1. Art and Diseño

SUSTAINABLE GROWTH
February 2015
Forward-Looking Statements
This presentation contains forward-looking statements concerning the Corporation. More particularly, it contains forward-looking statements concerning: (i) the prevailing
commodity prices at which the Corporation’s compliance with the debt to EBITA covenants in its credit facilities would be approached; (ii) expected 2015 capital expenditures
and average and exit rates of production; (iii) the internal rates of return and drilling economics for wells drilled at the Corporation’s key properties; (iv) the potential for asset
sales or other asset monetization transactions and the impact of such on the Corporation; (v) the number of drilling locations at the Corporation’s key properties and in total;
(vi) the potential exploration, development and recovery opportunities associated with the Corporation's properties; and (vii) the potential impact of waterflood implementation
on reserves, recovery factors, finding and development costs, declines and cash flow.
The forward-looking statements are based on certain key expectations and assumptions made by the Corporation.
With respect to the forward-looking statements
concerning the prevailing commodity prices at which the Corporation’s compliance with the debt to EBITA covenants in its credit facilities would be approached, these include
expectations and assumptions concerning expected revenues, expenses and other factors that would have a bearing on the calculation of the debt to EBITA ratio for any
applicable period. All of the forward-looking statements are also based on expectations and assumptions concerning prevailing commodity prices, exchange rates and
interest rates, the success and timing of future drilling, development and waterflood activities, the performance of existing wells, the performance of new wells, the availability
and performance of facilities and pipelines, the geological characteristics of the Corporation's properties, the successful application of drilling, completion and seismic
technology, prevailing weather conditions, prevailing royalty regimes, the application of regulatory and licensing requirements, the availability and cost of capital, labour and
services and, with respect to estimates of the impact of waterfloods, the assumptions specifically set out herein.
Although the Corporation believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be
placed on the forward-looking statements because the Corporation can give no assurance that they will prove to be correct. Since forward-looking statements address future
events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a
number of factors and risks. These include, but are not limited to, risks associated with commodity price, interest rate and exchange rate fluctuations, uncertainty as to the
cost and availability of labour, services and capital, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and
production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, the uncertainty of well performance,
and health, safety and environmental risks), uncertainty as to weather conditions, and uncertainties resulting from potential delays or changes in plans with respect to
exploration, development or waterflood projects or capital expenditures or changes to existing laws and regulations. These and other risks are set out in more detail in the
Corporation's Annual Information Form for the year ended December 31, 2013 dated March 25, 2014, which has been filed on SEDAR and can be accessed at
www.sedar.com.
The forward-looking statements contained in presentation are made as of the date hereof and the Corporation undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
2
What Differentiates Legacy
3
Historical Performance
Proved +Plus Probable Reserve Growth
400
Funds Flow per Share
P+P Reserves
350
0.70
80
0.56
60
0.42
40
0.28
0.40
20
0.14
0.00
0
1.20
150
0.80
100
50
0
2011
2012
2013
2014F
0.00
2009
2010
2011
2012
2013
Production Growth
25,000
150
Production
Production per Million Shares
20,000
120
15,000
90
10,000
60
5,000
30
0
Production (BOED/Million Shares)
2010
P+P Reserves (MMBOE)
200
Funds Flow ($/Share)
1.60
Production (BOED)
Funds Flow ($Millions)
300
250
P+P Reserves per Share
100
2.00
2009
0.84
120
2.40
Funds Flow
0
2009
2010
2011
2012
2013
2014F
4
P + P Reserves (Reserves/Share)
Funds Flow Growth
Corporate Profile (TSX: LEG)
Common Shares
Options & Restricted Shares
Insider Ownership (Fully Diluted)
199.7 million
8.0 million
5.4%
Enterprise Value
Average Liquidity (TSX)
Net Debt (estimated at December 31, 2014)
Total Borrowing Capacity
~$1.15 billion
3.8 million shares/day
$175 million
$850 million
available at
$1,025 million
year end
Production Weighting
81% light oil (39o API)
8% NGL and heavy
11% natural gas
~575,000 net acres
Undeveloped Land
89%
5
Bank Line and Term Debt
Term Debt
US$ 200 million, 7.5% coupon
Unsecured and covenant light – basically pay the interest
matures in November 2017
Bank Line
$800 million – approximately $175 million of surplus capacity at year end
10 bank syndicate, led by BMO – Legacy in proactive dialogue with syndicate
Routinely reviewed twice a year, next review in April
Banks have not requested an accelerated review
4.0X total debt/EBITA and 3.0X bank debt/EBITA covenants on a 4 quarter trailing
basis, as reported
Oil prices would have to average US$52/Bbl WTI for all of 2015 before these
covenants are approached in Q1 2016
6
2015 Guidance
Disciplined budget with focus on balance sheet and value preservation – spend within cash flow
Majority of drilling capital allocated to Midale and Turner Valley – generates returns well above
cost of capital at current strip pricing
Scalable budget – curtail or expand program based on commodity prices
Increased spending on waterfloods YoY – reduce corporate decline rate
2015 Guidance
Capital Expenditures: $238 million (~40% reduction over 2014)
Drill approximately 94 gross (79.4 net) wells targeting light oil
Avg. rate: 24,500 Boe/d (6% growth over 2014)
Exit rate: 27,300 Boe/d
Production mix: 85% light oil and NGL’s
2015 Capital Budget Breakdown
$238 Million Total
Operating assumptions
Royalties
Operating Costs
Transportation Costs
G & A (expensed)
14.5 %
$13.75/Boe
$3.10/Boe
$2.50/Boe
87% DC&E and Waterflood
Hedging
650 Bopd
400 GJ/d
H1 2015
H1 2015
Ave. US$91.29/Bbl WTI
Ave. C$4.39/GJ AECO
DC&E
Waterfloods
Facilities
Land/Seismic/Other
7
High Quality Light Oil Plays
(results based on Sproule Dec. 31/14 price forecast)
EXPL.
DEVELOPMENT
Play
Oil
Weighting
(%)
Net
Locations
API
DCET
Cost
(M$)
IP30
(BOED)
NPV
Capital (1)
@10% BT Payout Efficiency
(M$)
(yrs) ($/BOED)
IRR
(%)
Midale
85
38
351
2,200
165
64
1,642
1.4
22,000
Conventional
95
36
428
1,100
85
115
1,455
1.1
18,033
90
42
504
2,100
190
53
1,284
1.5
21,229
Spearfish
98
36
571
1,475
90
27
269
2.5
25,833
Three Forks - Frys
98
40
126
1,900
90
22
700
3.4
29,231
Williston Basin Total
94
38
1,980
1,756
131
59
1,055
1.8
22,038
Turner Valley
93
40
96
5,500
250
48
7,526
2.3
31,429
Total Development
94
39
2,076
1,979
140
58
1,354
1.8
22,200
Maxhamish
98
42
263
92
42
182
94
39
2,521
Bakken
(2)
Three Forks
(3)
Total Dev.+Expl.
1. Based on IP365
2. Includes Heward, Star Valley and Taylorton
3. Includes Taylorton/Pinto and Flat Lake
8
Other Initiatives
Asset sales are under consideration
Elmworth sale is pending
Given current low equity valuation, additional asset sales
would be highly accretive to valuation
Impactful to balance sheet improvement and therefore share
price
Volatility in oil prices have intervened in the market, delays in
possible sales may persist until some stability seen in the oil
quote
Other asset monetization
All options are on the table
9
Light Oil Price Advantage
Q3 2014
operating
netback of
$50.46/Boe
10
Focused + Light Oil Asset Base
Two core areas - each area has focused
development assets and new play
development opportunities:
MAXHAMISH
Williston Basin
‒
Development – Taylorton, Heward, Star Valley,
Spearfish, Frys/Antler, Mississippian
conventional
‒
New play development – Midale, Three Forks,
Mississippian conventional plays using
innovative seismic techniques, waterflood
EDMONTON
Turner Valley
‒
Development – Turner Valley Rundle field
‒
New play development – use of new 3D
seismic in Rundle and shallower zones
TURNER VALLEY
CALGARY
WILLISTON BASIN
REGINA
Emerging light oil resource play at
Maxhamish, BC
11
Williston Basin – Resource Plays +
Conventional
Production of ~21,000 Boe per day
High quality light oil, averaging 38o API
SOUTHEAST
SASKATCHEWAN
>1,980 net drilling locations on 464,000
net acres
Multiple play types:
High impact Midale play rapidly
expanding
HEWARD
Spearfish oil resource play
MANITOBA
PARKMAN
TATAGWA
BAKKEN
STAR
VALLEY
FRYS
LIGHTNING
WAUCHOPE
Development locations in the Bakken
resource play
Large inventory of conventional
Mississippian light oil locations
MANOR
EDENVALE
GOODWATER
STEELMAN
CEYLON
ALAMEDA
CARNDUFF
FLAT LAKE
OPENSHAW
TAYLORTON
Large Three Forks resource mapped
Significant reserves upside from low risk
field optimization, infill drilling and
waterflood
Large data set of 3D seismic
MIDALE
PINTO
BAKKEN+THREE FORKS
SOURIS FLAT
PIERSON
NORTH DAKOTA
BOTTINEAU
Legacy Focus Areas
Light Oil Resource Plays
Key owned and operated infrastructure
supports top-tier netbacks
12
Steelman/Pinto – Midale
High impact conventional play with
unconventional completion technique
S.E. SASK.
MANITOBA
Light oil (34-40 API)
Horizontal multi-stage frac has produced
strong production results
Legacy involved in play concept since its
inception (3 years)
Significant number of unbooked locations
Waterflood pilot commenced Q1 2014
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R7
R5
R4
R3
R2
R1W2M
R34
R33W1M
T6
NORTH DAKOTA
T5
MIDALE POROSITY EDGE
STEELMAN
B
Q3 wells 250 BOED 30 day IP
T4
B
Production Performance Improving
ALAMEDA
50.0
T3
LEGACY RECENT
MIDALE WELLS
45.0
Cum. Oil Production (MBbl)
R6
40.0
OPENSHAW
T2
35.0
30.0
SOURIS
FLAT
TAYLORTON
25.0
B
20.0
T1
PINTO
Legacy Land
B
15.0
Legacy 3D Seismic
Midale Wells
10.0
Conventional not frac’d
5.0
0.0
0
2
2009
4
6
2010
8
10
12 14
16
Months
2011
2012
18
2013
20
22
24
2014
13
Turner Valley – Rundle
40o API light oil, liquids-rich solution and non-associated natural gas with
low historical oil decline rate of 4%
Operated high WI, extensive infrastructure, batteries and natural gas plant
CARDIUM
FARM-OUT
WELLS
Large resource
Oil 1.3 billion Bbl OOIP
(1),
natural gas 1.6 Tcf OGIP
(1)
Low recovery factor of 12% to-date
UNIT #6
5.13%
Recent horizontal wells strongly outperforming
80.0
UNIT #5
82.93%
70.0
60.0
Cum. Prod (MBbl)
SOUTHERN
U
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G
G
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G
G
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J
G
V IG G
ME E M S
D
UV G
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F
S SI MG
MS E I
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G
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U
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MG
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UNIT #7
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40.0
30.0
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20.0
10.0
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0
2
4
6
Previous Operator
8
10
12
14
Month
All LEG Wells
16
18
20
22
Last 9 LEG Wells
Numerous opportunities
96 net locations, including 86 net Rundle multi-lateral horizontal
locations
3D seismic key in re-interpretation of the geology, faulting and
fracturing; more effective drilling and waterflood optimization
24
UNIT #4
82.46%
UNIT #3
87.72%
1.
Both figures from published ERCB estimates (Units 3, 4, 5, 6, 7)
14
Pierson + North Dakota – Spearfish
‒
‒
$1.5 to $1.6 million (1,400 m lateral)
$1.2 to $1.3 million (700 m lateral)
MANITOBA
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Bottineau County, North Dakota
400 net locations on northern lands at
200 m spacing, approximately 65
percent unbooked
151,769 gross (138,363 net)
undeveloped acres
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Pierson, Manitoba
171 net locations at 200 m spacing,
approximately 80 percent unbooked
50,098 gross (48,565 net) undeveloped
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Sales oil and solution gas recently tied in
Pilot waterflood start-up expected in Q4
2014
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PIERSON
OOIP ~ 750MMSTB
U
G
G
G
E
E E JJ
G
G
E E JJJ
EJ
JA
VM EE J
E EJ VG
EG
E VSVJ
R22W1M
JJJ
EV V
JJJV VVEVVE E
R23
A
G
G
G
G
WASKADA
OOIP ~ 1000MMSTB
T1
G
G
G
G
G
LEGACY 3D SEISMIC
G
G
G
E
BOTTINEAU
G
G
G
G
DOWNDIP LIMIT OF
SPEARFISH FAIRWAY
G
NORTH DAKOTA | MANITOBA
Play Attributes
1,000 m depth
12 MMBbl DOIP per section
Monobore completions with 30 stages
Low well cost
G
G
G
G
LegacyGLand
G
Legacy Drills
G
G
G
Spearfish Producers
G
15
G
Conventional Mississippian Plays
Main producing and target
zones include Souris Valley,
Tilston, Alida, Frobisher and
Midale
SOUTHEAST
SASKATCHEWAN
MANITOBA
Wells not frac’d, payouts 12
months or less
Average well cost $1.1 million
Drilling inventory of more
than 425 net locations
Continuing focus on
developing new prospects
aided by extensive 3-D
seismic coverage
HEWARD
PARKMAN
FRYS
STAR VALLEY
TATAGWA
LIGHTNING
MANOR
EDENVALE
GOODWATER
MIDALE
CEYLON
FLAT LAKE
OPENSHAW
TAYLORTON
Legacy owns and operates
key producing infrastructure
ALAMEDA
STEELMAN
BURKE
COUNTY
CARNDUFF
PIERSON
PINTO
NORTH DAKOTA
BOTTINEAU
Legacy Land
16
Waterflood Benefits
Add reserves cost-effectively
Typically double primary recovery factor
Finding & development costs low double digit
Leverage existing lands and infrastructure
Moderates declines
Oil production plateaus and can increase
Reduces treadmill effect caused by horizontal drilling and multi-stage fracs
Production stabilizes at higher rate than primary
Source of free cash flow
Once fully implemented, no material capital requirements
Can harvest the cash flow and use to fund other growth/early stage
opportunities or pay dividend – improves company sustainability
17
Impact of Waterflood Potential to Legacy
Area
Gross OOIP
(MMBbl)
Net Sections
WF Reserves
(MMBbl)
NPV@10% BT
($ million)
Bakken
377.3
80.5
30.0
954.7
Torquay
219.5
33.3
15.4
394.9
Spearfish
599.6
51.7
52.7
613.1
Midale
177.6
36.1
15.6
428.1
Total
1,374.1
201.5
113.7
2,390.8
Assumptions:
1.
OOIP from Sproule Contingent Resource Assessment
2.
Potential reserves based on impact of a 10.5% incremental recovery factor
3.
Waterflood implemented over 6 years
4.
NPV based on single section economics
5.
Stated amounts are for illustrative purposes only and do not constitute an evaluation of reserves under NI 51-101
18
Independent Reserve Engineers
Sproule Associates Limited
Bank Syndicate
Bank of Montreal
National Bank
The Bank of Nova Scotia
Canadian Imperial Bank of Commerce
JP Morgan Chase Bank, NA
The Toronto-Dominion Bank
ATB Financial
Caisse Centrale Desjardins
Wells Fargo Bank, NA
HSBC Bank Canada
Auditors
PricewaterhouseCoopers LLP
Contact Information
4400, 525 – 8th Avenue SW
Eighth Avenue Place
Calgary, Alberta T2P 1G1
Tel: 403.441.2300
Fax: 403.441.2017
Email: [email protected]
Website: www.legacyoilandgas.com
TSX: LEG
Legal
McCarthy Tetrault LLP
19
APPENDIX
20
Southern Alberta – Bakken
Alberta Basin Bakken Play
I
F
IP4 DAYS:
715 BOPD G
UE
C
G
V
F
E
E
F
IP7 DAYS: 630 BOPD
LGX owns 109,990 net acres on play fairway
95 square mile 3D seismic survey shot
Bakken oil system - Banff/Exshaw/Big Valley
formations tight oil resource play
Key 1979 Big Valley producer (10-30) adjacent to
lands – 250 MBbls to date
J
E
G
E
R24
V
G
F
J
E
E
F
IP90: 307 BOPD
CURR: 63 BOPD
CUM: 93 MBBL
J
E
E
F
V
J
LGX PENNY
13-2-9-24W4G L
J 2014 DRILLED WELL
E
LGX PENNY
15-25-8-24W4
E
2014 DRILLED WELL
G
C
F
C
V
V
G
G
C
F
Additional prospective light oil targets include the
Second White Specks, Barons, Mannville and Nisku
formations
LGX Oil + Gas Inc.
J
E
G
F
EC
E
E
G
E
E
E
J
IP90: 130 BOPD
CURR: 95 BOPD
CUM: 135 MBBL
E
F
G
V
F
C
F
F
E
EE
V
J
G
F
Legacy owns 16 million common shares of LGX
Provides management and technical services
‒
Has two members of board of directors
E
Big Valley Well Control
E
Banff/Exshaw/Big Valley Shows/Prod.
G
T7
F
G
J
E
K
F
G
L
T6
LGX 95 SQ. MI.
3D SEISMIC
G
V
G
F
C
G F
G
T5
RECENT KAINAI
BIG VALLEY WELL
J
E
E
E
T4
G
LGX 3D Seismic
G Reserve
F
Blood First Nation
J
10-15-7-22W4
2013 DRILL
G
E
IP90: 84 BOPD
CURR: 72 BOPD
CUM: 24 MBBL
T8
ECGV
F
F
LGX Land
‒
LGX PENNY
14-2-9-24W4
2013 OIL DISCOVERY
CURR: 103 BOPD
CUM: 66 MBBL
G
cumulative production is over 77 MBbls
Up to 40 sections of LGX land offsetting the 14-2
and new wells discovery high-graded for Big Valley
and/or Banff oil production; prolific Banff fairway
trending onto LGX lands
V
G
F
T9
J
E
LGX HZ. BLOOD
5-10-7-23W4
2012 DRILLJ
E
POTENTIAL FOR RE-ENTRY
AND HORIZONTAL LEG
MONTANA
MONTANA
G
S
E LGX KAINAI HZ. KIPP
E
8-30-8-23W4
IP90: 97 BOPD
CURR: 13 BOPD
CUM: 30.1 MBBL
G
G G
G
T10
G
C
F
RECENT KAINAI
BIG VALLEY WELL
Currently producing approximately 90 BOPD;
G
V
F
E
F
EE
R23W4M
G
BRITISH
COLUMBIA
C
C
F
F
IP60:
240 BOPD
CURR : 57 BOPD
CUM: 36 MBBL
BRITISH
COLUMBIA
COLUMBIA
V V
G
SOUTHERN
SOUTHERN
ALBERTA
R21
ALBERTA
IP90: 330 BOPD
CURR : 339 BOPD
CUM: 61 MBBL
I
V F
V
G
E E
J
RECENT KAINAI
G
GU E
E V
E
F
VE
E
F
A
J
F
E
BIG VALLEY LICENCE
E
E
E
F
F
G
E F
CE
F
EE
CV
V
G
V F
E
CG
AA
F
F
E EE
J
K
F
A E
E
F
G
G
E
F
E
E UV E
G
G
J
G
E
INDRA BLOOD 10-30
BIG VALLEY VERTICAL WELL
CUM: 255 MBBL
Performance comparable to best offsetting wells
G
F
E E
CVE
EE EE
EE
E
J
E
IP90: 305 BOPD
CURR: 61 BOPD
CUM: 109 MBBL
R23
E
D G
F
F
V E
F
EE
TORC
HORIZONTALS
G 177 BOPD
IP90:
E
CURR: 27 BOPD
CUM: 69 MBBL
G
2013 producer drilled at 14-2
‒
E
F
G
V
Drilled two wells in Q3/Q4 2014; currently
production testing through new battery
‒
FD
FV
V
R26
V
EE
F
E
LGX HZ. SPRINGCO
2-36-3-23W4
CUM: 4.1 MBBL
T3
G
21
Maxhamish, BC – Chinkeh
F
FV U
Chinkeh Formation light oil resource play
A
D
1,600 m depth
FNORTHWEST
F
TERRITORIES
F
UG
F
G
F F
F
FK
F UV
C
B
C
G
F
F
UVU F
F
F
F
C
Significant resource of 42o API light sweet oil,
confirmed by horizontal drilling and production
results
Aerially extensive sheet sand, 3 – 5 m thick
F
F
C
F
F
F
G
L
C
K
G
A
V
K
E EE
Drilled four 1,400m horizontal wells in 2010
and 2011
H
E
F
K
U KH
K
G
A
C
C
K
F
V
F
V
G
G
F
V
F
C
G
A
GC
F
K
A-18-J/94-O-11
GU
BATTERY
F
F
2011 DRILL
CUM: K
35.1 MBBL
LIGHT OIL RESOURCE
K
G
FAIRWAY
GV
D
F
F
K
K
FVU
L
All-season road and multi-well pads
completed, allowing summer drilling
K
F
K
V
G
F
V
11
F
F
F
F
FC
F
G
K V
2011 DRILL
CUM: 12.8 MBBL
Brought on production in Q2 2010 and late
2011; still averaging approximately 35 Boed
per well at 98% oil cut
F
C
E
2010 DRILL
CUM: 47.4 MBBL
Operated 61.5% W.I. in 69,000 acres (109
gross sections) of contiguous land
ALBERTA
F
F
F
G
F
F
F F
U
G
F F
F
F
ALL-SEASON
V F
F
F
GU
U
ROAD
LG
I
J
F F
EUV
F F
C
F
F
E
E F
C F
A
F
A
F
F
E
V
CV
VUEV B
F
E
F
F F
2010 DRILL
CUM: 37.3 MBBL
I
A
F
F
F
N.E BRITISH
F F
COLUMBIA
F F
6.5
MILES
F
V
F
C
G
C
F
G
F
K
G
F
D
G
C
F
K
C
U
G G
CD
FU
A
B
FG
U
F
G
A
F
F
G
F
F
G
U
I
CV
L
Legacy Land
Open Crown - Chinkeh Rights
C
MAXHAMISH AU
GAS FIELD F
F
VU
F
U F
F
F
C
K
C
GG
G
A
F
F
K
C
G
UC F
G
F
I
J
K
G
G
Legacy 2010-2011 Horizontal Drills
22
Heward + Taylorton – Waterflood
Heward
Heward
Oil Production
Response
Pilot Waterflood
Start of Injection
Taylorton
Taylorton
Pilot Waterflood
Oil Production
Response
Start of Injection
23
Frys + Pierson + Steelman – Waterflood
Frys
Frys
Oil Production
Response
Pilot Waterflood
Start of Injection
Pierson
Steelman
Proposed Pilot
Waterflood
Proposed Pilot
Waterflood
Pilot Waterflood
24