Groundstar Corporate Presentation 2015

www.groundstarresources.com 1

Corporate Presentation 2015Focused Conventional Light Oil Development

in Alberta & Saskatchewan


Forward-Looking Statements

This presentation may contain “forward-looking” statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance. These statements include, among others, statements regarding our future financial position, strategy, reserves, projected costs and estimated expenditures. These statements are often, but not always, made through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “anticipate”, “believe”, “estimate”, “intend”, “plan”, “project”, “would”, and “outlook”.

These forward-looking statements are not historical facts and are subject to a number of risks and uncertainties. Certain of these risks and uncertainties are beyond Groundstar’s control. Accordingly, Groundstar’s actual results could differ materially from those suggested by these forward-looking statements for various reasons discussed throughout Groundstar’s current Annual Information Form, and particularly in the section entitled “Risk Factors”.

Analogous Information

Certain information contained herein is considered “analogous information” as defined in National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities (“NI 51-101”). Such analogous information has not been prepared in accordance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook. In particular, this press release provides information about the Viking well in which the Corporation has an interest as a result of certain analogous information concerning the results in the neighboring wells and makes certain assumptions as a result of such analogous information and potential recovery rates in the Corporation’s Viking wells as a result thereof. Such information is based on public data and information recently obtained from the public disclosure of other issuers who are active in the area and the Corporation has no way of verifying the accuracy of such information and cannot determine may be present in commercially recoverable quantities in the Corporation’s area of interest. There is no certainty that such results will be achieved by the Corporation and such information should not be construed as an estimate of future reserves or resources or future production levels.

DISCLAIMER


Several months ago Groundstar took steps to begin transitioning to a lighter oil portfolio. With the recent downward trend in oil pricing, management is now accelerating this process.

CONVENTIONAL LIGHT OIL DEVELOPMENT

The graph demonstrates historical discounts associated with WCS are further compounded by fluctuating spreads attributable to seasonal market influences. Additionally, field operations and transportation costs associated with these heavier barrels create a low netback environment.

While there is focus on non-conventional light oil opportunities, they require horizontal drilling and/or multistage fracking. The cost of these wells range from $3MM - $5MM for Mannville / Cardium depth wells to in excess of $10MM - $15MM for Duvernay / Montney drills. Productivity from these wells is highly variable with typical payouts occurring in years, not months.

How Do We Source Conventional Light Oil? What’s Old Is New Again

Very simply, the only source of significant conventional light oil reserves reside in the Devonian reef systems of Alberta and Devonian, Silurian, and Ordovician of Saskatchewan. These horizons are proven, high volume light oil producers. These vertically drilled wells require no fracking, risk capital seldom exceeds $700K, and a successful well is on production for between $1.2MM - $1.5MM. Because of initial production rates ranging from 100 BOPD - 300 BOPD, payout is achieved in months, not years.

$40.00

$50.00

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$80.00

$90.00

$100.00

$110.00

$120.00

$130.00

Jan 2010 Jul 2010 Jan 2011 Jul 2011 Jan 2012 Jul 2012 Jan 2013 Jul 2013 Jan 2014 Jul 2014

WTI WCS Brent


The evolution of 3D seismic, modern well log analysis combined with the extensive geological review processes will facilitate not only discovery of significant incremental reserves within mature producing fields but also the identification of previously overlooked exploration targets. Groundstar’s first area of focus, Morinville, is such an area.

» Recently reprocessed 12.5 square mile 3D seismic base

» Low risk opportunity to develop significant light oil reserves; conventional vertical drilling; no fracking

» Area characterized by analogous and existing reef production with existing infrastructure

» All locations are targeting light oil at depths of +\-1,600m with anticipated on production capital costs of +\-$1MM

» Three development drilling locations have been identified within a large 12.5 square mile 3D seismic data base. In the case of the first three oil locations, the reef contains proven oil, the wells will simply be drilled higher on structure to maximize reservoir quality and pay thickness

» Based upon offsetting producers, rates of 70-120 BOPD are expected with recoverable reserves per well being 75-125k barrels

» Quick to cashflow, quick to payout

» One new exploration target has been identified and is analogous to a single well pinnacle which had initial production rates in excess of 500 BOPD and has produced more than 800k BBLS to date.

MORINVILLE LEDUC REEFS: NEW-OLD PLAY


3D COVERAGE: LEDUC TIME STRUCTURE MAP

10-23 Development Leduc Reef Target


New Exploration Target

Single Well Analogy Pool » 800k BBLS to date


Morinville D3-B Pool » >12MM BOE to date


Reef Crest

Nisku

Leduc

Cambrian

Proposed 11-23

Proposed 10-23

REEF CREST SEISMIC CHARACTER


12-23 » 1.5m pay » 50k BBLS to date

Proposed 11-23 » anticipate 4-6m pay

15-23 » 3m untested pay

Proposed 10-23 » anticipated 6-8m pay

11-23 » 2.5m bypassed pay » untested

10-23 » 3m pay » 70k BBLS to date

9-23 » off-reef facies » nonproductive

Shallow Gas Producer

MORINVILLE LEDUC REEF NET PAY MAP


“Best in Canada” for oil and gas investment in the Fraser Institutes’s Global Petroleum Survey

As part of Groundstar’s commitment to light oil exploration, pursuing opportunities in Saskatchewan was obvious. Specifically:

» Growing demand for lighter barrels and market access for them

» Lower cost operating environment from land acquisition through to production

» Industry friendly, streamlined regulatory body

» Pro-business jurisdiction characterized by an attractive fiscal regime:

» Royalty rates among the lowest in Canada

» Drilling incentives for new horizontal oil wells, deep oil wells, and exploratory oil and gas wells

» The opportunity to be the early player in the next Saskatchewan wave…the conventional exploitation of the hydrocarbon proven yet underdeveloped in deeper zones below the Bakken

Existing geological data associated with the deeper production from the Devonian, Silurian and Ordovician horizons forms the basis for Groundstar’s proprietary study of deep horizon potential. The study, comprising over 300 townships, has generated numerous drilling locations and leads and provides the Company an opportunity to become the pre-eminent deep horizon player in the region.

SASKATCHEWAN

Regina

Fig.-1

RedversArea

NexenBryant

Weyburn

TablelandArea

(Winnipegosis)

(Silurian Pool)

Outlook Field(Montana)

DuperowWinnipegosis

SilurianOrdovician

Study Areaof

Potential Fairwaysin the

BaikkenDevonianSilurian

Ordovician

Study Area of the Bakken, Silurian, & Ordivician


To date, 90% (2.7 billion barrels) of Southeast Saskatchewan’s petroleum production has come from Mississippian horizons. Comparatively small volumes have been produced from the Devonian (40 million barrels) and the Silurian-Ordovician (28 million barrels).

It can be argued that technology developments such as water flooding, horizontal drilling, application of CO2 as an EOR technique and more recently, multi-stage hydraulic fracturing has delayed the development of these deeper horizons.

Groundstar is focused on these hydrocarbon proven, underdeveloped zones.

UNDERDEVELOPED POTENTIAL


» Intensive drilling of the Bakken-Torquay and Birdbear drilling for heavy oil in West Central Saskatchewan has skewed the overall Devonian production profile

» Limited Winnipegosis and Duperow drilling activity peaked shortly after discovery in 1990, however, comparative per-well average production between the Devonian and other play types highlights the significant hydrocarbon potential of Devonian reservoirs in Saskatchewan

DEVONIAN


» Silurian-Interlake oil was discovered at Nexen-Bryant in 2001 with average daily rates of close to 1,400 BOPD. Oil from this well is compositionally identical to recovery from the Mobil Redvers 14-19-8-32 W1 located in Groundstar’s area of focus

» Ordovician-Red River oil discovered at Midale in1995 resulted in significant reserves with the most prolific well at 11-26-3-21 W2 having produced more than 2.5 million barrels and currently producing more than 1,000 BOPD. There are currently fewer than 30 Ordovician producers in the province

» Similar to the Devonian, Silurian-Ordovician production peaked shortly after discovery with limited follow-up drilling activity

SILURIAN / ORDOVICIAN


Groundstar’s proprietary deep horizon study uses producing analogies from North Dakota and applies this data when looking for opportunities in the Saskatchewan portion of the basin. This study is comprised of more than 300 townships of analysis. Although referred to as “deeper horizons”, these zones are encountered at depths similar to many Central Alberta plays. From a risk mitigation standpoint, these deeper horizons are typically found as stacked reservoirs, that is, productive Devonian, Silurian and Ordovician are often found as contiguous reservoirs. This is a consequence of Precambrian basement structure playing a major role in reservoir development and trapping. A comprehensive geophysical approach is required in order to identify and understand all structural elements. While not large in areal extent, these pronounced structural closures are capable of significant production rates and reserve base.

Groundstar’s proposed Silurian-Interlake location in the Redvers area is characterized by the structural elements associated with producing stacked analogues and displays additional potential in the Bakken, Winnipegosis and Red River formations. Most significant is a recovery of free oil from a downdip location drilled in 1957 which is compositionally identical to the Nexen-Bryant Silurian discovery.

SASKATCHEWAN SILURIAN OPPORTUNITY

Fig.-2

-3600

-3600

-3500

-3700

-3700

-3700

-3700

-3700

-3400

-3800

-4000

T.8

T.9

R.33 R.32W1M

-3714

-3786

-3702

-3585

NTS.I.5716Rec. 60 GC + --SW240’OFSW, 75’SW

S.I.5883Rec. 100 OCM + 40--SW120’ SW

S.I.5682Rec. 720’ SW

14-19-8-32W1M

Redvers AreaStructural Elements

S.E. Saskatchewan

501’ 524’524’470’531’

Silu

rian

Devo

nia

nM

id.

Intlk

Elk

Po

int

Total Elk Point

Key well

2nd Red Beds

1409’ XW

60’ GC / OF / XWCM240’ OFXW

61’188’

161’

Oil

Winnipegosis

Oil

WaterAshern

Ashern90’ MC Oil100’ DCM120’ XW(6’) PayCASED toSILURIAN

540’ XW

62’67’

NT

RedversArea

“Structural” ElementsS.E. Saskatchewan

Fig.-5

Proposed Well

Proposed Well Key Well

Key Well


BAKKEN WINNIPEGOSIS SILURIAN LOCATIONProp Loc 11-31-8-32W1

Dev

Winn

PC

Evap

Red River

Datumn

Bakken anomalyProp loc 11-31

Devonian

Winnipegosis

Red River

Pre-Cambrian

Enhanced Bakken

Proposed WellKey Well


The core photo on the right side shows fracture enhanced reservoir typically associated with deep structure, and denoted on the previous seismic slide. An enhanced Bakken reservoir is anticipated overlying the proposed Silurian location providing an excellent secondary target.

BAKKEN CORE COMPARISON


7

18

12

13

D

D

D

D

T45T45R25W3R26

R25W3R26

Groundstar 4-13

Groundstar 3-13

Groundstar 5-13

NEILBURG COLONY PRODUCTION

Groundstar’s producing property at Neilburg, Saskatchewan is currently experiencing low and fluctuating WCS pricing. The company anticipates monthly net cash flow from Neilburg to generate between $20k and $30k per month in this period of low pricing.

Groundstar 6-13


31,500,000 common shares

400,000 preferred shares @ $1.00 par value Convertible to common shares @ $0.25 per share

NIL debt

$900,000 cash in hand at December 31, 2014

CAPITAL


Murray Stodalka - Chairman Compton, Exxon, Waldron

Dale Hammons, Director Independent Businessman, Hammons Group of Companies

Ty Pfeifer, B.Sc - Chief Operating Officer, Director Computalog / Precision, LNG Energy, Rider Resources / Circle Energy

DIRECTORS & MANAGEMENT


Auditors Delloite and Touche , LLP

Lawyers Dentons LLP

Transfer CST Trust Company - CUSIP 399900

Address Canada Office

Suite 2300 144 4th Avenue SW

Calgary, Alberta T2P 3N9

US Office Suite 1600

1200 Smith Street, Houston, Texas 77002

Contact Ty Pfeifer

E-mail: [email protected] Cell: 403.614.6014

Murray Stodalka E-mail: [email protected]

Cell: 403.818.0775

CORPORATE

appendix: economic summariesSproule Pricing 2015

LEDUC ECONOMIC SUMMARY IP 70 BOPDBase Case

Results as of January 01, 2015New Drill IP70&Res 70

Proved Developed Producing (Working Copy, <Current Options>)

1/16/2015 10:15 AM Economics Summary (Canada) - BEFORE TAX Page 1 of 1

Evaluation ParametersReserves Category Proved Developed ProducingPlan WorkingReference Date January 01, 2015Discount Date January 01, 2015Econ. Calc. Date January 01, 2015Country Canada

Province AlbertaCompany Share 100.00 %Price Deck Sproule Q1 2015Price Set Edmonton Light 40 APIEconomic Limit Applied - BTCF 0.00 %Scenario <Current Options>

GCA Applied NoBOE Ratio 6:1 Mcf/bblChance of Success 100.0 %Chance of Occurrence 100.0 %Oil Reserves Type Light and Medium OilGas Reserves Type N/A

(4)

(10)

0

15

30

45

60

75

0

2

4

6

8

10

2015 2020 2025

WIC

alenda

rR

ate W

ellC

oun

t

Oil (bbl/d) Gas (BOE/d) Well Count

Remaining Reserves Net Revenue NPV (M$C) PriceGross WI RI Net 0.00 % 5.00 % 8.00 % 10.00 % 15.00 % 20.00 % Average

Oil Mbbl 73.4 73.4 - 56.4 Oil 4,811.0 4,144.4 3,816.1 3,621.2 3,202.6 2,861.8 85.06Gas MMcf - - - - Gas - - - - - - -Liquids Mbbl - - - - Liquids - - - - - - -

NGL Mbbl - - - - NGL - - - - - - -Condensate Mbbl - - - - Condensate - - - - - - -C2 Mbbl - - - - C2 - - - - - - -C3 Mbbl - - - - C3 - - - - - - -C4 Mbbl - - - - C4 - - - - - - -C5+ Mbbl - - - - C5+ - - - - - - -

Sulphur MLT - - - - Sulphur - - - - - - -

Total MBOE 73.4 73.4 - 56.4 Total 4,811.0 4,144.4 3,816.1 3,621.2 3,202.6 2,861.8 85.06

Cash Flow NPV (M$C)BT Cash Flow 2,678.4 2,248.1 2,031.2 1,901.1 1,618.5 1,386.1

Risked Capital Costs (M$C) Cash Flow (M$C) Economic Indicators

Gross Co. Share Co. Share % ofSales Rev.

Before Tax

Land (COGPE) - - Revenue 6,242.1 Rate of Return (%) 137.2

Exploration (CEE) - - Royalties/Burdens 1,431.1 22.9 Payout (yrs from Aug 2015) 1.1

Development (CDE) 781.8 781.8 Operating Cost 1,013.8 16.2 Payout (date) Sep 2016

Other Capital (CCA) 277.4 277.4 Abandonment/Salvage 59.6 1.0 P/I - 0.0 % Discount 2.53

Oth. Rev./Oth. Deduct. - - P/I - 10.0 % Discount 1.91

Capital 1,059.2 17.0 Init. Value (M$C/BOE/d) -

(Credit)/Surcharge - -

Total 1,059.2 1,059.2 BT Cash Flow 2,678.4 42.9 WI Co. Share

Op. Cost ($C/BOE) 13.81 13.81

Cap. Cost ($C/BOE) 14.43 14.43

Annual Co. Share Cash Flow

YearWell

Count Rate Avg. Price WI RevenueRoyalty

Revenue Roy. / BurdenOperating

CostAbandon. /

SalvageOther

RevenueOther

DeductionsCredit /

(Surcharge)Net Op.Income

CapitalCost

BTaxCash Flow

bbl/d $C/bbl M$C M$C M$C M$C M$C M$C M$C M$C M$C M$C M$C

2015 (4) 1.00 68.3 67.35 561.0 - 123.3 66.4 - - - - 371.3 1,059.2 -687.82016 1.00 61.1 67.35 1,505.6 - 371.9 187.8 - - - - 946.0 - 946.02017 1.00 42.9 95.28 1,490.7 - 358.2 155.8 - - - - 976.7 - 976.72018 1.00 28.0 96.75 989.5 - 223.9 129.6 - - - - 636.0 - 636.02019 1.00 18.3 98.25 656.8 - 141.8 112.6 - - - - 402.4 - 402.42020 1.00 12.0 100.85 441.6 - 92.0 101.8 - - - - 247.8 - 247.82021 1.00 7.8 102.40 292.2 - 59.1 95.0 - - - - 138.0 - 138.02022 1.00 5.1 103.99 193.9 - 38.8 90.9 - - - - 64.3 - 64.32023 (10) 1.00 3.5 105.59 110.8 - 22.2 73.9 - - - - 14.7 - 14.7Rem. - - - - - - - 59.6 - - - -59.6 - -59.6

8.17 yr 85.06 6,242.1 - 1,431.1 1,013.8 59.6 - - - 3,737.6 1,059.2 2,678.4

LEDUC ECONOMIC SUMMARY IP 120 BOPDBase Case

Results as of January 01, 2015New Drill IP120 & Res 80

Proved Developed Producing (Working Copy, <Current Options>)

1/14/2015 1:00 PM Economics Summary (Canada) - BEFORE TAX Page 1 of 1

Evaluation ParametersReserves Category Proved Developed Producing

Plan Working

Reference Date January 01, 2015

Discount Date January 01, 2015

Econ. Calc. Date January 01, 2015

Country Canada

Province Alberta

Company Share 100.00 %

Price Deck Sproule Q1 2015

Price Set Edmonton Light 40 API

Economic Limit Applied - BTCF 0.00 %

Scenario <Current Options>

GCA Applied No

BOE Ratio 6:1 Mcf/bbl

Chance of Success 100.0 %

Chance of Occurrence 100.0 %

Oil Reserves Type Light and Medium Oil

Gas Reserves Type N/A

(4)

(7)

0

30

60

90

120

150

0

2

4

6

8

10

2015 2020 2025

WIC

ale

ndar

Rate W

ell

Count






Total MBOE 81.2 81.2 - 62.0 Total 5,476.4 4,813.1 4,481.3 4,282.6 3,850.4 3,492.6 88.08




Before Tax

Land (COGPE) - - Revenue 7,153.9 Rate of Return (%) 313.3


Development (CDE) 781.8 781.8 Operating Cost 1,032.1 14.4 Payout (date) Apr 2016






Op. Cost ($C/BOE) 12.71 12.71

Cap. Cost ($C/BOE) 13.04 13.04


YearWell



CostAbandon. /

Salvage Other RevenueOther

DeductionsCredit /


CapitalCost

BTaxCash Flow


2015 (4) 1.00 109.2 67.35 897.0 - 210.1 91.7 - - - - 595.3 1,059.2 -463.92016 1.00 75.9 84.36 2,342.3 - 588.0 215.4 - - - - 1,538.9 - 1,538.92017 1.00 44.2 95.28 1,537.6 - 370.6 158.3 - - - - 1,008.6 - 1,008.62018 1.00 26.5 96.75 936.3 - 210.4 126.7 - - - - 599.2 - 599.22019 1.00 16.3 98.25 584.5 - 124.8 108.7 - - - - 351.0 - 351.02020 1.00 10.2 100.85 378.1 - 77.9 98.4 - - - - 201.8 - 201.82021 1.00 6.6 102.40 245.6 - 49.2 92.5 - - - - 104.0 - 104.02022 1.00 4.3 103.99 163.2 - 32.6 89.2 - - - - 41.3 - 41.32023 (7) 1.00 3.1 105.59 69.3 - 13.9 51.2 - - - - 4.3 - 4.3Rem. - - - - - - - 59.3 - - - -59.3 - -59.3

7.92 yr 88.08 7,153.9 - 1,677.5 1,032.1 59.3 - - - 4,385.0 1,059.2 3,325.9

Base CaseResults as of January 01, 2015

New Drill IP 200 & Res 120Proved Developed Producing (Working Copy, <Current Options>)



Plan Working




Country Canada

Province Alberta






GCA Applied No






(4)

(8)

0

40

80

120

160

200

0

2

4

6

8

10

2015 2020 2025

WIC

ale

ndar

Rate W

ell

Count






Total MBOE 117.8 117.8 - 89.1 Total 7,814.7 6,875.2 6,407.9 6,128.7 5,523.0 5,022.8 87.44




Before Tax

Land (COGPE) - - Revenue 10,296.7 Rate of Return (%) > 500.0


Development (CDE) 781.8 781.8 Operating Cost 1,310.7 12.7 Payout (date) Jan 2016






Op. Cost ($C/BOE) 11.13 11.13

Cap. Cost ($C/BOE) 8.99 8.99


YearWell



CostAbandon. /


DeductionsCredit /


CapitalCost

BTaxCash Flow


2015 (4) 1.00 177.3 67.35 1,456.5 - 358.9 133.7 - - - - 963.9 1,059.2 -95.32016 1.00 113.4 84.36 3,500.0 - 895.0 285.4 - - - - 2,319.6 - 2,319.62017 1.00 60.3 95.28 2,097.2 - 519.2 188.8 - - - - 1,389.3 - 1,389.32018 1.00 34.5 96.75 1,217.6 - 283.7 142.0 - - - - 791.9 - 791.92019 1.00 20.9 98.25 748.0 - 163.6 117.6 - - - - 466.9 - 466.92020 1.00 13.2 100.85 487.5 - 102.4 104.3 - - - - 280.9 - 280.92021 1.00 8.7 102.40 324.8 - 66.2 96.7 - - - - 161.9 - 161.92022 1.00 5.9 103.99 224.3 - 44.9 92.5 - - - - 86.9 - 86.92023 1.00 4.1 105.59 159.2 - 31.8 90.2 - - - - 37.2 - 37.22024 (8) 1.00 3.1 107.22 81.4 - 16.3 59.5 - - - - 5.7 - 5.7Rem. - - - - - - - 60.3 - - - -60.3 - -60.3

9.00 yr 87.44 10,296.7 - 2,482.0 1,310.7 60.3 - - - 6,443.7 1,059.2 5,384.6

LEDUC ECONOMIC SUMMARY IP 200 BOPD

Base CaseResults as of January 01, 2015

New Drill IP 300 & Res 350Proved Developed Producing (Working Copy, <Current Options>)



Plan Working




Country Canada

Province Alberta






GCA Applied No






(4)

(3)

0

60

120

180

240

300

0

2

4

6

8

10

2015 2020 2025 2030 2035

WIC

ale

ndar

Rate W

ell

Count






Total MBOE 344.5 344.5 - 259.5 Total 24,857.4 19,172.5 16,856.4 15,606.7 13,189.8 11,447.0 95.39




Before Tax

Land (COGPE) - - Revenue 32,863.5 Rate of Return (%) > 500.0


Development (CDE) 781.8 781.8 Operating Cost 8,451.5 25.7 Payout (date) Dec 2015






Op. Cost ($C/BOE) 24.53 24.53

Cap. Cost ($C/BOE) 3.07 3.07


YearWell



CostAbandon. /


DeductionsCredit /


CapitalCost

BTaxCash Flow


2015 (4) 1.00 267.4 67.35 2,197.2 - 555.0 199.3 - - - - 1,443.0 1,059.2 383.82016 1.00 217.6 84.36 6,717.8 - 1,748.4 570.8 - - - - 4,398.6 - 4,398.62017 1.00 138.1 95.28 4,802.9 - 1,237.3 529.3 - - - - 3,036.2 - 3,036.22018 1.00 89.0 96.75 3,144.0 - 796.5 484.9 - - - - 1,862.6 - 1,862.62019 1.00 65.2 98.25 2,336.8 - 581.7 463.9 - - - - 1,291.2 - 1,291.22020 1.00 51.1 100.85 1,886.2 - 461.1 453.0 - - - - 972.1 - 972.12021 1.00 41.9 102.40 1,565.3 - 375.3 444.6 - - - - 745.4 - 745.42022 1.00 35.4 103.99 1,343.1 - 314.3 439.7 - - - - 589.1 - 589.12023 1.00 30.6 105.59 1,178.4 - 269.9 436.4 - - - - 472.0 - 472.02024 1.00 26.9 107.22 1,054.3 - 237.6 435.1 - - - - 381.6 - 381.6Rem. 1.00 17.1 115.07 6,637.4 - 1,429.0 3,994.4 69.6 - - - 1,144.5 - 1,144.5

18.58 yr 95.39 32,863.5 - 8,006.1 8,451.5 69.6 - - - 16,336.3 1,059.2 15,277.2

LEDUC ECONOMIC SUMMARY IP 300 BOPD

Groundstar Corporate Presentation 2015

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Transcript of Groundstar Corporate Presentation 2015