Northern Virgo Technical Update NORTHERN PETROLEUM PLC

23rd October 2014 Disclaimer

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October 2014 2 Project summary

. Northern Petroleum has established a 30,000 acre land position in the Virgo area of NW to undertake a field re-development project . The area is prospective for light oil from 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

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

October 14 4 Virgo area geological background

. The area is prospective for oil and gas in several formations at and Devonian Levels Fort Simpson and Muskwa Shales . Upper has been prolific for Slave Pt. oil with over 110 MMSTB produced to date in Fort Vermillion Sulphur Pt. the area of the Northern’s land position

. Up hole zones include the Sulphur and Slave Muskeg Point formations Upper — these tend to contain non-associated Keg sour gas (although oil is also present) River Lower Keg River . Oil is present in the Muskeg formation and the Muskwa Shale is prospective for oil and wet gas Chinchaga

Oil Pools Non-Associated Gas Pools Formation Pool Count Average STOIIP Formation Pool Count Average GIIP MMSTB (BCF) Jean Marie 1 2.1 Bluesky (Cret.) 1 9.9 Slave Point 3 0.1 Slave Point 171 0.9 Sulphur Point 11 0.3 Sulphur Point 128 0.6 Muskeg 64 0.9 Muskeg 2 0.3 Keg River 416 1.5 Keg River 23 0.6

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

October 14 5 Reef count

. 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

AER Reported Pool STOIIP for Keg River Reefs Completely or Partially Located 108 MMSTB of original oil in place based on on the Company's Land Position the Alberta Energy Regulator’s (AER) 60 estimate 50 43 Reefs with STOIIP > 1 MMSTB . The average recovery factor on these reefs 40 is 18% 16 Reefs with 30 STOIIP > 2 MMSTB Reef Count Reef 20

10

0 0 - 500 500 - 1,000 1,000 - 1,500 - 2,000 - 2,500 - 3,000 - 3,500 - 4,000 - 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Stock Tank Original Oil in Place (,000 STB)

October 14 6 Infrastructure

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

October 14 7 3D seismic position

WABAMUN

FORT SIMPSON

SLAVE POINT KEG RIVER . The company has purchased and interpreted over COLD LAKE 50 sq km of 3D seismic . Just under 30% of the land position is now covered

October 14 8 Keg River Formation at Virgo

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)

October 14 9 Primary gas in the Keg River Formation

. 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 Saturated Oils and Primary Under-Saturated . Lands were deliberately targeted which did Gas Caps in oils no Primary Gas not have primary gas caps the Keg River Caps in the Keg River

Depth of Burial

Increasing API Gravity

Increasing Saturation Pressure

October 14 10 Production performance in Keg River Reefs

Sweep . Displacement of oil by water within swept areas of the reef can achieve recovery factors between 45 – 65%

Virgo / Zama / Amber . To the south of Virgo, in Wells / Reef 1.5 the Rainbow area, Average Pool Area 37 acre Average pool Size 1.5 MMSTB recovery factors in the Primary Recovery Factor 16% Keg River are much Secondary Recovery Factor 29% 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

Rainbow Area un-swept pore volume? Wells / Reef 4.6 Average Pool Area 223 acre Average pool Size 9.0 MMSTB Primary Recovery Factor 32% Secondary Recovery Factor 51%

October 14 11 Production performance in Keg River Pinnacle Reefs

Geological Model . 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 Langton and Chin 1968 . 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 Water Displaces oil through the massive core Initial Well Waters out of the reef

October 14 12 Production performance in Keg River Pinnacle Reefs

Displacement (original well in reef) Water Cut v Cumulative Oil Drive Initial Perforations : 100/15-23-114-06W6M 100 . Generally, under primary production, the reefs were

90 produced with perforations near the top of the

80 structure

70 . Drive energy came, predominately, from bottom aquifer

60 drive

50 . Displacement is gravity stabilised

40 Water Cut (%) Cut Water 30

20

10

0 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 Cumulative Oil (STB)

. 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

October 14 13 Development history: horizontal wells

In 2001 100/15-23 Sidetrack (05 Event) Produces 500 STB before watering out

In 2014 102/15-23 Vertical Distance calculated for each grid block from Tests >1300 STB/D dry oil intersection of surface with constant depth plane at the reef edge

. A series of horizontal sidetrack wells were drilled in the area between 1995 – 2005 . They were singularly unsuccessful at increasing recovery factor from the Water, which has already displaced oil reefs from the core of the reef will water out the heel of the horizontal well almost . Conventional horizontal wells are advantageous to suppress coning immediately. No additional oil will be . Due to oil being trapped by vertical layering at the reef edge, horizontal captured from the heterolithic strata at wells do not increase sweep the reef edge

6th October 14 14 Phase 1B results (Oct 2014)

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

100/01-27 100/14-23 102/15-23

October 14 15 Phase 1B – 102/15-23-114-05W6

100/15-23 102/15-23

100/15-23

102/15-23

SLAVE POINT

Top Keg River KEG RIVER Demonstrated un-swept oil at the reef edge and significant oil

COLD LAKE deliverability

6th October 14 16 102/15-23 cross section with original wells

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

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

Un-swept 32m

Swept

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

October 14 17 102/15-23 wireline formation pressure results

102/15-23 MDT Pretest Results Pressure (PSIA) 2100 2150 2200 2250 2300 2350 2400 1120

1130

1140

32m 1150 swept

- 1160 Un

1170

Depth (mSS) Depth 1180 Swept 1190

Original Free Water Level 1190mSS 1200

1210

1220 . 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

October 14 18 102/15-23 flow test and performance

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

October 14 19 102/15-23 production and pressure history

102/15-23 : Flow Test : Tubing Head Pressure 6000 Flow Period 5000 Clean-Up 4000 Main Flow Period High Rate Flow Period 3000 Final Flow Period

2000

Perforation Interval Tubing Tubing Head Pressure(kPag) 1000 Depth Curve DEPTH.m 0 1499.4128 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 1499.4382 1499.4636 102/15-23 : Flow Test : Oil Rate 1499.489 3000 1499.5144 1499.5398 1499.5652 2500 1499.5906 1499.616 2000 1499.6414 1499.6668 1500 1499.6922 1499.7176

Oil RateOil (STB/D) 1000 1499.743 1499.7684 500 1499.7938 1499.8192 0 1499.8446 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 1499.87 1499.8954 Clean-up Main Flow High Rate Final Flow Build-up Period Period Period Period Period

October 14 20 102/15-23 rate comparison to other wells in Alberta

Distribution of Oil Rates (Last 12 Months) of All Flowing Oil Wells in the Province of Alberta 1

0.9

0.8

0.7

0.6

0.5

0.4

0.3 Cumulative Frequency (Fraction)

0.2

0.1

0 0 200 400 600 800 1000 1200 1400 1600 1800 Average Daily Oil Rate (STB/D)

. 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

October 14 21 Phase 1B – 100/14-23-114-05W6

14-23 100/15-23

100/15-23

SLAVE POINT

14-23

KEG RIVER

Top Keg River

Encountered poorly developed, but COLD LAKE oil saturated reservoir Completed for production

6th October 14 22 Keg River expression on the overlying Slave Point

Pre-drill Post-drill Overlying

. 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

October 14 23 Phase 1B – 100/01-27-114-05W6

08-27 01-27 08-27

01-27 SLAVE POINT

KEG RIVER

Top Keg River

COLD LAKE Encountered high quality reservoir, but swept by original producer

6th October 14 24 Well Results Phase 1A

Well and Objective Drilling Result Production Result

14-22 Successfully re-entered Well on test 02/04/2014 Re-entry Up-hole zones cemented Produced over 3000 STB oil at an 14-22 average water cut of 63% Test for migration of oil after Well swab tested and pump run extended shut-in Peak daily rate 100 STB/D and 13-33 current rate 35 STB/D oil

13-33 Drilled and encountered 15m gross oil Well on test 16/04/2014 16-19 column in the Keg River formation Infill well into previously produced Produced over 11,300 STB oil at an reef Produced dry oil on MDT test average water cut of 36% Test for un-swept oil at reef edge Ran liner across Keg River and Peak daily rate 260 STB/D and perforated current rate 50 STB/D oil Well swab tested and pump run

16-19 Drilled and encountered 22m gross oil Well on test 14/04/2014 column in the Keg River formation Exploration well into undrilled reef Produced over 8,700 STB oil Produced dry oil on MDT test Test new structure The well continues to produce dry oil Completed open hole with inflatable Peak daily rate 140 STB/D and packer above oil water contact current rate 70 STB/D oil Produced at high water cut after Inflatable packer failure Liner cemented in place and perforated. Well flowing dry oil

October 14 25 Virgo type curve and economics

Update on assumptions Cost (US$) . IP rates are higher than originally planned Drill and complete $1.82m Equip and tie in $0.55m . DCET costs should reduce with larger well programmes and lessons learnt Forecast production and reocvery IP30 (bbls/d) 150 . Variable opex will significantly reduce if water Year 1 decline 33% separation and disposal facilities are built Estimated economic reserves (bbls) 125,000

. Fixed opex will reduce through synergies of Economics (using $85 WTI flat) scale Operating net back per barrel $37 Payback (months) 10 . Metrics are robust using a life of well $85 flat IRR 63% PV10 $2.09m . Payback within a year Note: assume well tied in upon completion

October 2014 26 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

NORTHERN PETROLEUM PLC

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