Corporate Presentation December 2013 TSX-V: YGR Statements in this - - PowerPoint PPT Presentation

Corporate Presentation TSX-V: YGR December 2013

Statements in this presentation may contain forward-looking information including expectations of future production and components of cash flow and earnings. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward looking statements or information include, among other things: general economic and business conditions; the risk of instability affecting the jurisdictions in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew

• production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew

leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates; risks inherent in the Company’s marketing operations, including credit risk; health, safety and environmental risks; and uncertainties as to the availability and cost of financing. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. The reader is cautioned not to place undue reliance on this forward-looking information. The forward looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or

• therwise unless required by applicable securities laws. The forward looking statements or information contained in this

presentation are expressly qualified by this cautionary statement.

Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas. Reserve Definitions: (a) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. (c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves

• n production.

(d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date

• f resumption of production must be known with reasonable certainty.

(e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. (f) "Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. (g) The Net Present Value (NPV) is based on AJM Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the AJM evaluations will be attained, and variances could be material.

Proven operational track record, on a per share basis

• Production per share growth of 146% since 2010
• Reserve per share growth of 62% since 2010

Focus on improving economics and accelerating capital

• CAPEX / well down 41% since 2011 drilling program
• Cardium wells now offer 10-14 month paybacks with IRRs of over 100%
• Cardium wells now offer 10-14 month paybacks with IRRs of over 100%

Focus on balance sheet strength

• Forecasted Q4 debt to cash flow of 1.0 : 1
• Forecasted Net Debt of $36 million at year-end ($65 million in ATB credit facilities)

Running Room Established

• Recently executed 29 net section / 37 net location Cardium farm-in to bring total

inventory in the Glauc and Cardium to 104 net locations Yangarra has reached a corporate transition point having established operational excellence and financial flexibility coupled with significant running room in their core area

Publicly listed junior oil and gas company TSX-V: YGR Shares Outstanding Basic Options/Warrants (weighted average $0.54) 147 million 12 million Fully Diluted 159 million Insider Ownership Basic Fully Diluted 20% Fully Diluted 20% 25% Market Capitalization (at $0.54/share) $86 million Forecast year-end Net Debt ($65 million in ATB credit facilities) $36 million Enterprise Value $122 million Forecast Q4 Net Debt to annualized Cash Flow 1.0 : 1 Proved plus Probable Reserves (Dec 31, 2012) 12.5 million boe Net Present Value @ 10% (P+P) (not including land) $167 million

Third Quarter 2013 Production 2,238 boe /d Liquid Content 46% Sales Price $ 43.95 /boe Royalty income 0.95 / boe Royalty expense (3.42) /boe Royalty expense (3.42) /boe Production costs (5.45) / boe Transportation costs (1.47) / boe Operating netback $ 34.56 / boe G&A and other (excludes non-cash items) (1.76) / boe Finance expenses (2.32) / boe Cash flow netback $ 30.49 / boe

Jim Evaskevich, President & CEO

• 30+ years extensive executive experience with strong
• perations background

Michael d’Entremont, COO

• 30+ years experience with reservoir development,

horizontal drilling and multi-stage fracture technology

• Livingston Energy, Cdn. Hunter, Amoco Canada Petroleum

James Glessing, CA, CFO

• 15 years oil and gas accounting experience

Randall Faminow, VP, Land

• 30+ years of experience in all aspects of oil and gas land work,

including negotiation, acquisitions and divestments, contracts and mergers

Lorne Simpson B.Sc., C.E.T., VP, Operations

• 30+ years experience in the industry
• Supervisor, Drilling Ops with PetroBakken Energy Ltd.
• Engineered, drilled or completed 250 HZ Cardium wells, 200 HZ

Bakken wells, 2 HZ Duvernay wells, 25 HZ Montney wells, and dozens of Blue Sky, Viking, SWS, Glauc, and Rock Creek HZ wells

Management Team

• 15 years oil and gas accounting experience
• Executive and financial experience as CFO with North

Peace Energy Corp

• Controller at BlackRock Ventures,
• Canadian Natural Resources, Shell and Deloitte

Board of Directors

W.W. (Chuck) Charlton

• President of Charlton Capital Corp

Jim Evaskevich

• President and CEO of Yangarra Resources Ltd

Gordon Bowerman

• Chairman
• President of Cove Resources Ltd
• Founder of several successful private and public oil

and gas companies

Robert Weir

• President of Weir Resource Management Ltd

Alan T. Pettie Q.C.

• Senior Partner at BD&P

6,000 8,000 10,000 12,000 14,000 1,000 1,500 2,000 2,500 (boe/d) (mboe)

• 2,000

4,000 500 2010 2011 2012 Production Reserves

Production per share growth 2010 3% 2011 55% 2012 52% Reserves per share growth 2010 0% 2011 13% 2012 38%

• 1,807

498 473 373

• 4000

5000 6000 Equip 41% reduction in average drilling costs since 2011 Drilling Represents 70%

• f Corporate Costs

Staff count is down and performance is up 2,088 2,832 2,134 1,563 1,792 1,376 1,134 273

• 1000

2000 3000 2010 2011 2012 2013 Equip Complete Drill Staff Count

• !
• "

90% 50% 60% 70% 80% 90% 100% IRR

• 24%

41% 67% 90% 0% 10% 20% 30% 40% 50% 2010 2011 2012 2013 IR Based on actual costs, production to date and P+P reserves Based on actual costs and type curves

47 gross (29 net) sections in the Willesden Green area that

• ffset existing Yangarra land holdings

61 gross (37 net) Cardium locations indentified Pay 100% to earn 75%, earn one section per earning well 7 net earning wells over a two year period

7 net earning wells over a two year period

Rolling option until December 2016 Drilling will be completed on a two well pad basis, with the first

well on the pad being the earning well and the second well drilled on a working interest basis.

• Drilling costs significantly reduced by drilling on a 2 well-pad basis

No infrastructure issues expected as the lands are either

adjacent to existing Yangarra facilities or farmor facilities

Existing Yangarra Land Farm-in Land

• Geology and expected type

curves consistent with existing Cardium landholdings

• Cost savings from drilling
• Cost savings from drilling

all wells on a 2 well per PAD basis essentially negates the promote

CAPEX budget for 2014 $50.0 million Budget focused on Cardium Wells

• Split between Farm-in locations and pre-existing locations
• Includes one Duvernay vertical test well

Funded with cash flow and the existing credit facilities 2014 Guidance

• 2014 Guidance

Production (boe/d) Annual Average 3,200 boe/d Cash flow from operations $40 million Annual debt to cash flow 1.2 : 1 Pricing Assumptions (annual average) Crude oil – Edmonton Par $85.00/bbl Natural Gas $3.00/GJ

Central Alberta

• Interest in 140 sections of land
• 63 total wells drilled since 2010 (58

Horizontal wells)

• Horizontal wells)
• Focus
• Cardium and Glauc plays
• Light oil
• High netback
• Quick payouts

Cardium Colorado Group 650m thick Second White Specks Viking

• Vertical production

exists in all zones

• Viking

Glauconitic Ellerslie Rock Creek

• All zones meet the

criteria for horizontal drilling

• 2013 capital budget

will focus on the Cardium & Glauconite

• Duvernay

Inventory Type Gross Locations Net Locations Net Booked in 2012 reserve report Cardium Light Oil (includes farm-in) 105 78 16 Glauconite Liquids Rich 40 26 13

• Total

145 104 29

• Yangarra has drilled 58 horizontal wells into our development resource

plays

• 8+ years of drilling inventory in Cardium and Glauconite
• Significant un-booked upside
• Additional locations in the SWS and Rock Creek included in the reserve

report but not in the Company’s immediate development plans

• Drilled or participated in 27 gross (13.6 net) HZ

Cardium wells (21 operated)

• Reservoir is characterized by 60-85% oil and

liquid weighting

• Currently being developed with four wells per

section

• Yangarra owns a 15 % override on 11 sections
• Yangarra owns a 15 % override on 11 sections
• Map indicates extent of prospective lower

permeability Cardium Halo (> 6% porosity) but not fully developed

Yangarra Land

• Development of our Glauconite

lands commenced in March 2010 with the drilling of our first horizontal (“HZ”) well

• Drilled or participated in 22 gross

HZ (13.3 net) wells to date into Hoadley Glauconite Barrier Island Complex: HZ (13.3 net) wells to date into the formation (12 operated)

• Accumulated 45 gross (24.0 net)

sections

• Reservoir is characterized by 50–

75 bbls/mmcf of NGL’s, with an average of 65 bbls/mmcf

• Currently being developed with

three wells per section

• Yangarra owns a 15% override on

11 sections

Yangarra Land # YGR owned 15% Override Land

• Significant amounts of
• il have been produced
• ver the past 30 years

from vertical wells

• 10 to 20 million barrels
• f Original Oil in Place

(OOIP) per section

• Yangarra Land
• Accumulated 45 gross

(35 net) sections

• Yangarra has 3

horizontal wells and 2 vertical wells in the SWS formation

• Yangarra owns 60 Gross (60 net)

sections of Duvernay land

• Three vertical strat test wells

before October 2015 will continue all 60 sections until October 2020

• Estimated to contain 80-100 bcf

Original Gas in Place (“OGIP”) per

• Yangarra Land

Original Gas in Place (“OGIP”) per section with liquid content estimated to be greater than 100 bbls/mmcf

• Current industry development

program envisions 6-8 locations per section with recoveries of 20% to 30% of the OGIP

• The play is currently being de-

risked by industry drilling

Oil Hedges 2013: 900 bbl/d hedged at $100.37/bbl 2014: 1,200 bbl/d hedged at $95.02/bbl 2015: 900 bbl/d hedged at $90.59/bbl Natural Gas Hedges

• * Assumes Yangarra specific heat value

Natural Gas Hedges 2013: 4,500 GJ/d hedged at 3.46/GJ or 4.18/mcf* 2014: 3,000 GJ/d hedged at 3.23/GJ or 3.90/mcf* Interest Rate Swaps 4.70% Fixed rate on $10 million (June 2014-June 2018) 4.85% Fixed rate on $10 million (June 2014-June 2018)

5.00 10.00 15.00 20.00 25.00 30.00 35.00

Q3 2013 Operating costs/boe

2.00 4.00 6.00 8.00 10.00

Q3 2013 G&A/boe

• 0.00

5.00

YGR

0.00

YGR

• Management team with strong operations background
• Maintain low operating costs through operational presence and control over

infrastructure

• Central Alberta land base is an established oil and gas operating area
• Focused on cash flow per share

Tables based on internal analysis of 20 peer companies

1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

Q3 2013 Debt to Cash Flow

0.20 0.40 0.60 0.80 1.00 1.20 1.40

Q3 2013 Debt/Equity

• 0.00

1.00 2.00

YGR

0.00 0.20

YGR

• Focus on reducing costs and maximizing profit
• Lower natural gas prices, higher WTI to Edmonton par spreads and lower NGL

prices have negatively affected the debt to cash flow ratio

• Risk management program protects against a drop in oil prices

Tables based on internal analysis of 20 peer companies

Maximize netbacks in the current price environment by

focusing on oil targets

Maintain top-tier drilling and completion costs Maintain low operating costs through operational

presence and cost efficiencies

• presence and cost efficiencies

Continue to grow drilling inventory through drilling,

geology and strategic acquisitions

Execution on low capital / high impact strategy to

unlock the significant upside in the Second White Specks and Duvernay plays

8,000 10,000 12,000 14,000

P+P Reserves (mboe)

Oil NGL's

80 100 120 140 160 180

Reserve Value PV10 ($ millions)

Oil NGL's

• 2,000

4,000 6,000 2010 2011 2012

NGL's Natural gas

20 40 60 80 2010 2011 2012

NGL's Natural gas

179% increase in reserves since 2010 Replaced 2012 production by 546% (958% in 2011) Finding and development recycle ratio of 2.05 times on P+P reserves Finding and development costs of $12.45/boe on proved plus probable reserves including changes in future capital ($4.44/boe excluding changes in future capital)

2013 (900 bbl/d hedged)

• 200 bbl/d @ $98.00 WTI/CAD for 2013
• 100 bbl/d @ $97.50 WTI/CAD for 2013
• 200 bbl/d @ $98.30 WTI/USD for 2013
• 100 bbl/d @ $98.00 WTI/USD for 2013
• 100 bbl/d @ $104.80 WTI/CAD for 2013
• 200 bbl/d @ $105.20 WTI/CAD Aug – Dec 2013
• Sold Calls on 200 bbl/d @ $110 US/bbl for 2013

2014 (1,200 bbl/d hedged)

• 100 bbl/d @ $98.30 WTI/CAD for 2014
• 100 bbl/d @ $100.00 WTI/CAD for 2014

2013 Natural Gas (4,500 GJ/d hedged)

• 2,000 GJ/d at $3.51/GJ for Jan – Dec 2013
• 1,000 GJ/d at $3.35/GJ for Jan – Dec 2013
• 500 GJ/d at $3.42/GJ for Jan – Dec 2013
• 500 GJ/d at $3.42/GJ for Apr – Dec 2013
• 500 GJ/d at $3.60/GJ for May – Dec 2013

2014 Natural Gas (3,000 GJ/d hedged)

• 1,000 GJ/d at $3.11/GJ for Jan – Dec 2014
• 1,000 GJ/d at $3.05/GJ for Jan – Dec 2014
• 1,000 GJ/d at $3.54/GJ for Jan – Dec 2014
• 100 bbl/d @ $100.00 WTI/CAD for 2014
• 100 bbl/d @ $91.40 WTI/CAD for 2014
• 100 bbl/d @ $91.35 WTI/CAD for 2014
• 200 bbl/d @ $92.00 WTI/USD for 2014
• 100 bbl/d @ $90.00 WTI/USD for 2014
• 200 bbl/d @ $93.52 WTI/CAD for 2014
• 100 bbl/d @ $98.20 WTI/CAD for 2014
• 200 bbl/d @ $98.20 WTI/CAD for Jan – Jun 2014
• Sold Swaption on 200 bbl/d @ $100.00 WTI/USD for 2014
• Sold Swaption on 200 bbl/d @ $100.00 WTI/USD for Jul – Dec 2014

2015 (900 bbl/d hedged)

• 100 bbl/d @ $86.05 WTI/USD for 2015
• 100 bbl/d @ $91.20 WTI/CAD for 2015
• 200 bbl/d @ $90.37 WTI/CAD for 2015
• 200 bbl/d @ $90.10 WTI/CAD for 2015
• 100 bbl/d @ $92.25 WTI/CAD for 2015
• 200 bbl/d @ $92.45 WTI/CAD for 2015
• 1,000 GJ/d at $3.54/GJ for Jan – Dec 2014

Interest Rate Swaps

• 4.70% Fixed rate on $10 million (June 2014-June 2018)
• 4.85% Fixed rate on $10 million (June 2014-June 2018)

$%& $'' (' $$) *+ ,-% .( /-% ,- 01 (2 $( 12 322 (,4 )-

150% 175% 200% 225% X + Divs )/ CashFlow

>$500 EV Liquids >$500 EV Gas <$500 EV Liquids <$500 EV Gas

Cash Flow Sustainability Ratio (2013) vs. Debt / Cash Flow

#

$% $, ,2 +2, 2(& $* *2 $ 2% ( (2 ,2 ($ 3,' ((' (0$ /%) ,-5 $2) ,2, *$ 6( '2 + *% (* *+ $() .( *+/ 026 // 26 ,+2 22 )' $' /(

• 6

42 , /,2 $*2 /(' )%( 6/* 3*

50% 75% 100% 125% 150% 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x Cash Flow Sustainability ((CAPEX + D Debt / Cash Flow

* Ignores DRIP * Based on analyst estimates of cash flow, dividends and capex for 2013 * 2012 YE net debt / 2013E cash flow

Source: AltaCorp Capital Inc.

• Yangarra is highly leveraged to the Duvernay play in terms of acres to

Enterprise Value

Texas Water Demand Irrigation 55.9% Municipal 26.9% Manufacturing 9.6% Steam Electric 4.1% Livestock 1.8%

• Livestock

1.8% Mining (including oil and gas) 1.6% “The amount of water required to drill all 2916 of the Marcellus wells permitted in Pennsylvania in the first 11 months of 2010 would equal the amount of drinking water used by just one city, Pittsburgh, during the same period.” Source: Carnegie Mellon University Study

YGR PEY BNP BXE WCP DTX TVE YO TOU RMP NVS NGL

Production 2,238 56,343 73,580 21,852 21,448 7,573 3,162 2,384 74,096 6,639 4,637 10,255 Gas Weighting 54% 89% 63% 72% 31% 20% 41% 69% 89% 49% 12% 42% Netback $34.56 $21.13 $21.55 $20.37 $50.58 $46.63 $45.84 $19.51 $18.80 $32.48 $44.50 $29.22 Op Costs $6.92 $3.03 $10.29 $9.91 $11.54 $12.78 $13.08 $12.66 $6.44 $9.47 $11.71 $7.48 Net Royalty $2.46 $1.90 $4.96 $4.08 $9.27 $19.50 $7.41 $3.98 $2.64 $13.98 $7.42 $11.04 G&A Costs $1.76 $0.14 $1.14 $2.29 $1.62 $2.20 $3.43 $3.03 $0.69 $2.72 $4.05 $3.22 G&A Costs $1.76 $0.14 $1.14 $2.29 $1.62 $2.20 $3.43 $3.03 $0.69 $2.72 $4.05 $3.22 Cash Flow 6.4 99.7 120.1 30.0 83.4 29.4 10.3 3.4 120.5 17.8 15.8 17.6 Debt 43 863 1,069 218 429 131 57 31 691 93 83 242 Debt/CF 1.7 2.2 2.2 2.2 1.3 1.1 1.4 2.3 1.4 1.3 1.3 3.4 Market Cap 66 4,687 2,691 794 2,101 699 111 131 7,980 646 220 286 EV 108 5,550 3,760 1,012 2,527 830 168 162 8,672 739 302 528 EV/boe 48,407 98,509 51,106 46,324 117,845 109,693 53,294 68,100 117,039 111,395 65,274 51,567 MC/NPV10 (less debt) 53% 173% 88% 64% 259% 344% 99% 88% 218% 235% 75% 62% Current Share Price $0.54 $31.51 $13.61 $7.25 $12.61 $9.12 $3.75 $2.60 $42.10 $5.90 $1.16 $3.54 NPV10 (Less Debt) / Share $1.03 $18.26 $15.46 $8.11 $5.86 $3.15 $3.79 $3.67 $19.28 $2.51 $1.55 $5.72

Yangarra Resources Ltd. 1530, 715 – 5 Ave. SW Calgary, Alberta T2P 2X6 403-262-9558