www.KeltExploration.com

Corporate Presentation

David J. Wilson, President & Chief Executive Officer Sadiq H. Lalani, Vice President, Finance & Chief Financial Officer

September 2015

1

Advisory Regarding Forward-Looking Statements

Certain information with respect to Kelt Exploration Ltd. (“Kelt” or the “Company”) contained herein, including expectations, beliefs,

plans, goals, objectives, assumptions, information and statements about future events, conditions, results of operations, performance,

financial position, average daily production and land holdings, Kelt’s planned capital expenditure program and the nature of the

expenditures, drilling plans, expected drilling and completion costs, expected average production, the expected splits among crude

oil, NGLs and gas and forecasted commodity prices and factors affecting natural gas prices, forecasted general and administrative

expenses, interest expenses, revenue, operating income, operating netbacks, funds from operations and year-end bank debt,

management’s assessment of future potential, including numerous years of drilling inventory and expectations with respect to natural

gas supply in the Unites States of America, contain forward-looking statements. These forward-looking statements are based on

assumptions and are subject to numerous risks and uncertainties, certain of which are beyond the Company’s control, including the

impact of general economic conditions, industry conditions, volatility of commodity prices, currency exchange rate fluctuations,

imprecision of reserve estimates, environmental risks, competition from other explorers, stock market volatility, ability to access

sufficient capital and receipt of necessary regulatory and shareholder approvals. We caution that the foregoing list of risks and

uncertainties is not exhaustive.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied

assessment, based on current estimates and assumptions that the reserves and resources can be profitably produced in the future.

Readers are cautioned that disclosure of any well test results are not necessarily indicative of long-term performance.

Kelt’s actual results, performance or achievement could differ materially from those expressed or implied by, these forward-looking

statements and, accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire

or occur. As a result, undue reliance should not be placed on forward-looking statements.

In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The forward-looking

statements contained herein are made as of the date hereof and the Company does not intend, and does not assume any obligation, to

update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly

required by applicable securities laws.

Certain information set out herein may be considered as “financial outlook” within the meaning of applicable securities laws. The

purpose of this financial outlook is to provide readers with disclosure regarding Kelt’s reasonable expectations as to the anticipated

results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not be

appropriate for other purposes.

2

For investors who want to be exposed to a growth oriented oil and gas

exploration and development business plan

– TRACK RECORD: the Kelt management team has a strong track

record of building shareholder value, previously with Celtic

Exploration Ltd.

– OPPORTUNITY DRIVEN: Kelt maintains financial flexibility during

periods of opportunistic market conditions, providing the Company

with the ability to act on new opportunities quickly and effectively.

– OBJECTIVE: Kelt aims to deliver profitable future growth targeting

an inception to date production per share CAGR of 20% to 25%;

generating an inception to date recycle ratio of 2.0 times or better

based on proved plus probable reserves; and at the same time,

continuing to add future drilling locations to its inventory.

Why Invest in Kelt?

3

• Stock Exchange listing TSX

• Trading symbol KEL

• Market capitalization ( @ Sep / 10 / 2015 ) $ 1.0 billion

• 52-week trading range $ 4.91 - $ 13.37

• Common shares issued 168.6 million

• Restricted share units ( RSUs ) 1.3 million ( 0.8% )

• Stock options 5.1 million ( 3.0% )

→ average exercise price = $ 8.36 / share

• Total diluted common shares 175.0 million

• Directors & Officers ownership 17% ( 18% diluted )

Common Share Information

4

Capital Expenditures

( $ millions ) 2014

Actual

2015

Forecast Change

Inception to

Dec/31/2015

Drilling & Completions 188.6 99.8 - 47% 372.7 [ 30% ]

Facilities, Equipment &

Pipeline Infrastructure 46.1 44.0 - 5% 109.6 [ 9% ]

Land, Seismic & Asset

Acquisitions [1] 21.6 36.0 + 67% 283.0 [ 23% ]

Sub-total 256.3 179.8 - 30% 765.3 [ 62% ]

Corporate Acquisitions 167.6 [2] 313.2 [3] + 87% 480.8 [ 38% ]

Total Capital Expenditures 423.9 493.0 + 16% 1,246.1 [ 100% ]

Notes:

[1] Asset acquisitions are net of property dispositions.

[2] Acquisition of Capio Exploration Ltd. ( private company ).

[3] Acquisition of Artek Exploration Ltd. ( public company ).

5

2015 Drilling Program

Gross

Wells

Net

Wells

D&C

( MM ) %

Avg / Well

( MM )

Grande Prairie [1] 9 7.6 $ 46 43% $ 6.1

Karr [2] 1 1.0 $ 7 7% $ 7.0

Inga / Fireweed /

Stoddart [3] 5 5.0 $ 32 36% $ 6.4

Grande Cache [4] 1 1.0 $ 6 6% $ 6.0

Other - - $ 9 8%

Total 16 14.6 $ 100 100%

Notes:

[1] Grande Prairie (Pouce Coupe / Spirit River / Valhalla): Montney / Doig / Charlie Lake / Halfway formations. [2] Karr: Montney formation. [3] Inga / Fireweed / Stoddart: Montney / Doig / Baldonnel formations. [4] Grande Cache: Cretaceous formations.

6

Production Outlook

2015

Forecast

(average)

Split

Change

from

2014

Q4 2015

Forecast

(average)

Split

Oil ( bbls/d ) 5,350 28% + 57% 6,200 28%

NGLs ( bbls/d ) 1,650 9% + 79% 2,000 9%

Gas ( mcf/d ) 72,000 63% + 43% 81,600 63%

Combined ( BOE/d ) 19,000 + 49% 21,800

Per Million Shares

( BOE/d ) 123 + 17% 129

7

813

4,337

7,000 8,200

3,148

8,419

12,000

13,600

3,961

12,756

19,000

21,800

0

4,000

8,000

12,000

16,000

20,000

24,000

2013 2014 2015 [E]Forecast

Q4-15 [E]Forecast

Production Growth ( since inception )

Oil / NGLs Gas

11

36 45 49

42

69

78 81

53

105

123 129

0

40

80

120

160

2013 2014 2015 [E]Forecast

Q4-15 [E]Forecast

PRODUCTION PER MM SHARES ( BOE / d ) PRODUCTION ( BOE / d )

CAGR since 2013 = 119%

CAGR since 2013 = 52%

8

Commodity Prices

( CA $, unless otherwise specified ) 2014 2015 (E) Change Q4 2015 (E)

WTI Crude Oil ( USD/bbl ) US $ 92.99 US $ 52.50 - 44% US $ 56.00

WTI Crude Oil ( CAD/bbl ) $ 102.49 $ 66.82 - 35% $ 73.36

NYMEX Natural Gas ( USD/mmBtu ) US $ 4.37 US $ 2.95 - 32% US $ 3.35

AECO 5A Natural Gas ( CAD/GJ ) $ 4.27 $ 2.75 - 36% $ 3.20

Exchange Rate ( CAD/USD ) [1] $ 1.105 $ 1.273 + 15% $ 1.310

Kelt realized Oil price ( $/bbl )

Percent of WTI CAD

$ 85.91

84%

$ 55.97

84%

- 35%

$ 61.94

84%

Kelt realized NGLs price ( $/bbl )

Percent of WTI CAD

$ 59.47

58%

$ 27.66

41%

- 53%

$ 33.37

45%

Kelt realized Gas price ( $/mcf ) $ 4.75 $ 3.08 - 35% $ 3.66

Kelt realized Combined price ( $/BOE ) $ 46.11 $ 29.83 - 35% $ 34.38

Notes:

[1] Actual average WTI crude oil price for Jan-Aug 2015 was US $51.66/bbl.

[2] Actual average NYMEX natural gas price for Jan-Aug 2015 was US $2.81/mmBtu.

9

Gas Marketing / Transportation Contracts

Firm Service ( mmBtu / d ) NIT

AECO

Spectra

Station 2

Alliance

Chicago TOTAL

ALBERTA

Current to Nov/30/15

Dec/1/15 to Oct/31/16

38,000

38,000

-

-

-

8,100

38,000

46,100 [See Note 1]

BRITISH COLUMBIA

Current to Nov/30/15

Dec/1/15 to Oct/31/16

6,100

-

5,500

5,500

-

17,200

11,600

22,700

Notes:

[1] In addition to the firm service contracts shown above, effective October 1, 2015, Kelt has secured approximately 10,000 mmBtu/d of third party firm service on TCPL (priced at AECO).

[2] Kelt also has interruptible service on TCPL (AECO pricing), Alliance (CREC pricing), Spectra (Station 2 pricing) and Alliance priority interruptible (Chicago pricing).

[3] Kelt expects to have weak realized natural gas prices in British Columbia during Q3 2015 due to low index pricing at Spectra Station 2. AECO (5A) was $2.71/GJ in Jul/15 and $2.80/GJ in Aug/15. Spectra Station 2 daily index pricing was $2.20/GJ in Jul/15 and $1.53/GJ in Aug/15.

[4] Due to low/negative Alliance CREC prices to date in Q3 2015, Kelt has kept newly drilled gas wells shut-in and has not delivered to its spot interruptible Alliance CREC contracts.

10

Protecting Cash Flow through Hedging

( CA $ unless otherwise specified ) Period Quantity Fixed Price

CAD / USD Exchange Rate [1] Mar/1/15 to

Dec/31/15

US $3.0 MM

per month

CA $ 1.258 or

US $0.795

Interest Rate Swap [2] Jul/2/15 to

Jun/30/17 CA $100 MM 0.925%

OPIS Conway Propane [3] Mar/1/15 to

Dec/31/15

250

bbls/d

US $ 40.95

per bbl

NYMEX HH – AECO Basis Aug/1/15 to

Dec/31/15

30,000

MMBtu/d US $ 0.625

Notes:

[1] Kelt has sold forward US$30.0 million for the March to December 2015 period, at an exchange rate of $ 1.258 (or US$0.795), representing approximately 31% of the Company’s budgeted oil revenue currency exposure for the same period.

[2] The interest rate swap fixes the B/A rate at 0.925% for two years. Using current stamping fees of 3.0%, this provides the Company with an all-in fixed borrowing rate of 3.925% on $100.0 million of bank debt.

[3] The propane hedge was un-wound by Kelt in Q1 2015 for a realized gain of US$1.5 million (CA$1.8 million).

11

Netbacks

( $ / BOE ) 2014 2015 (E) Change

Oil & gas revenue 46.11 29.83 - 35%

Realized hedging gain ( loss ) ( 0.08 ) 0.24

Royalties ( % of revenue ) ( 13.3% ) ( 10.4% ) - 22%

Transportation expense ( 2.30 ) ( 2.72 ) + 18%

Production expense ( 12.00 ) ( 12.57 ) + 5%

Operating netback [1] 25.62 11.68 - 54%

G&A expense ( 0.78 ) ( 0.84 )

Interest expense ( 0.18 ) ( 0.90 )

Other income ( costs ) 0.15 0.15

Funds from operations [1] 24.81 10.09 - 59%

Note:

[1] See “Financial Advisories”

12

In each of its core areas, Kelt has embarked on projects that are expected to

reduce corporate operating and transportation expenses:

KARR: Pembina Pipeline Corporation announced the construction of a 30,000 bbl/d Karr

Lateral pipeline and LACT Unit as part of its Phase III pipeline expansion. Upon completion

in early-2016, Kelt will have all of its oil pipeline connected, eliminating trucking

requirements. Water injection was implemented in Q2-15.

POUCE COUPE/PROGRESS: Kelt is installing a LACT Unit at its 6-19 Progress battery and at

the same time will run a liner through an existing pipeline to connect its Pouce Coupe oil

and condensate to the Progress LACT Unit, eliminating oil trucking and third party terminal

fees. In addition, several water injectors have been activated eliminating water trucking fees.

VAHALLA/LA GLACE: a LACT Unit has been installed and water injection has been activated,

eliminating higher costs to truck oil and fluids.

BRITISH COLUMBIA: Kelt is currently converting an existing pipeline acquired in the

Stoddart acquisition into an oil sales line that will deliver clean oil from Inga/Fireweed to a

Company owned Pembina Terminal. A water injector was activated in Q2-15.

Note: The Lease Automatic Custody Transfer or LACT Unit is the critical system in measuring the volume of crude oil and petroleum

products when it is being transferred from the production site to trucks, pipelines or storage tanks.

Facility Spending to result in Cost Savings

13

Financial Outlook

2014 2015

Forecast Change

Q4-15 (F) Annualized

Revenue, before royalties ( $ MM ) 214.3 208.5 - 3% 272.5

Funds from operations ( $ MM ) [1] 115.5 70.0 - 39% 115.0

Per share – diluted ( $/share ) 0.93 0.45 - 52% 0.67

Capital expenditures ( $ MM ) [2] 423.9 493.0 + 16%

Debt, net of working capital,

at year-end ( $ MM ) 104.4 193.0 + 85% 193.0

Debt / Annualized Q4 2015 funds

from operations ratio [3] 1.7 x

Notes:

[1] See “Financial Advisories”

[2] Capital expenditures are net of dispositions, if any.

[3] Debt/Annualized Q4 2015 funds from operations ratio is calculated using estimated bank debt, net of working capital, at December 31, 2015 divided by estimated funds flow from operations based on estimated fourth quarter production annualized at estimated commodity prices.

14

Commodity Price Sensitivities – Funds from Operations

WTI Oil →

NYMEX Gas /

AECO Gas ↓

US $ 45.00

US $ 56.00

US $ 67.00

US $ 78.00

US $ 1.95 /

CA $ 1.45 42 62 79 93

US $ 2.65 /

CA $ 2.32 70 90 105 119

US $ 3.35 /

CA $ 3.20 97 115 130 143

US $ 4.05 /

CA $ 4.06 122 140 155 167

Note: Sensitivities to WTI are based on increments of US $11.00 / bbl, representing 20% of the forecasted US $56.00 / bbl price. Sensitivities to NYMEX HH are based on increments of CA $0.70 / mmBtu, representing 20% of the forecasted US $3.35 / mmBtu price. The USD / CAD exchange rate is forecasted as follows: at WTI US $45.00 / bbl, the exchange rate is US $0.741 (or CA $1.350); at WTI US $56.00 / bbl, the exchange rate is US $0.763 (or CA $1.310); at WTI US $67.00 / bbl, the exchange rate is US $0.787 (or CA $1.270); at WTI US $78.00 / bbl, the exchange rate is US $0.813 (or CA $1.230).

Forecasted Annualized Q4-2015 Funds from Operations

- Sensitivities to Varying Commodity Prices ( $ millions )

15

Core Areas

Grande Prairie ( includes Pouce Coupe, Spirit River & Valhalla/LaGlace ) :

→ Montney/Doig gas development → Montney light oil development → Charlie Lake light oil development → Halfway light oil development

Karr:

→ Montney light oil exploration/ development

Grande Cache / Chicken:

→ Cretaceous gas development → Cretaceous oil/gas exploration

Inga / Fireweed / Stoddart ( B.C. ) :

→ Montney/Doig condensate rich gas exploration/development

→ Baldonnel oil exploration/development

Grande Cache / Chicken

Karr

Grande Prairie

Inga / Fireweed

/ Stoddart

16

Land Holdings

Gross Acres Net Acres Average WI Net Sections

Developed 386,919 205,556 53% 321

Undeveloped 632,022 507,721 80% 793

Total 1,023,941 713,277 70% 1,114

Note:

Growth in net land holdings since March 31, 2013:

Date Net Acres Net Sections % Growth since Mar/31/2013

Mar/31/2013 107,997 169

Dec/31/2013 297,355 465 175%

Dec/31/2014 461,188 721 327%

Current 713,277 1,114 560%

17

Recycle Ratio ( since inception )

Recycle Ratio ( since inception )

Proved Proved + Probable

Capital expenditures plus future

development capital expenditures ( $MM ) 1,277.8 1,400.3

Reserve additions, net ( MMBOE ) 67.2 105.2

Finding, Development & Acquisition

( “FD&A” ) cost ( $/BOE ) 19.02 13.31

Average corporate operating netback

( $/BOE ) 23.56 23.56

Recycle ratio 1.2 x 1.8 x

As at December 31, 2014

18

Alberta Land Base

Operations

Kelt’s main field operating base is in the city of Grande Prairie, currently staffed with 20 full-time employees. All operated properties are within a 75-mile radius of Grande Prairie and are easily accessible from Kelt’s field office.

Alberta Land Holdings

Gross: 772,748 acres ( 1,207 sections ) Net: 500,745 acres ( 782 sections )

Forecast 2015 Average Production

Oil/NGLs: 4,900 bbls/d ( 37% ) Gas: 50.5 mmcf/d ( 63% ) Combined: 13,300 BOE/d

Grande Prairie

Pouce Coupe

Spirit River

Grande Cache

Karr

Chicken

Valhalla / La Glace

Progress

Gordondale

19

Grande Prairie

LAND

Gross: 308,908 acres ( 483 sections )

Net: 195,017 acres ( 305 sections )

PRODUCTION

2014 Production: 6,459 BOE/d ( 60% gas & 40% oil )

Top five IP30 wells ( gross sales, BOE/d ): (1) Pouce Coupe 14-25-077-13W6 Montney ( 95% gas ) 1,401 (2) Progress 04-16-077-09W6 Halfway ( 83% oil ) 1,187 (3) La Glace 13-33-074-08W6 Montney ( 88% oil ) 1,089 (4) Pouce Coupe 13-08-078-11W6 Montney ( 83% oil ) 1,047 (5) Pouce Coupe 14-08-078-11W6 Montney ( 82% oil ) 975

Note:

% oil above includes crude oil and natural gas liquids.

Kelt Lands

Pouce Coupe

Spirit River

Valhalla / La Glace

Progress

Gordondale

20

Pouce Coupe

Targeting Montney (upper and middle/lower) and Doig formations.

Ownership in pipeline infrastructure, gas compression and a 20% interest in the CNRL Progress 140 MMcf/d Gas Plant.

Montney drilling to date has been successful for both oil and gas.

Progress Halfway

“O” Pool Unit 7.8% WI

Pouce Coupe South Boundary

“B” Unit #2 67.9% WI Operated

14-9

Pouce Coupe South Boundary “A” Unit

32.0% WI

Progress Gas Plant (20% WI)

Kelt Pouce Coupe Compressor

Facility (100% WI)

13-8

Kelt Lands Unit Outline

13-32 UM+LM 14-25

LM

16-17 UM

12-8

8-18 7-18

21

Progress / Spirit River

PROGRESS:

• Targeting Montney and Halfway formations.

SPIRIT RIVER:

• Targeting the Charlie Lake formation.

• Various vertical up-hole re-completion candidates in the E&M Unit.

Progress Halfway

Gas Unit #1 15.9% WI

Spirit River Charlie Lake E & M Unit 81.6% WI Operated

13-33

15-5

13-34

15-13 (50%)

Kelt Lands Unit Outline

2-12 (25%) Halfway

16-11 H2O

Disposal

22

Valhalla / La Glace

Targeting the Montney formation.

Ownership in pipeline infrastructure, oil battery and gas compression.

Ownership interest (0.3%) in the Encana Sexsmith 200 MMcf/d Gas Plant.

Kelt Lands

1-19

13-33

15-33

Sexsmith Gas Plant (0.3% WI)

Kelt Valhalla/La Glace

3,500 bopd + + 20 MMcf/d

Facility (100% WI)

23

Karr

LAND Montney Rights:

37.0 sections ( gross )

35.8 sections ( net )

OPERATIONS

2014 Production: 1,353 BOE/d ( 56% oil & 44% gas )

Top four IP30 wells ( gross sales, BOE/d ): (1) Karr 102/15-28-065-03W6 ( 78% oil ) 1,360 (2) Karr 100/16-28-065-03W6 ( 57% oil ) 1,022 (3) Karr 100/16-08-066-03W6 ( 49% oil ) 495 (4) Karr 100/14-21-065-03W6 ( 66% oil ) 452

Note:

% oil above includes crude oil and natural gas liquids.

Kelt Lands

4-16

16-10 (75%) “ MM ”

13-27 OS 2015

2-21 OS 2015

1-17 H2O

Disposal

13-31 2016 drill

4-17 OS 2015

16-31 “ MM ”

2015 drill

16-8 (75%)

4-2 OS 2015

12-26

15-28 16-28

14-21

MM – Middle Montney

H2O – water

OS – on-stream

24

British Columbia Land Base

Operations

Kelt’s secondary field office is based in the town of Fort St. John.

Core operated properties at Fireweed, Inga and Stoddart are in close proximity to Fort St. John.

B.C. Land Holdings

Gross: 251,193 acres ( 392 sections ) Net: 212,532 acres ( 332 sections )

Forecast 2015 Average Production

Oil/NGLs: 2,100 bbls/d ( 37% ) Gas: 21.5 mmcf/d ( 63% ) Combined: 5,700 BOE/d

Kelt Lands

Fort St. John

Fireweed

Inga

Stoddart

25

British Columbia – DOIG Lands

Kelt Lands

Fireweed 16 MMcf/d Compressor/

Facility (100% WI)

Inga 28 MMcf/d Compressor/

Facility (100% WI)

CNRL West Stoddart

120 MMcf/d Gas Plant

Stoddart 10 MMcf/d + 2,500 bopd

Facility (100% WI)

LAND

Doig Rights:

Gross: 175 sections Net: 168 sections

OPERATIONS

● Recent Doig wells completed using slick-water fractures have shown very encouraging results. In about eight months, raw production from the Inga 10-21 Doig well was approximately 297,000 BOE (43% field condensate).

Top five IP30 wells ( gross sales, BOE/d ): (1) Inga 100/10-21-087-23W6 ( 26% gas ) * 1,980 (2) Inga 100/10-02-088-23W6 ( 41% gas ) 1,800 (3) Inga 100/08-11-088-23W6 ( 43% gas ) 1,624 (4) Fireweed 200/A-085-I/094-A-12 ( 74% gas ) 1,550 (5) Inga 100/11-15-088-23W6 ( 57% gas ) 1,549

* Slick-water completion

Fireweed

Inga

Stoddart 3-33 Doig

Slick-water Completion

10-21 Doig Slick-water Completion

26

0

500

1,000

1,500

2,000

2,500

1 2 3 4 5 6 7 8Month

10-21-87-23W6

3-33-87-23W6

BC Wells: DOIG Slick Water Completions

( BOE / d )

0

100

200

300

400

500

600

700

1 2 3 4 5 6 7 8Month

10-21-87-23W6

3-33-87-23W6

( BBLs / MMCF )

10-21 Cumulative Raw Gas: 1,023 MMcf Condensate: 127 Mbbls

3-33 Cumulative Raw Gas: 630 MMcf Condensate: 96 Mbbls

PRODUCTION

CONDENSATE TO GAS RATIO

27

British Columbia – MONTNEY Lands

Kelt Lands

CNRL West Stoddart

120 MMcf/d Gas Plant

LAND

Montney Rights:

Gross: 163 sections Net: 162 sections

OPERATIONS

● recent Montney wells completed using slick-water fractures have shown very encouraging results with high IP30 rates comprised 57% to 69% condensate

● Montney wells qualify for BC royalty incentives of approximately $900,000 per well

● Drilling to date has been in the upper- Montney

● The upper-Montney reservoir is up to 40 metres thick and porosities are up to 9%

C-26-A Montney (Sfc: A-6-A)

Gross IP30 = 1,147 BOE/d

of which 696 bbls/d (60%) was condensate

C-85-I Montney (Sfc: A-65-I) Gross IP30 = 903 BOE/d of which

512 bbls/d (57%) was condensate

8-31 Montney

(Sfc: B7-29) Gross IP30 = 1,245 BOE/d

of which 857 bbls/d (69%) was

condensate

Fireweed

Inga Stoddart

28

0

200

400

600

800

1,000

1,200

1,400

1 2 3 4 5 6 7 8 9 10Month

8-31-87-23W6

C-26-A/94-A-13

C-85-I/94-A-12

BC Wells: MONTNEY Slick Water Completions

( BOE / d )

0

50

100

150

200

250

300

350

1 2 3 4 5 6 7 8 9 10Month

8-31-87-23W6

C-85-I/94-A-12

C-26-A/94-A-13

( BBLs / MMCF )

PRODUCTION

CONDENSATE TO GAS RATIO

8-31 Cumulative Raw Gas: 245 MMcf Condensate: 55 Mbbls

C-26-A Cumulative Raw Gas: 478 MMcf Condensate: 51 Mbbls

C-85-I Cumulative Raw Gas: 280 MMcf Condensate: 46 Mbbls

29

British Columbia – BALDONNEL Lands

LAND

Baldonnel Rights:

Gross: 149 sections Net: 138 sections

OPERATIONS

● Oil exploration activity with plans to drill initial well in 2016.

● Competitor activity offsetting Kelt lands has been successful in the Baldonnel formation.

Kelt Lands

30

Future Considerations

– DRILLING INVENTORY: Kelt estimates that it has numerous years of drilling inventory on its existing lands to continue to grow the Company.

– BALANCE SHEET: Kelt maintains financial flexibility so that it can persevere during periods of declining commodity prices and pursue new opportunities as they arise.

– CRUDE OIL PRICES: the number of rigs drilling for crude oil in the U.S. declined to 652 in early September 2015, after peaking at about 1,600 in November 2014. With low current oil prices, we believe that global oil supply will eventually be negatively affected as a result of significant reductions in capital investment. We believe this will lead to higher crude oil prices in 2016.

– NATURAL GAS PRICES: the number of rigs drilling for natural gas in the U.S. declined to 196 in early September 2015, after peaking at about 1,600 in September 2008. Despite record high gas supply in the U.S. primarily due to higher productive shale wells, we expect U.S. supply will be negatively affected as declines on new production sets in. In addition, with a declining crude oil rig count in the U.S., associated gas production will also be negatively affected. We believe these factors bode well for natural gas prices in 2016.

31

Management

David J. Wilson, President & CEO

Sadiq H. Lalani, Vice President, Finance & CFO

Douglas J. Errico, Vice President, Land

Alan G. Franks, Vice President, Production

Douglas O. MacArthur, Vice President, Operations

Patrick Miles, Vice President, Exploration

William C. Guinan, Corporate Secretary

32

Board of Directors

Robert J. Dales Compensation (Chair), Nominating, Audit, Reserves

William C. Guinan Chairman, Nominating (Chair), HSE

Eldon A. McIntyre Reserves (Chair), Nominating, Audit, Compensation

Neil G. Sinclair Audit (Chair), Compensation, HSE, Reserves

David J. Wilson HSE (Chair)

33

Oil and Gas Advisories

Barrel of oil equivalent (“BOE”) amounts may be misleading, particularly if used in isolation. A BOE conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel. This conversion ratio of six thousand cubic feet of natural gas to one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

In addition, if applicable, sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel.

References to oil in this presentation include crude oil and field condensate. References to natural gas liquids (“NGLs”) include pentane, butane, propane and ethane. References to gas in this discussion include natural gas and sulphur.

In this presentation, reference may be made to OOIP or OGIP, meaning original oil in place and original gas in place, respectively, which are hereinafter collectively will be called “discovered petroleum initially-in-place”. Discovered petroleum initially-in-place is the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum-in-place includes production, reserves and contingent resources; the remainder is unrecoverable.

References to IP30 means initial production from a well for the first 720 hours (30 days) based on operating/producing hours. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate hydrocarbon recovery.

Estimates of the net present value of the future net revenue from Kelt’s reserves do not represent the fair market value of the Company’s reserves. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation.

Where discussed herein "NPV" represents the net present value of cash flow (after capital expenditures) discounted at the percentage indicated, with cash flow reflecting the indicated oil, liquids and natural gas prices, less internal estimates of operating costs and royalties.

34

Financial Advisories

All dollar amounts are referenced in Canadian dollars, except when noted otherwise. This presentation contains the terms “funds from operations”, “operating income”, “operating netback”, “production per million shares”, “finding, development and acquisition cost” and “recycle ratio” which do not have a standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other companies.

Funds from operations, operating income and operating netbacks are used by Kelt as key measures of performance. Funds from operations, operating income and operating netbacks are not intended to represent corporate profits nor should they be viewed as an alternative to cash provided by operating activities, profit or other measures of financial performance calculated in accordance with GAAP.

Operating income is determined by deducting royalties, production expenses and transportation expenses from oil and gas revenue, after realized financial instruments and cash premiums. Operating netbacks are calculated by dividing operating income by aggregate production.

Funds from operations are determined by adding back change in non-cash operating working capital to cash provided by operating activities. The Company calculates funds from operations per share using the same method and shares outstanding which are used in the determination of profit per share.

Finding, development and acquisition (“FD&A”) cost is the sum of capital expenditures incurred in the period and the change in future development capital (“FDC”) required to develop reserves. FD&A cost per BOE is determined by dividing current period net reserve additions into the corresponding period’s FD&A cost. Readers are cautioned that the aggregate of capital expenditures incurred in the year, comprised of exploration and development costs and acquisition costs, and the change in estimated FDC generally will not reflect total FD&A costs related to reserves additions in the year.

Recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment by comparing the operating netback per BOE to FD&A cost per BOE.

www.KeltExploration.com

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September 2015