The New Frontera...Corporation (the “Company” or “Frontera”) believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding

The New FronteraOctober 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 EnergyCorporation (the “Company” or “Frontera”) believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates orassumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration anddevelopment plans and objectives) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based oninformation 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 todiffer 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 theywill 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, amongother things: uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; uncertainties associated with estimating oil and naturalgas reserves; failure to establish estimated resources or reserves; volatility in market prices for oil and natural gas; fluctuation in currency exchange rates; inflation; changes inequity 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 hasinvestments; 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 toupdate any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherentin the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on suchstatements due to the inherent uncertainty therein. In addition, reported production levels may not be reflective of sustainable production rates and future production rates maydiffer 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 expectedcapital 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. TheCompany and management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, however, actual results ofoperations 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 asmay 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 orotherwise. The Company discloses several financial measures in this presentation that do not have any standardized meaning prescribed under International Financial ReportingStandards ("IFRS") (including operating and consolidated Netback and operating and consolidated EBITDA). These measures should not be considered in isolation or as a substitutefor 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 EvaluationHandbook 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 reservesinformation 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 Evaluatorcompleted 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. Allreserves presented are based on forecast pricing and estimated costs effective December 31, 2016 as determined by the Company’s independent reserves evaluators. TheCompany’s net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates, including anyadditional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2016. Contingent Resources are those quantities of petroleumestimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currentlyconsidered to be commercially recoverable due to one or more contingencies. Contingent Resources have an associated chance of development (economic, regulatory, market andfacility, 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 willbe 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 ContingentResources. 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 areexpressed in United States dollars and all production volumes are expressed net of royalties, unless otherwise stated.

3

Corporate SnapshotThe 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

72.4Mboe/d

Q2’17 Production Mix

50%42%

8%Heavy Oil

2016 Net 2P Reserves(4)

170MMboe

Natural Gas

1 As at September 30, 2017 2 Gross cash balance includes restricted cash current ($34MM) and non-current ($67MM)3 As at June 30, 20174 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

Light & Medium Oil

4

Second Quarter 2017 Operational & Financial Highlights

1 Net after royalties 2 Excluded Bicentenario off-time3 Non-IFRS Measures. See Advisories.

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 EfficienciesCost 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

0

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

1 Non-IFRS measure: See Advisories

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 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.

Portfolio Enhancement: Detailed Reservoir Study

9

Leading Latin American Upstream PortfolioDiversified Portfolio of Production, Development and Exploration

75.169.4

72.5 72.470 - 75

0

20

40

60

80

3Q'16 4Q'16 1Q'17 2Q'17 Exit

GuidanceColombia Peru

Frontera Production History (Mboe/d)

10

Production & Development OptimizationQuifa: 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

one well

− Currently under technical review

11

Production & Exploration UpsideGuatiquía: 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



Base Royalty Rate (%) 8% + (PAP)


Operator Frontera



12

Significant Exploration UpsideLlanos 25: Acorazado Exploration Upside and Reserve Replacement

1 Contingent resources. See Advisories.

• 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

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 Q1 2018



Base Royalty Rate (%) 9% (8% + 1%X)

Operator Frontera

13

Production & DevelopmentCubiro: 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


Base Royalty Rate (%) 8% + (PAP)


Operator Frontera



14

Production & Exploration UpsideCPE-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

opportunity

• Environmental licence in place for

Hamaca and vicinity

• Evaluation program under way

• Declaration of commerciality due January

2018



Base Royalty Rate (%) 8.4% (6.4% + 2%X)


Operator Frontera


2017 Capital Expenditure ~$6.6MM

15

Production & Exploration UpsideBlock 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 2017Acreage (Net Acres) 1,266,037

Working Interest (%) Under Negotiation

Royalty Rate (%) Under Negotiation

Cumulative Production

(as of Dec 2016)729MMbbl

Operator Frontera


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 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 SummaryOver $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

Block Country BuyerCash

Proceeds

Exploratory

Commitments(1)

SBLC /

Collateral(2)

Santos Basin Brazil Karoon Gas 15.5 50.8 0.0

North Basins Brazil Queiroz Galvao (10.0) 25.6 42.5

Lote 131 Peru CEPSA 17.1 8.8 0.0

PUT-9 Colombia Amerisur 0.7 9.1 0.9

Mecaya Colombia Amerisur 0.6 5.2 0.8

Terecay Colombia Amerisur 0.1 8.1 0.8

Tacacho Colombia Amerisur 3.5 4.1 0.4

Casanare Este Colombia Gold Oil 2.0 12.0 0.8

SSJN-7 Colombia Canacol 0.0 7.8 2.5

Lote 126 Peru Maple Gas 0.2 13.9 2.8

Cerrito Colombia PetroSouth 0.1 0.9 0.0

PNG Blocks Papua - NG Exxon Mobil 57.0 0.0 0.0

Total 86.8 146.3 51.5

1 Includes Abandonment/Environmental Costs2 Standby Letter of Credit / Released Collateral

$ millions

17

Unlocking Value: Monetizing Hidden ValueNon-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

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.

TBDMonetization

process/progress75%

Monetization

process/progress

18

Unlocking Value: Reducing Costs, Increasing Cash FlowAddressing Highly Fixed Transportation Costs

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

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

operational cost reductions within BIC

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

or-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

$4.2Suspended

Pipeline Capacity$3.5

UPDATE

19

Balance Sheet StrengthCost Reduction Initiatives Continue

1 Assumes midpoint of 2017 Operational EBITDA Guidance of $287.5 million2 Source: Frontera’s Reported 1Q’17 versus Reported Q2’17

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

1 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

1,1361,061

Accounts payable

and accrued liabilities

537

250

Q2’17

Loans and borrowings

274

-85%

Q4’16

1,141

587

250

299315

250

862 764

5,803

6,953

Q3’16

5,815

576

-7%

343288

Q2’16

6,922

Variation

(Q2’17 vs.

Q2’16)

Variation

(Q2’17 vs.

Q1’17)

Balance Sheet Improvement Continues

21

Positive Working Capital

1 Other assets includes: income tax receivable, assets held for sale, risk management asset and prepaid expenses2 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

343

Q4’16

205

Q1’17

134

280

+22%

Q2’17Q3’16Q2’16

323

Q2’17Q1’17

474

-7%

34

439

507

37

Q3’16

450

76

61

631

556

Q2’16

389

599

470

90

Q4’16

689

30

110

13

Q2’17

154

31

Q1’17

150

+3%

111

Q4’16

9

146

29 831

197

125

Q3’16Q2’16

87

31

108

1304311

Working capital Cash and cash equivalents

229229

16 1510350

Q4’16

1033

-3%

Q2’17Q1’17

360

106

367

232

109

13

225

114

12

Q3’16

225

Q2’16

390 381

122

15182826

Inventories and others

236

63

Q4’16

5841

+21%

Q2’17

286

87

6635

98

Q1’17

47

89

64

Q3’16

170

39

70

235

64

Q2’16

2339

60

133

18

97

307

44

Accounts receivable

Current Assets (2)

Current Liabilities (2)

-

Cash and cash equivalents

Restricted cash

Trade receivable

Receivable from joint arrangements

VAT

Other receivables

Other Assets (1)

Crude oil inventory

Material Inventory

144 144167 188 154 8774 51 80 67 4748 39 50 43Days

sales

Days costs Capex,

G&A and Opex

Others contingent liabilities

Withholding tax and provisions

Payables from joint arrangements

Payroll

20

Q4’16

17

142

62

Q1’17

-13%

Q2’17

221253

83

149

259

33

Q2’16

85200

156

60140

416

Q3’16

479

191

72

217

OPEX

G&A

CAPEX

264 7 30 20

80143 151 82 87

5264 57 44 51

Days AR

trade/sales

Days OPEX AP

/OPEX

Q2’17 working capital

increased 22% mainly due to

the short term receivable

related to Exxon (Papua)

reclassified from long term

receivable

Trade Payable Others Payable

Growing Working Capital, Normalized Sales and Payment Cycle

Significant Value with Catalysts for UpsideFrontera 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)

1 Enterprise Value fully diluted market capitalization adjusted for total debt, net working capital, investment in associates, non-controlling interests and asset retirement obligations as of June 30, 2017 market close2 Reserves as at December 31, 2016

22

6.8x 6.6x6.2x

4.6x 4.6x4.1x

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 StrategyPath to Increasing Equity Demand and Liquidity

Complete

Restructuringof Frontera

Portfolio Optimization

Program

Complete

Ongoing

New Leadership

Team

Marketing Roadshow

Cost Improvement

Program

Go-Forward Strategy

InPROGRESS

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

Volumes1,440K 1,440K1,440K1,440K 1,200K 1,200K 1,200K 1,200K 1,200K 1,200K1,200k

55.63

58.0457.64

57.36 57.17 57.02 56.88 56.75 56.64 56.52 56.37

50.43

51.56

50.2849.52

49.11

49.95 50.06

50.7751.10 51.23

52.00

60.0059.60

57.14

55.1655.45 55.28 55.37

55.73 55.86 55.91

59.31

50

$48

$52

$56

$60

SEP OCT NOV DIC JAN FEB MAR APR 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

1 Exploratory minimum work commitments as of June 30, 2017 includes Queiroz $26MM and Amerisur blocks $26MM2 Others include: Operating leases and procurement $53MM and communities $6MM3 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

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

171665914

36

40

38291

La

Creciente

Río

Ariari

2016

Production

2015 2P 2016 2PCPE-6GuatiquíaQuifaOther

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 TeamLatin American Expertise and Strategic Know HowBarry LarsonCEO

• 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 McAllisterCFO

• 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 CampagnaroVP, Supply, Transportation &

Trading

• 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

• Has over 30 years experience in the global oil & gas industry

• Former SVP, Exploration at Petrominerales; former Chief Geologist of Petrobank Energy

Duncan NightingaleVP, Development

• Has over 30 years experience in the global oil & gas industry

• Formerly Chief Operating Office at Gran Tierra Energy

Jorge FonsecaVP, 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 AlbaChairman

• 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 BromarkDirector

• 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 MarulandaDirector

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

[email protected]

INVESTOR RELATIONS CONTACT:

[email protected]

Documents

The New Frontera...Corporation (the “Company” or “Frontera”) believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding