NORTHERN PETROLEUM PLC

23rd October 2014

Northern Petroleum Virgo Technical Update

Disclaimer

October 2014 2

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Project summary

Northern Petroleum has established a 30,000 acre land position in the Virgo area of NW Alberta to undertake a field re-development project

The area is prospective for light oil from Devonian Keg River vuggy carbonate reefs

— approximately 1,500m depth

The recovery factor in the Virgo reefs is lower than analogue Keg River reefs to the south in the Rainbow area

Production to date has been through bottom aquifer drive

There has been lower recovery at Virgo from poor sweep efficiency at the reef edge due to reduced vertical permeability within hetrolithic strata

Trapped oil at the reef edge is an attractive development target and well results prove its existence

— additionally, vuggy carbonate reefs remain prolific, even at the reef edge

— well placed development locations have demonstrated high oil productivity

Recent well results have highlighted the importance of seismic interpretation to locate wells in a ‘sweet spot’ between the core and edge of the reefs

October 14 3

The Virgo area

October 14 4

Virgo is located in a remote Boreal forested wilderness setting, 500 miles north west of Edmonton, Alberta

Northern land position (five year petroleum and natural gas lease)

10 miles

Virgo area geological background

October 14 5

The area is prospective for oil and gas in several formations at Cretaceous and Devonian Levels

Upper Keg River formation has been prolific for oil with over 110 MMSTB produced to date in the area of the Northern’s land position

Up hole zones include the Sulphur and Slave Point formations

— these tend to contain non-associated sour gas (although oil is also present)

Oil is present in the Muskeg formation and the Muskwa Shale is prospective for oil and wet gas

Formation Pool Count Average STOIIP MMSTB

Jean Marie 1 2.1

Slave Point 3 0.1

Sulphur Point 11 0.3

Muskeg 64 0.9

Keg River 416 1.5

Chinchaga

Lower Keg River

Upper Keg

River

Muskeg

Sulphur Pt.

Slave Pt.

Fort Simpson and Muskwa Shales

Fort Vermillion

Formation Pool Count Average GIIP (BCF)

Bluesky (Cret.) 1 9.9

Slave Point 171 0.9

Sulphur Point 128 0.6

Muskeg 2 0.3

Keg River 23 0.6

Oil Pools Non-Associated Gas Pools

Pool count in the 576 square mile region around company lands Does not include co-mingled pools nor associated/solution gas volumes

Reef count

October 14 6

The Company participated in eight Crown land sales in 2013 and 2014

Acquired just under 30,000 acres for a total of Cdn2.9 million

The Company has obtained mineral rights covering 118 full or partial Keg River reefs

It is estimated that these reefs did contain 108 MMSTB of original oil in place based on the Alberta Energy Regulator’s (AER) estimate

The average recovery factor on these reefs is 18%

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Re

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Stock Tank Original Oil in Place (,000 STB)

AER Reported Pool STOIIP for Keg River Reefs Completely or Partially Located on the Company's Land Position

43 Reefs with STOIIP > 1 MMSTB

16 Reefs with STOIIP > 2 MMSTB

Infrastructure

October 14 7

Roads Emulsion Gathering Gas Gathering & Export

The area benefits from extensive infrastructure which was constructed between 1968 and the present day

Good road infrastructure and proximal tie-in locations significantly reduce the cost of entry

3D seismic position

October 14 8

The company has purchased and interpreted over 50 sq km of 3D seismic

Just under 30% of the land position is now covered

SLAVE POINT

WABAMUN

FORT SIMPSON

KEG RIVER

COLD LAKE

Keg River Formation at Virgo

October 14 9

Average KR Reef properties

Porosity 8%

Water Saturation 15%

Net Pay 35m

Radius 250m

Kh (air) 100mD

Oil Gravity 32-40 API

Reservoir Temperature 75 C

Original Solution Gas Oil Ratio200-450 scf/STB

Initial Pressure 150 Bara

(2200 PSIA)

Primary gas in the Keg River Formation

October 14 10

The Keg River formation deepens to the West and is sourced from later basinal Keg River equivalent strata

The increased maturity of the source rock leads to higher API gravity oils and additional gas generation

Oil API gravity increases to the west (from 32 to 40 API), the saturation pressure increases and primary gas caps begin to develop

Lands were deliberately targeted which did not have primary gas caps

Saturated Oils and Primary Gas Caps in the Keg River

Under-Saturated oils no Primary Gas Caps in the Keg River

Depth of Burial

Increasing API Gravity

Increasing Saturation Pressure

Production performance in Keg River Reefs

October 14 11

Sweep Displacement of oil by

water within swept areas of the reef can achieve recovery factors between 45 – 65%

To the south of Virgo, in the Rainbow area, recovery factors in the Keg River are much higher and demonstrate little un-swept pore volume

This is due to many more wells / reef and larger reef size

Why is the recovery factor at Virgo half as high and where is the un-swept pore volume?

Rainbow Area

Wells / Reef 4.6

Average Pool Area 223 acre

Average pool Size 9.0 MMSTB

Primary Recovery Factor 32%

Secondary Recovery Factor 51%

Virgo / Zama / Amber

Wells / Reef 1.5

Average Pool Area 37 acre

Average pool Size 1.5 MMSTB

Primary Recovery Factor 16%

Secondary Recovery Factor 29%

Production performance in Keg River Pinnacle Reefs

October 14 12

Water Displaces oil through the massive core of the reef

Langton and Chin 1968

Initial Well Waters out

The core of the reef tends to be homogenous and vertically continuous

— whereas, the reef edge tends to be heterolithic and have vertical barriers to flow.

These vertical barriers at the reef edge can trap oil resulting in low recovery factors where well penetration counts are low

When the reef is produced, aquifer support from the base sweeps oil from the core of the reef towards the production well until the well waters out

After an extended shut-in, some oil migrates from the reef edge back to the core of the reef and some oil remains trapped at the reef edge

This is not coning, it is low areal sweep efficiency

Geological Model

Production performance in Keg River Pinnacle Reefs

October 14 13

Primary production performance from original wells tends to show extended low water cut production followed by sharp water breakthrough

— consistent with piston like displacement of oil by water

The live oil viscosity varies from below 1 to 3 cP

— good mobility ratio for the displacement of oil by water

— again consistent with piston like displacement

This suggests that coning is not occurring to a material degree and that un-swept pore volume results from geological factors rather than fluid dynamics

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Cumulative Oil (STB)

Water Cut v Cumulative OilInitial Perforations : 100/15-23-114-06W6M

Drive Displacement (original well in reef)

Generally, under primary production, the reefs were produced with perforations near the top of the structure

Drive energy came, predominately, from bottom aquifer drive

Displacement is gravity stabilised

Development history: horizontal wells

6th October 14 14

Distance calculated for each grid block from intersection of surface with constant depth plane

In 2001

100/15-23 Sidetrack (05 Event)

Produces 500 STB before watering out

A series of horizontal sidetrack wells were drilled in the area between 1995 – 2005

They were singularly unsuccessful at increasing recovery factor from the reefs

Conventional horizontal wells are advantageous to suppress coning

Due to oil being trapped by vertical layering at the reef edge, horizontal wells do not increase sweep

In 2014

102/15-23 Vertical

Tests >1300 STB/D dry oil

at the reef edge

Water, which has already displaced oil from the core of the reef will water out the heel of the horizontal well almost immediately. No additional oil will be captured from the heterolithic strata at the reef edge

Phase 1B results (Oct 2014)

October 14 15

Well and Objective Drilling Result Production Result

102/15-23 14m net oil pay Well flowed at over 1,300 STB/D on test. Waiting on delivery of separator package.

100/14-23 4m net oil pay Well swabbed 20 STB/D and pump run. Waiting on delivery of separator package.

100/01-27 0m net oil pay MDT showed Keg River to be swept

102/15-23 100/14-23

100/01-27

Phase 1B – 102/15-23-114-05W6

6th October 14 16

102/15-23

SLAVE POINT

102/15-23

100/15-23

KEG RIVER

COLD LAKE

Top Keg River

100/15-23

Demonstrated un-swept oil at the reef edge and significant oil deliverability

Original Well

New Well

102/15-23 cross section with original wells

October 14 17

Original Free Water Level 1190mSS

Keg River reef was clearly oil saturated at 102/15-23 with a total of 14m of net pay interpreted based on the wireline logs

Un-swept oil has been encountered in a heterolithic sequence at least 32m below the top of the Keg River perforated in the original producer, 350m away

This well clearly indicates that significant un-swept oil is present at the reef edge

Un-swept

Swept

32m

Original Well (100/15-23) New Well (102/15-23)

New well encounters oil down dip from the top of the perforation in the original well

102/15-23 wireline formation pressure results

October 14 18

MDT pressure show good overpressure, consistent with a significant gross hydrocarbon column and demonstrating the reef to be at original pressure

This suggests that the perforated interval may not be in hydrostatic equilibrium with the swept interval

Original Free Water Level 1190mSS

Un

-sw

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Swep

t

32m

1120

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1190

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pth

(m

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Pressure (PSIA)

102/15-23 MDT Pretest Results

102/15-23 flow test and performance

October 14 19

Flow Period Start End Hours Oil Rate Water Rate Gas Rate Water Cut GOR Cumulative Oil Cumulative Water Cumulative Gas

(h) (STB/D) (BBL/D) (MSCF/D) (fraction) (scf/STB) (STB) (BBL) (MSCF)

Clean-Up 07/10/2014 13:00 07/10/2014 15:45 2.75 675 65 44 0.09 65 77 59 44

Main Flow Period 07/10/2014 15:45 09/10/2014 08:00 40.25 304 1 136 0.00 448 588 64 180

High Rate Flow Period 09/10/2014 08:00 09/10/2014 20:00 12.00 1313 0 237 0.00 180 1,245 64 417

Final Flow Period 09/10/2014 20:00 10/10/2014 13:00 17.00 181 0 69 0.00 381 1,373 64 486

The well cleaned up quickly and showed excellent deliverability with a productivity index of approximately 2.9 STB/D/Psi

The flow test was conducted over exactly 72 hours and was divided into the flow periods shown above

The average rate during the 12 hour high rate flow period was 1,313 STB/D against a ½” choke with 300 to 400 psi tubing head pressure

Perforated Interval 1499.4 – 1508.8mMD

Net Perforated Pay 9.2m

PHIE 0.074

102/15-23 production and pressure history

October 14 20

Flow Period

Clean-Up

Main Flow Period

High Rate Flow Period

Final Flow Period

Perforation Interval

Depth Curve

DEPTH.m

1499.4128

1499.4382

1499.4636

1499.489

1499.5144

1499.5398

1499.5652

1499.5906

1499.616

1499.6414

1499.6668

1499.6922

1499.7176

1499.743

1499.7684

1499.7938

1499.8192

1499.8446

1499.87

1499.8954

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07/10/2014 07:12 07/10/2014 19:12 08/10/2014 07:12 08/10/2014 19:12 09/10/2014 07:12 09/10/2014 19:12 10/10/2014 07:12 10/10/2014 19:12 11/10/2014 07:12

Tub

ing

He

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ress

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(kP

ag)

102/15-23 : Flow Test : Tubing Head Pressure

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07/10/2014 07:12 07/10/2014 19:12 08/10/2014 07:12 08/10/2014 19:12 09/10/2014 07:12 09/10/2014 19:12 10/10/2014 07:12 10/10/2014 19:12 11/10/2014 07:12

Oil

Rat

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102/15-23 : Flow Test : Oil Rate

Clean-up Period

Main Flow Period

High Rate Period

Build-up Period

Final Flow Period

102/15-23 rate comparison to other wells in Alberta

October 14 21

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Average Daily Oil Rate (STB/D)

Distribution of Oil Rates (Last 12 Months) of All Flowing Oil Wells in the Province of Alberta

Production from 102/15-23 expected to be between 300 – 400 stb/d after tie-in

‒ Positions the well in the top 2% of flowing oil wells in Alberta in terms of production rate

Only 12% of wells in the province flow to surface with the rest requiring artificial lift

Phase 1B – 100/14-23-114-05W6

6th October 14 22

14-23

SLAVE POINT

14-23

100/15-23

KEG RIVER

COLD LAKE

Top Keg River

100/15-23

Encountered poorly developed, but oil saturated reservoir Completed for production

Keg River expression on the overlying Slave Point

October 14 23

Pre-drill Post-drill Overlying Slave Point formation

A thorough review of the 14-23 result has highlighted the importance of the muted expression of the Keg River structure on the overlying Slave Point surface

This will improve our ability to discriminate between subtle Keg River tops and Muskeg on-lap on the reefs

Phase 1B – 100/01-27-114-05W6

6th October 14 24

08-27

SLAVE POINT 01-27

08-27

KEG RIVER

COLD LAKE

Top Keg River

01-27

Encountered high quality reservoir, but swept by original producer

14-22

16-19

13-33

Well Results Phase 1A

October 14 25

Well and Objective Drilling Result Production Result

14-22

Re-entry

Test for migration of oil after extended shut-in

Successfully re-entered

Up-hole zones cemented

Well swab tested and pump run

Well on test 02/04/2014

Produced over 3000 STB oil at an average water cut of 63%

Peak daily rate 100 STB/D and current rate 35 STB/D oil

13-33

Infill well into previously produced reef

Test for un-swept oil at reef edge

Drilled and encountered 15m gross oil column in the Keg River formation

Produced dry oil on MDT test

Ran liner across Keg River and perforated

Well swab tested and pump run

Well on test 16/04/2014

Produced over 11,300 STB oil at an average water cut of 36%

Peak daily rate 260 STB/D and current rate 50 STB/D oil

16-19

Exploration well into undrilled reef

Test new structure

Drilled and encountered 22m gross oil column in the Keg River formation

Produced dry oil on MDT test

Completed open hole with inflatable packer above oil water contact

Produced at high water cut after Inflatable packer failure

Liner cemented in place and perforated. Well flowing dry oil

Well on test 14/04/2014

Produced over 8,700 STB oil

The well continues to produce dry oil

Peak daily rate 140 STB/D and current rate 70 STB/D oil

Cost (US$)

Drill and complete $1.82m

Equip and tie in $0.55m

Forecast production and reocvery

IP30 (bbls/d) 150

Year 1 decline 33%

Estimated economic reserves (bbls) 125,000

Economics (using $85 WTI flat)

Operating net back per barrel $37

Payback (months) 10

IRR 63%

PV10 $2.09m

Virgo type curve and economics

Update on assumptions

IP rates are higher than originally planned

DCET costs should reduce with larger well programmes and lessons learnt

Variable opex will significantly reduce if water separation and disposal facilities are built

Fixed opex will reduce through synergies of scale

Metrics are robust using a life of well $85 flat

Payback within a year

October 2014 26

Note: assume well tied in upon completion

Potential from existing land position

Virgo notional development plan

AER STOIIP and recovery factors suggest that there are at least 12 reefs with the capacity for a minimum of three additional wells

• minimum well recovery at 125 MSTB

• at least 17 reefs which with capacity for a single producer

Estimated that existing land position can support 64 wells

• providing for 8,000,000 incremental oil recovery

Sufficient for the Virgo asset to grow, organically, to 3,000 – 5,000 STB/D.

Key points for successful development

New wells will increase recovery factors by targeting unswept areas of reefs

Well locations will be optimised with increased understanding of edge reef environment

Well evaluation and completion improved through application of formation tester data acquisition and interpretation

October 14 27

NORTHERN PETROLEUM PLC

Northern Petroleum

Northern Petroleum