito and Neiva) The Company is also re-evaluating the forward development program for these two fields. A pilot water injection program in Neiva to enhance recovery is being evaluated. The Company will also assess the production potential of the A Limestone in the Orito Field through the recompletion of two existing wells. Positive results could result in increased activity in 2018 Copa Field Reservoir injectivity tests have been successfully completed, indicating that future injector wells will be able to effectively provide reservoir pressure maintenance support to increase production from the Copa Field. 8

9 Leading Latin American Upstream Portfolio Diversified Portfolio of Production, Development and Exploration Frontera Production History (Mboe/d) Q'16 4Q'16 1Q'17 2Q'17 Exit Guidance Colombia Peru 9

10 Production & Development Optimization Quifa: Legacy Heavy Oil Asset Acreage (Net Acres) 159,572 Working Interest (%) 60% Base Royalty Rate (%) 6.4% +(PAP at >US$54/bbl) P Certified Reserves 61MMbbl Operator/Partner Frontera/Ecopetrol Q2 17 Production (Net) 24,700 bbl/d 2017 Capital Expenditure ~$86MM Currently producing ~25 Mbbl/d net 65 well infill program expected to largely mitigate short-term production decline 15 well vertical program targeting reserve replacement Cajúa: technical study initiated with the goal of improving oil rates, limiting water production and evaluating the future potential; currently producing ~1,200 bbl/d Adding up to two rigs in Q to accelerate program as a result of revised reservoir model Jaspe: potential exploration upside opportunity Q plan incudes the drilling of at least one well Currently under technical review 10

11 Production & Exploration Upside Guatiquía: Building on Deep Llanos Success Acreage (Net Acres) 14,372 Working Interest (%) 100% Base Royalty Rate (%) 8% + (PAP) P Certified Reserves 10MMbbl Operator Frontera Q2 17 Production (Net) 16,400 bbl/d 2017 Capital Expenditure ~$55MM Recent development success at Avispa-14, Avispa-8, Ardilla 2 and Ardilla 3 Drilling Ardilla 4 & injector, and Avispa-9, 11 & 12 in Q4, potentially two or three rigs for development and exploration Ardilla-3 LS-1 encountered 62 feet of pay, extending the area of reservoir closure On production for 60 days at 1,615 bbl/d with a 17% water cut Implement water injection by year end to improve targeted recovery from ~30% to ~50% in 2018 Ceibo-1 recompleted in the Guadalupe formation On production for 62 days at 727 bbl/d; with a 76.5% water cut Both Ardilla-3 and Ceibo-1 have added to our inventory of future drilling locations Currently updating reservoir simulation model to optimize development of several additional pools 11

12 Significant Exploration Upside Llanos 25: Acorazado Exploration Upside and Reserve Replacement Acreage (Net Acres) 169,805 Working Interest (%) 100% Base Royalty Rate (%) 9% (8% + 1%X) Operator Frontera Proven hydrocarbon fairway on trend with Cusiana & Cupiagua fields Potential high rate wells (10,000bbl/d unrisked) (1) 273 km 2 of high quality 3D seismic data and extensive reprocessed 2D seismic data Acorazado prospect potential impact: mean original oil-in-place of 154 MMbbl Three other additional exploration prospects along trends of producing fields Multiple development follow-up locations exist based on success case Existing accessible Infrastructure nearby Fulfills $23MM exploration commitment with ANH (estimated investment $25-50MM) Well to be spud in Q Contingent resources. See Advisories. 12

13 Production & Development Cubiro: Growing with Secondary Recovery & Enhanced Field Development. Acreage (Net Acres) 9143 Working Interest (%) 100% Base Royalty Rate (%) 8% + (PAP) P Certified Reserves 14MMbbl Operator Frontera Q2 17 Production (Net) 3,400 bbl/d 2017 Capital Expenditure ~$16MM Recent development successes were horizontal wells is Copa-23H, Copa-26H, and Copa 29H Drilling Copa A Norte-4stH and Copa-27H in Q Estimation of OOIP is approximately 100 MMBBL with only 11.5 MMBBL produced. Recent successful water injection tests and implementation of a water flood project in the Copa Field in Q is expected to significantly increase the recovery factor from the current 11.5% The water-flooding project will commence in Carbonera C-5 reservoir and will then be implemented in other reservoirs Based on the successful injectivity tests Frontera is currently building a reservoir simulation model to optimize the secondary recovery development of the field and optimize the water flood efficiency 13

14 Production & Exploration Upside CPE-6: Exploration Upside and Reserve Replacement Acreage (Net Acres) 593,018 Working Interest (%) 100% Base Royalty Rate (%) 8.4% (6.4% + 2%X) P Certified Reserves 22MMbbl Operator Frontera Q2 17 Production (Net) 1,300 bbl/d 2017 Capital Expenditure ~$6.6MM Heavy oil field currently producing approximately 1,300 bbl/d Hamaca: two horizontal wells to be drilled by end 2017 Surrounding area covered with 3D seismic + 2 D seismic Two exploration wells to be drilled by the end of 2017 Substantial exploration acreage opportunity Environmental licence in place for Hamaca and vicinity Evaluation program under way Declaration of commerciality due January

15 Production & Exploration Upside Block 192: Production Growth Opportunity Acreage (Net Acres) 1,266,037 Working Interest (%) Royalty Rate (%) Cumulative Production (as of Dec 2016) Operator Under Negotiation Under Negotiation 729MMbbl Frontera Largest oil producing block in Peru: nearterm production potential of 5 to 10 Mbbl/d Opportunity to add significant production and reserves by extending the contract with the Peruvian government Significant exploration upside (negotiations underway) (1) Contains 15 producing fields with varying API gravities (light, medium and heavy) Three shut-in heavy oil pools Pipeline repaired and production ramp-up initiated from ~2 Mbbl/d to as much as 10 Mbbl/d by YE 2017 Q2 17 Production (Net) 4,700 bbl/d 1 The Company is currently negotiating with Peruvian authorities on an extension of the Block 192 production contract. If the contract is extended, the Company will have Block 192 s reserves certified in accordance with NI However, until the contract is awarded, there is uncertainty that it will be commercially viable to produce any portion of the resources. Therefore these are considered contingent resources. See advisories 15

16 Unlocking Value: Asset Sale Summary Over $250 Million in Cost Savings Achieved to Date Below is a summary of all the non-core asset sales of exploration and production blocks executed by the Company to date; many are pending final government approvals $ millions Block Country Buyer Cash Exploratory SBLC / Proceeds Commitments (1) Collateral (2) Santos Basin Brazil Karoon Gas North Basins Brazil Queiroz Galvao (10.0) Lote 131 Peru CEPSA PUT-9 Colombia Amerisur Mecaya Colombia Amerisur Terecay Colombia Amerisur Tacacho Colombia Amerisur Casanare Este Colombia Gold Oil SSJN-7 Colombia Canacol Lote 126 Peru Maple Gas Cerrito Colombia PetroSouth PNG Blocks Papua - NG Exxon Mobil Total Includes Abandonment/Environmental Costs 2 Standby Letter of Credit / Released Collateral 16

17 Unlocking Value: Monetizing Hidden Value Non-Core Midstream & Infrastructure Monetizable Assets PUERTO BAHÍA (41.8% Gross (1), 39.6% Net (2) ) Other Major Shareholders: International Finance Corporation ( IFC Member of World Bank) (3) 28%, Blue Pacific 20.4% Greenfield liquids import-export terminal with a 2.4 MMbbl storage capacity and a dry terminal for various types of cargo Focusing on adding value through volume in dry terminal with opportunities to connect to a nearby refinery; when implemented, EBITDA (5) could double (currently ~US$50MM) PETROELÉCTRICA DE LOS LLANOS (4) (100.0% Gross (1), 63.6% Net (2) ) Power transmission line of 230 kv that connects Llanos Basin oilfields to Colombia s national energy grid Petroeléctrica is a key piece of infrastructure for the Company as it supplies energy for the development of Quifa and other nearby fields in the Llanos Basin, including the Sabanero block, CPE-6 block and the ODL pipeline system Monetization process/progress TBD Monetization process/progress 75% Near-term value of $180MM - $200MM not reflected in share price 1 Holding company s interest 2 Frontera interest through holding company 3 In 2013, IFC invested $150MM in Pacific Infrastructure 4 In 2014, IFC invested $240MM in Pacific Midstream, which holds Petroeléctrica de los Llanos interest, for 36.36% 5 Non-IFRS Measures. See Advisories. 17

18 Unlocking Value: Reducing Costs, Increasing Cash Flow Addressing Highly Fixed Transportation Costs UPDATE Bicentenario PIPELINE (1) (43% Gross (2), 28.9% Net (3) ) Runs from Araguaney to Banadia, connecting to Caño Limón-Coveñas (CLC) pipeline Committed Capacity: 47,333 bbl/d Cost Reduction Initiatives: Capture savings from lower tariffs as a result of operational cost reductions within BIC Working with joint owners CENIT and IFC to reduce takeor-pays and align owners interests Transportation cost $14.28 $14.50 $14.00 OCENSA PIPELINE OCENSA runs from either the Cusiana station or the El Porvenir station and transports oil to the Coveñas terminal Committed Capacity: 30,000 bbl/d, effective July 1, 2017 Cost Reduction Initiatives: Negotiation of a reduced tariff Assignment of spare capacity to third parties Suspended Pipeline Capacity Q1'17 Q2' Exit $4.2 $3.5 ODL PIPELINE (1) (35.0% Gross (2), 22.3% Net (3) ) Transports heavy crude oil from Quifa and Cajúa fields to be shipped via Bicentenario or OCENSA Committed Capacity: 29,238 bbl/d 1 In 2014, IFC invested $240MM in Pacific Midstream, which holds the Bicentenario interest, for 36.36% 2 Holding company s interest 3 Frontera interest through holding company 18

19 Balance Sheet Strength Cost Reduction Initiatives Continue Balance Sheet Metrics (June 30, 2017) Debt to Book Cap 17.3% Gross Debt/EBITDA (1) 0.9x Net Debt/EBITDA (1) (0.7x) Interest Coverage (1) 11.3x Evolution of Frontera G&A Cost ($/boe) $6.34 $5.37 $3.10 $2.56 $ % Reduction (2) $4.05 No Debt Maturities until 2021 Q1'16 Q2'16 Q3'16 Q4'16 Q1'17 Q2'17 1 Assumes midpoint of 2017 Operational EBITDA Guidance of $287.5 million 2 Source: Frontera s Reported 1Q 17 versus Reported Q

20 Liabilities Continue to Decrease Balance Sheet Improvement Continues Others liabilities (1) Accounts payable and accrued liabilities 6, , % Variation (Q2 17 vs. Q2 16) -5% Variation (Q2 17 vs. Q1 17) -8% -38% -9% Loans and borrowings 5,803 5,815-96% 0% 315 1, , ,061-7% Q2 16 Q Q Q Q2 17 Liabilities remain stable in comparison with Q1 17 and variations are related to the operation of the Company during the period. In comparison with Q2 16 liabilities decreased 85% mainly due to restructuring transaction finalization 1 Other liabilities includes: oil hedge contracts liability, income tax payable, finance lease and asset retirement obligation 20

21 Positive Working Capital Growing Working Capital, Normalized Sales and Payment Cycle Working capital Cash and cash equivalents Accounts receivable Inventories and others Cash and cash equivalents Trade receivable Crude oil inventory Restricted cash Other receivables Material Inventory Receivable from joint arrangements Other Assets (1) % Current Assets (2) % VAT % % Q2 16 Q3 16 Q4 16 Q1 17 Q Days sales Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q2 16 Q3 16 Q Days AR trade/sales Q Q Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q2 17 working capital increased 22% mainly due to the short term receivable related to Exxon (Papua) reclassified from long term receivable Current Liabilities (2) Trade Payable OPEX CAPEX G&A Q2 16 Q3 16 Q % Q1 17 Q2 17 Others Payable Payroll Payables from joint arrangements Withholding tax and provisions Others contingent liabilities -3% Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Days costs Capex, G&A and Opex Days OPEX AP /OPEX Other assets includes: income tax receivable, assets held for sale, risk management asset and prepaid expenses 2 Days of Cash & Cash Equivalents, accounts receivables and inventories and others are calculated on average sales by quarter. Accounts payables are calculated on average cost, G&A and CAPEX by quarter. Non-controlled cash balances and loans for Q2 16 are excluded from the above figures 21

22 Significant Value with Catalysts for Upside Frontera Trades at a Deep Discount to Peers, Unique Upside Opportunity Enterprise Value ( EV ) / 2017 EBITDA (1) EV / 2P Reserves ($ per boe) (2) 8.0x 6.0x 4.0x 6.8x 6.6x 6.2x 4.6x 4.6x $20 Average $16.01 $15 4.1x $10 $11.64 $10.23 $8.79 Average $6.13 $ x $5 0.0x Canacol Amerisur Parex GeoPark Gran Tierra Frontera EV / Daily Production ($ per boe/d) $0 Parex Amerisur Canacol Gran Tierra Frontera GeoPark 2017E Debt / Cash Flow $60,000 $50,000 $50,787 $49,073 $47,517 Average 3.0x 2.0x 2.6x 2.2x Average $40,000 $30,000 $20,000 $10,000 $36,556 $29,393 $14, x 0.0x (1.0x) 1.0x (0.2x) (0.5x) $0 Parex Canacol Amerisur Gran Tierra GeoPark Frontera (2.0x) (1.8x) Canacol GeoPark Gran Tierra Frontera Parex Amerisur 1 Enterprise Value fully diluted market capitalization adjusted for total debt, net working capital, investment in associates, noncontrolling interests and asset retirement obligations as of June 30, 2017 market close 2 Reserves as at December 31,

23 Reasons to Own Frontera Significant Value with Catalysts 1. Compelling Discounted Valuation & Near-term Catalysts to Unlock Value: Contract renegotiations (Peru, Pipelines) Portfolio optimization through non-core asset dispositions Exploration drilling opportunities (Alligator 1x, Llanos 25) EBITDA growth through continued cost control 2. Capex within operating EBITDA = sustainable growth 3. Balance sheet strength 4. Successful EBITDA expansion strategy 5. Disciplined management team focused on returns and economic growth 23

24 Appendix

25 Restructuring Process and Go Forward Strategy Path to Increasing Equity Demand and Liquidity 2H 2017 aggressive marketing campaign Go-forward strategy disseminated across the market place Enhance capital markets profile and familiarize investors with Frontera s story Communicate goforward strategy for reserves replacement, production growth, exploration upside Amend existing debt covenants for improved flexibility Strategy to narrow Company s focus and reduce exploration commitments Non-core asset divestment strategy reducing commitments and increasing liquidity In PROGRESS Marketing Roadshow Go-Forward Strategy Ongoing Complete Restructuring of Frontera Portfolio Optimization Program Ongoing Complete New Leadership Team Cost Improvement Program Ongoing Creditor and Catalyst led restructuring completed reducing overall debt to $250MM from $5.4BN and appointment of new Independent Board Announced Gabriel de Alba as Chairman, Barry Larson as CEO New Board of Directors and New Management Team Optimization and cost reduction programs showing incremental value early in 2017 Annualized G&A is anticipated to be in the range of $90 to $100MM, targeting a 45% to 50% reduction over 2016 expenses 25

26 Capital Markets Strategy and Planning Unlocking the Value with a Proven Plan Deliver on our Catalysts: Peru Extension / Renegotiation Production Guidance Asset Optimization Exploration Deliver a 2018 Budget that includes production growth and exploration upside Continue to work on managing and reducing exposure and cost of fixed transportation commitments Conference and Non Deal Roadshows in 2H 2017 to target over 250 client interactions Increase daily liquidity to over C$3MM in daily value traded from current level of ~C$0.8MM Increase the number of sell-side analysts covering the stock from 1 currently Enhance our opportunity for index inclusion (some peers are included in over 50 indices) 26

27 USD/bble Current Hedging Portfolio As at September 25, 2017 $ FWD Sep 25th Floor Ceiling Price level used for market guidance $ $ $48 SEP OCT NOV DIC JAN FEB MAR APR MAY JUN JUL Hedged Volumes 1,440K 1,440K 1,440K 1,440K 1,200K 1,200K 1,200K 1,200K 1,200K 1,200k 1,200K 27

28 Transportation Commitments Summary Capacity and Commitments Balanced when Bicentenario Working Commitments (As per Note 16 of Financial Statements) Transportation (Take or Pay/Ship or Pay) 3, ,116 3, Other ToP (3) P135 (4) CENIT (CLC) BIC - 110K BPD BIC system (5) at $1.9 Billion 1,272 Note 17 Financial Statements Exploratory (1) Others (2) Transportation (ToP s/sop s) Total 2017 (3) 2018 (4) Subsequent Exploratory minimum work commitments as of June 30, 2017 includes Queiroz $26MM and Amerisur blocks $26MM 2 Others include: Operating leases and procurement $53MM and communities $6MM 3 Other ToPs include: Port $174MM (could be reduced depending on sale of asset/s), ODL $156MM, Darby $122MM, others $19MM (Cusiana offloading, Monterey-El Porvenir pipeline and Santiago offloading contracts) and gas transport and purchases $11MM 4 Ocensa P135 commitment was calculated using 30Kbbl/d at rate of $8.55/bbl. (Rate is under review by the supplier) 5 Bicentenario Pipeline connects Araguaney, in the Casanare Department of central Colombia, to the Coveñas Export Terminal in the Caribbean 28

29 2016 Reserves Revisions Prudently Reassessed Reserves, D&M and RPS Reviewed Economic write-down due to lower oil prices Technical write-down P 2016 Río La Lote Z1 Other Quifa Guatiquía CPE P Production Ariari Creciente Revisions 29

30 Proven Management Team Latin American Expertise and Strategic Know How Barry Larson CEO Camilo McAllister CFO Camilo Valencia VP, Operations Renata Campagnaro VP, Supply, Transportation & Trading Over 40 years of oil & gas industry experience including 21 years of international experience Former VP, Ops. & COO of Petro Andina and subsequently Parex after the company was acquired Co-founder and former VP of Aventura Energy, a South American E&P company Experienced as an Operating Partner for PE funds and has held several CEO positions at portfolio companies Formerly with BP for 15 years including positions in Investor Relations, Finance and Planning & Performance With the Company for 10 years holding positions of Drilling Manager, General Manager, Executive Vice President and President of Pacific E&P Peru As President of Pacific Peru he was in charge of developing offshore and jungle operations With the Company since 2010; over 36 years experience in the oil & gas industry focused on supply operation, trading, and business development Former Managing Director of Petróleos de Venezuela Do Brasil Erik Lyngberg VP, Exploration Duncan Nightingale VP, Development Jorge Fonseca VP, Business Development Has over 30 years experience in the global oil & gas industry Former SVP, Exploration at Petrominerales; former Chief Geologist of Petrobank Energy Has over 30 years experience in the global oil & gas industry Formerly Chief Operating Office at Gran Tierra Energy With the Company since 2012, integral part of the restructuring process Has over 18 years experience of investment banking experience with Citibank, BBVA and CAF Peter Volk General Counsel & Secretary With the Company since 2004; has over 30 years legal and 20 years industry experience Formerly with Blake, Cassels & Graydon LLP in their securities group 30

31 Independent Board of Directors Engaged and Active in Generating Shareholder Value Gabriel de Alba Chairman Luis F. Alarcon Director Ellis Armstrong Director Managing Director and Partner of The Catalyst Capital Group Inc. International experience restructuring public and private companies, unlocking value for investors Former President of the Colombian Association of Pension Funds Former CEO of Interconexion Electrica S.A. Former CEO of Flota Mercante GranColombiana Currently serves as Chairman of the Board of Directors of Grupo Sura and Almacenes Exito Over 35 years of international experience in the oil & gas industry with BP where he held roles in Argentina, Colombia, Venezuela, Trinidad, Alaska, and the North Sea Former CFO of BP s global exploration and production business Currently serves as Independent director of Lamprell plc and Lloyds Register Group Raymond Bromark Director Russell Ford Director Camilo Marulanda Director Former Partner of PwC where he served for almost 40 years Led the PwC Professional, Technical, Risk and Quality Group Currently serves as Director and Chair of the Audit Committee for YRC Worldwide Inc., Tesoro Logistics GP LLC, and CA Inc. Over 35 years of experience in the oil & gas industry primarily with Shell Former EVP, Contracting & Procurement, EVP, Onshore, and Head of EP Strategy and Portfolio at Shell Former VP at Western Hemisphere Former CEO of CENIT Former COO of Ecopetrol 31

32 INVESTOR RELATIONS CONTACT: Grayson M. Andersen Corporate Vice President, Capital Markets Calle 110, No 9 25, Piso 16 Bogota DC, Colombia +57 (314) gandersen@fronteraenergy.ca ir@fronteraenergy.ca