The New Frontera October 2017 Advisories This presentation - - PowerPoint PPT Presentation

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

• ther 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 www.sedar.com. Any forward- looking 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

• perations 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

• therwise. 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 www.sedar.com. 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 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and included in the F1 Report filed on SEDAR. Additional reserves information as required under NI 51-101 can also be found on SEDAR, under the: (i) Forms 51-101F2 – Report on Reserves Data by Independent Qualified Reserves Evaluator completed by each of RPS and D&M dated February 27, 2017; and (ii) Form 51-101F3 – Report of Management and Directors on Oil and Gas Disclosure dated March 14, 2017. 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 2016. 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.

3

Corporate Snapshot

The New Frontera

Capital Structure Shares Outstanding (FEC on TSX)(1) ~50MM Market Cap(1) ~$1,750MM Cash and Cash Equivalents(2)(3) ~$540MM / ~$439MM Long-term Debt (B+ Rated)(3) ~$250MM Minority Interest(3) ~$112MM Enterprise Value ~$1,572MM 2017 Operating Expectations Guidance Production (boe/d) 70,000-75,000 Operating EBITDA $275-$300MM Capital Expenditures $250-$300MM Wells Drilled 50-60 Workovers / Well Services 80-90 Reserves (December 31, 2016)(4) NI 51-101 Basis Proved (boe) 117MM Probable (boe) 53MM Total Proved + Probable (boe) 170MM NPV 10 After Tax(5) $1,917MM

38% 53% 9%

Light & Medium Oil Heavy Oil Natural Gas

72.4 Mboe/d /d

Q2’17 Production Mix

50% 42% 8%

Heavy Oil

2016 Net 2P Reserves(4) 170

MMboe Natural Gas

probable reserves

Light & Medium 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. 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

GENERAL & ADMINISTRATIVE Continue to target sub $4 per boe G&A costs as restructuring costs diminish going forward.

Well Recompletions Drive Improved Capital Efficiencies

Cost Effective Production Additions

680 690 700 710 720 730 740 750 760 770 January February March April May June

2017 Active Well Count 2017 Drilling Program

• 50-60 Development Locations
• 80-90 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 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

5 5 10 15 20 25 30 35 40 January February March April May June Q3 (F) Q4 (F)

2017 Drilling Activity

Development Workover Well Service

6

2017 Guidance Reflects Comprehensive Asset Review

2017 Capital Expenditures Forecasts Budgeted Capital Expenditures $250 - $300MM Maintenance & Development Drilling $170 - $175MM Facilities & Infrastructure $50 - $60MM Exploration Expenditures $30 - $65MM Other Forecasts Operating EBITDA(1) $275 - $300MM Estimated Total Exit Production 70 - 75Mboe/d Brent Oil Price Assumption $50/bbl Benchmark Price Differential $7 - $7.50/bbl

2%-9% Exit to Exit Production Growth, Balanced Capex and EBITDA

Increased Operating EBITDA Guidance, Balanced with Capital Expenditures

7

The New Frontera Strategy

Returns Focused Development of Assets Key Asset Areas:

• Deep Llanos
• Central Llanos
• Heavy Oil at Quifa and CPE-6
• Peru

Balance Returns on Invested Capital, Growth, Oil Mix, and Geographies

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

Exploration Upside Key Prospects:

• Guatiquia (Alligator 1x)
• Block 192
• Llanos 25
• Orito “A” Limestone

8

Strategic Review of Assets

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

fa 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;

• Guati

tiquia uia – 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

ks (Orit ito and Neiv iva) – 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

ld – 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.

Portfolio Enhancement: Detailed Reservoir Study

9

Leading Latin American Upstream Portfolio

Diversified Portfolio of Production, Development and Exploration

75.1 69.4 72.5 72.4 70 70 - 75 75

20 40 60 80 3Q'16 4Q'16 1Q'17 2Q'17 Exit Guidance

Colombia Peru

Frontera Production History (Mboe/d)

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) 2016 2P 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 Q3 2017 to accelerate

program as a result of revised reservoir model

• Jaspe: potential exploration upside opportunity

− Q1 2018 plan incudes the drilling of at least

• ne well

− Currently under technical review

11

Production & Exploration Upside

Guatiquía: Building on Deep Llanos Success

• 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

Acreage (Net Acres) 14,372 Working Interest (%) 100% Base Royalty Rate (%) 8% + (PAP) 2016 2P Certified Reserves 10MMbbl Operator Frontera Q2’17 Production (Net) 16,400 bbl/d 2017 Capital Expenditure ~$55MM

12

Significant Exploration Upside

Llanos 25: Acorazado Exploration Upside and Reserve Replacement

• Proven hydrocarbon fairway on trend with

Cusiana & Cupiagua fields

• Potential high rate wells (10,000bbl/d

unrisked)(1)

• 273 km2 of high quality 3D seismic data and

extensive reprocessed 2D seismic data

• Acorazado prospect potential impact: mean
• riginal 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 Q1 2018

Acreage (Net Acres) 169,805 Working Interest (%) 100% Base Royalty Rate (%) 9% (8% + 1%X) Operator Frontera

13

Production & Development

Cubiro: Growing with Secondary Recovery & Enhanced Field Development.

• Recent development successes were

horizontal wells is Copa-23H, Copa-26H, and Copa 29H

• Drilling Copa A Norte-4stH and Copa-27H in

Q4 2017

• 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 Q4 2017 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

Acreage (Net Acres) 9143 Working Interest (%) 100% Base Royalty Rate (%) 8% + (PAP) 2016 2P Certified Reserves 14MMbbl Operator Frontera Q2’17 Production (Net) 3,400 bbl/d 2017 Capital Expenditure ~$16MM

14

Production & Exploration Upside

CPE-6: Exploration Upside and Reserve Replacement

• 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
• pportunity
• Environmental licence in place for

Hamaca and vicinity

• Evaluation program under way
• Declaration of commerciality due January

2018

Acreage (Net Acres) 593,018 Working Interest (%) 100% Base Royalty Rate (%) 8.4% (6.4% + 2%X) 2016 2P Certified Reserves 22MMbbl Operator Frontera Q2’17 Production (Net) 1,300 bbl/d 2017 Capital Expenditure ~$6.6MM

15

Production & Exploration Upside

Block 192: Production Growth Opportunity

• Largest oil producing block in Peru: near-

term 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

Acreage (Net Acres) 1,266,037 Working Interest (%) Under Negotiation Royalty Rate (%) Under Negotiation Cumulative Production (as of Dec 2016) 729MMbbl Operator Frontera Q2’17 Production (Net) 4,700 bbl/d

extended, the Company will have Block 192’s reserves certified in accordance with NI 51-101. 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

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 Bloc

• ck

Country Buyer er Cash Proc

• ceeds

ds Explor lorat ator

• ry

Comm mmitme itments ts(1

(1)

SBLC C / Collat llater eral al(2) Santos

• s Basin

in Brazil Karoon Gas 15.5 50.8 0.0 North th Basins ins Brazil Queiroz Galvao (10.0) 25.6 42.5 Lot

• te

e 131 Peru CEPSA 17.1 8.8 0.0 PUT-9 Colombia Amerisur 0.7 9.1 0.9 Mec ecaya Colombia Amerisur 0.6 5.2 0.8 Terecay Colombia Amerisur 0.1 8.1 0.8 Tac acac acho ho Colombia Amerisur 3.5 4.1 0.4 Casan sanar are e Este Colombia Gold Oil 2.0 12.0 0.8 SSJN JN-7 Colombia Canacol 0.0 7.8 2.5 Lot

• te

e 126 Peru Maple Gas 0.2 13.9 2.8 Cerrit ito Colombia PetroSouth 0.1 0.9 0.0 PNG Bloc

• cks

Papua - NG Exxon Mobil 57.0 0.0 0.0 Total tal 86.8 146.3 51.5

$ millions

17

Unlocking Value: Monetizing Hidden Value

Non-Core Midstream & Infrastructure Monetizable Assets

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 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)

Near-term value

• f $180MM -

$200MM not reflected in share price

TBD

Monetization process/progress

75%

Monetization process/progress

18

Unlocking Value: Reducing Costs, Increasing Cash Flow

Addressing Highly Fixed Transportation Costs

Transportation cost

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

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

• perational cost reductions within BIC

− Working with joint owners CENIT and IFC to reduce take-

• r-pays and align owners’ interests

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

$14.28 $14.50 $14.00 Q1'17 Q2'17 2017 Exit $4.2 Suspended Pipeline Capacity $3.5

UPDATE

19

Balance Sheet Strength

Cost Reduction Initiatives Continue

Evolution of Frontera G&A Cost ($/boe)

$2.56 $3.10 $5.37 $6.34 $4.34 $4.05 Q1'16 Q2'16 Q3'16 Q4'16 Q1'17 Q2'17

36%

Reduction (2)

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 No Debt Maturities until 2021

20

Liabilities Continue to Decrease

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

Other liabilities includes: oil hedge contracts liability, income tax payable, finance lease and asset retirement obligation

• 96%
• 38%
• 5%

0%

• 9%
• 8%

Others liabilities(1) Q1’17 1,136 1,061 Accounts payable and accrued liabilities 537 250 Q2’17 Loans and borrowings 274

• 85%

5% Q4’16 1,141 587 250 299 315 250 862 764 5,803 6,953 Q3’16 5,815 576

• 7%

7% 343 288 Q2’16 6,922

Vari riation tion (Q2’17 vs. Q2’16) Vari riation tion (Q2’17 vs. Q1’17)

Balance Sheet Improvement Continues

21

Positive Working Capital

Other assets includes: income tax receivable, assets held for sale, risk management asset and prepaid expenses

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

343 Q4’16 205 Q1’17 134 280 +22% +22% Q2’17 Q3’16 Q2’16 323

• 7%

Working ing capit ital al Cash h and cash h equivalents alents

• 3%

Invent ntor

• rie

ies and others

Account

• unts recei

eivab able Current Assets (2) Current Liabilities (2)

• Cash and cash equivalents

Days sales Days costs Capex, G&A and Opex

• 13%

Days AR trade/sales

Q2’17 working capital increased 22% mainly due to the short term receivable related to Exxon (Papua) reclassified from long term receivable Trade Payab able le Others Payable

Growing Working Capital, Normalized Sales and Payment Cycle

Significant Value with Catalysts for Upside

Frontera Trades at a Deep Discount to Peers, Unique Upside Opportunity

Enterprise Value (“EV”) / 2017 EBITDA(1) EV / Daily Production ($ per boe/d) 2017E Debt / Cash Flow EV / 2P Reserves ($ per boe)(2)

controlling interests and asset retirement obligations as of June 30, 2017 market close

22 6.8x 6.6x 6.2x 4.6x 4.6x 4.1x 0.0x 2.0x 4.0x 6.0x 8.0x Canacol Amerisur Parex GeoPark Gran Tierra Frontera Average

$16.01 $11.64 $10.23 $8.79 $6.13 $5.54 $0 $5 $10 $15 $20

Parex Amerisur Canacol Gran Tierra Frontera GeoPark

Average

$50,787 $49,073 $47,517 $36,556 $29,393 $14,845 $0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 Parex Canacol Amerisur Gran Tierra GeoPark Frontera Average 2.6x 2.2x 1.0x (0.2x) (0.5x) (1.8x) (2.0x) (1.0x) 0.0x 1.0x 2.0x 3.0x Canacol GeoPark Gran Tierra Frontera Parex Amerisur Average

23

Reasons to Own Frontera

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

Significant Value with Catalysts

Appendix

25

Restructuring Process and Go Forward Strategy

Path to Increasing Equity Demand and Liquidity

Complete

Restructuring

• f Frontera

Portfolio Optimization Program

Complete Ongoing

New Leadership Team Marketing Roadshow Cost Improvement Program Go-Forward Strategy

In

Ongoing 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

• Strategy to narrow

Company’s focus and reduce exploration commitments

• Non-core asset

divestment strategy reducing commitments and increasing liquidity

• Communicate go-

forward strategy for reserves replacement, production growth, exploration upside

• Amend existing debt

covenants for improved flexibility

• 2H 2017 aggressive

marketing campaign

• Go-forward strategy

disseminated across the market place

• Enhance capital

markets profile and familiarize investors with Frontera’s story

26

Capital Markets Strategy and Planning

• 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

Unlocking the Value with a Proven Plan

• 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)

27

Hedged Volumes

1,440K 1,440K 1,440K 1,440K 1,200K 1,200K 1,200K 1,200K 1,200K 1,200K 1,200k

55.63 58.04 57.64 57.36 57.17 57.02 56.88 56.75 56.64 56.52 56.37 50.43 51.56 50.28 49.52 49.11 49.95 50.06 50.77 51.10 51.23 52.00 60.00 59.60 57.14 55.16 55.45 55.28 55.37 55.73 55.86 55.91 59.31

50

$48 $52 $56 $60

SE SEP OCT OCT NOV OV DIC IC JAN FEB FEB MA MAR APR PR MA MAY JUN JUL

USD/bble

FWD Sep 25th Floor Ceiling Price level used for market guidance

Current Hedging Portfolio 2017-2018

As at September 25, 2017

Transportation Commitments Summary

(Cusiana offloading, Monterey-El Porvenir pipeline and Santiago offloading contracts) and gas transport and purchases $11MM

Caribbean

59 52 Transportation (ToP’s/SoP’s) 3,116 Others(2) Exploratory(1) 340 288 Note 17 Financial Statements 3,515

Commitments

(As per Note 16 of Financial Statements)

376 405 423 422 218 750 482 971 913 2017(3) Total 3,116 2020 2021 Subsequent 2022 1,272 2018(4) 2019

Transportation

(Take or Pay/Ship or Pay)

CENIT (CLC) P135(4) Other ToP(3) BIC - 110K BPD

BIC system(5) at

$1.9 Billion

28

Capacity and Commitments Balanced when Bicentenario Working

2016 Reserves Revisions

171 6 6 5 9 14 36 40 38 291 La Creciente Río Ariari 2016 Production 2015 2P 2016 2P CPE-6 Guatiquía Quifa Other Revisions Lote Z1

Economic write-down due to lower oil prices Technical write-down

29

Prudently Reassessed Reserves, D&M and RPS Reviewed

30

Proven Management Team

Latin American Expertise and Strategic Know How

Barry Larson

CEO

• 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

Camilo McAllister

CFO

• 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

Camilo Valencia

VP, Operations

• 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

Renata Campagnaro

VP, Supply, Transportation & Trading

• With the Company since 2010; over 36 years experience in the oil & gas industry focused on supply
• peration, trading, and business development
• Former Managing Director of Petróleos de Venezuela Do Brasil

Erik Lyngberg

VP, Exploration

• Has over 30 years experience in the global oil & gas industry
• Former SVP, Exploration at Petrominerales; former Chief Geologist of Petrobank Energy

Duncan Nightingale

VP, Development

• Has over 30 years experience in the global oil & gas industry
• Formerly Chief Operating Office at Gran Tierra Energy

Jorge Fonseca

VP, Business Development

Peter Volk

General Counsel & Secretary

• 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
• 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

Independent Board of Directors

31

• Managing Director and Partner of The Catalyst Capital Group Inc.
• International experience restructuring public and private companies, unlocking value for

investors

Gabriel de Alba

Chairman

• 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

Luis F. Alarcon

Director

• 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

Ellis Armstrong

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.

Raymond Bromark

Director

• 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

Russell Ford

Director

• Former CEO of CENIT
• Former COO of Ecopetrol

Camilo Marulanda

Director

Engaged and Active in Generating Shareholder Value

Grayson M. Andersen Corporate Vice President, Capital Markets Calle 110, No 9 – 25, Piso 16 Bogota DC, Colombia +57 (314) 250-1467 gandersen@fronteraenergy.ca

INVESTOR RELATIONS CONTACT:

ir@fronteraenergy.ca