2
CAUTIONARY
STATEMENTS
Certain information regarding the Company contained in this presentation, including our liquidity position, our business strategies, plans and objectives; our guidance for 2015 including our capital budget, production targets and anticipated product type weighting; expectations regarding our real ized oil and natural gas prices; proposed exploration and development activities (including the number of wells to be drilled, completed and put on production); our drilling inventory; the timing of certain projects; future finding and development costs; asset disposition strategy; sources of capital, anticipated interest savings, debt repayment, the sufficiency of our financial resources to fund our operations may constitute forward-looking statements under applicable securities laws.
The forward‐looking statements are based on certain key expectations and assumptions made by the Company, including, without limitation: that Lightstream will
continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes, the accuracy of the estimates of Lightstream’ s reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate financing and cash flow to fund its planned expenditures. Although the Company 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 Company 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 commodity price and exchange rate fluctuations, the oil and gas industry in general (e.g.,
operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), changes in the regulatory regime applicable to the Company and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in the Company's Annual Information Form which has been filed on SEDAR and can be accessed at www.sedar.com. The forward‐looking statements 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 otherwise, unless so required by applicable securities laws.
This presentation contains financial terms that are not considered measures under International Financial Reporting Standards (“IFRS”), which are considered to be
3
OUR ASSET BASE
Q2 2015 Production:
31,966 boepd;
72% liquids weighted
Year-to-Date Production:
33,563 boepd;
76% liquids weighted
Business Units
Q2 Production
4
2015 CORPORATE
STRATEGY
Retain long-term value and preserve financial flexibility in
the current low commodity price environment
Operational Plan
Suspension of monthly dividend
Capital program of $100 - $120 million, funded by internally generated cash flow
First half spending was $80 million; $30 million estimated for second half
Drilling one additional high-impact gas well in Cardium Falher play in second half
Annual average production of 30,500 – 32,500 boepd
Funds flow from operations of $175– $195 million at WTI of US$50.00/bbl
1
$75 million surplus cash to be applied to debt
Strategy to potentially sell our Bakken business unit
Proceeds would be used to transform our balance sheet and shift LTS into an
Alberta-focused company with a growth platform
5
2015 CAPITAL &
DRILLING PROGRAM
2015 Planned Capital Activity
Business
Unit
DCET
(million)
Facilities
(million)
Workovers,
Optimization
& Other
(million)
Net
Wells
Bakken
7
$19
$9
$14
Cardium
9
48
9
6
AB/BC
0
0
2
3
TOTAL
16
$67
$20
$23
Our 2015 capital & drilling program is $110 million
1
with a suspended second half
operated drilling program given low commodity prices and current capital costs
1. Mid-point of guidance
In Q2 we drilled 1 net non-op well, brought 6 wells on production, leaving 2 wells in
inventory
6
CAPITAL & FUNDS FLOW
We expect to generate funds flow well above our capital spending in 2015
Funds Flow Capital Expenditures* Cash Dividend Annual Outflows/Inflows (%)
*Does not include A&D
7
DEBT AND LIQUIDITY
Term subject to
further extensions
Term Secured Debt
$750 million Credit Facility
1Our second lien debt transactions in Q3 reduced overall debt and
increased credit capacity
2015
2017
2020
Senior Unsecured Notes (8.625% interest)
D
EB
T
C
A
PIT
A
L
C
OM
PO
SIT
IO
N
MATURITY DATE
Term Unsecured Debt
US$254 million High Yield Notes
31. The borrowing base is subject to re-determination on a semi-annual basis and the amended credit facility contains a single financial covenant as described in our May 21, 2015 press release. Pro forma US$200 million second lien note issuance July 2,2015. 2. See slide 10 for second lien overview.
3. Original high yield issue of US $900 million. Current balance reflects total repurchases of US$100 million and debt exchanges and cancellations of US$546 million.
~$375 million of available liquidity
~$375 million drawn
(Pro forma Q2 2015)
Term Secured 2
ndLien
8
SECOND LIEN
OVERVIEW
In Q3 we issued US$650mm of second lien notes with a semi-annual coupon of 9.875%
US$546 million of senior unsecured notes exchanged
for US$450 million of second lien notes
Immediate debt reduction of ~$125 million
1
and annual interest savings of ~$3.4 million
1
Maturity date of June 15, 2019
US$200 million of second lien notes were issued for cash which was
applied to reduce outstanding borrowing under our secured credit facility
Liquidity increased to ~$375 million with borrowing base of $750 million
9
DEBT POSITION
We have decreased our overall debt positon since 2012, with
continuous access to an appropriate level of liquidity
2015 (e)
12010
2011
2012
2013
2014
Credit Facility Drawn Credit Facility Available Convertible Debenture
2Second Lien
2Unsecured
2Working Capital Deficit
1. Based on our $750 million credit facility in place at June 30, 2015 and second lien 2.Stated in $USD
3. Debt reduction based on pro forma Q2 2015 including debt exchanges and surplus cash generated in 2015
$0
$500
$1,000
$1,500
A
m
o
u
n
t
('
0
0
0
)
Total Debt Outstanding
10
GUIDANCE
2015 Guidance
(Aug 5, 2015)
2015 Actual
1H 2015
Average Production (boe/d)
30,500 – 32,500
33,563
Exit Production (boe/d)
26,500 – 28,500
Liquids Weighting
73%
74%
EBITDA
$295,000 – $315,000
$174,202
Funds Flow
1Funds Flow from Operations (000)
$175,000 – $195,000
$118,984
Funds Flow per share
$0.89 – $0.99
$0.60
Annual Dividend per share
$0.00
$0.00
Capital Expenditures (000)
2$100,000 - $120,000
$80,429
Economic Parameters
WTI oil price
US$50.00/bbl
3US$53.29/bbl
Light oil wellhead price differential
15%
15%
AECO gas price
$3.00/mcf
$2.74/mcf
Foreign exchange rate (US$/Cdn$)
0.77
0.81
In the current commodity price and service cost environment we intend to limit our
investment in new well drilling in the second half of 2015
11
$0 $5 $10 $15 $20 $25 $30 $35 $40 $45WCP VET LTS TOG BTE CR PGF ERF PWT TET BNP BXE
Q2 Operating Netback Plus Commodity Hedges
Operating Netback Realized Commodity Contract Hedge Gain
Q1 2015 NETBACKS &
HEDGING EFFECTS
In Q2 2015 we realized a gain of ~$20 million on crude oil derivative contracts,
resulting in a netback of $35.87/boe
12
FUNDS FLOW
PROTECTION
Our 2015 crude oil hedge position helps provide funds flow downside protection
We are building our 2016 oil hedge portfolio to protect against a further drop in prices
1. Net production (less royalties of 15%), 73% liquids weighting
2. Based on mid-point of annual average production guidance and US$/Cdn$ exchange rate of $0.77 3. All hedge proceeds stated in Cdn$
4. We have an average ~950 Mcf/d of AECO swaps at an average price of $3.01/Mcf in 2H 2015 and an average ~3,800 Mcf/d at an average price of $3.08 in 2016.
We aim to hedge 25% - 50% of net production
34% of net liquids production
1,2
hedged in 2H 2015
Typically hedge 12 - 36 months out depending on market conditions
Cash proceeds on crude oil derivative contracts for Q2 were ~$20 million
3
Commodity
Jul – Dec 2015
Jul – Dec 2015
1H 2016
2H 2016
Oil hedged - WTI (bbl/d)
Ceiling ($US/bbl)
Floor ($US/bbl)
Fixed Price Swap ($US/bbl)
4,795
$103
$80
N/A
1,500
N/A
N/A
$56
1,500
N/A
N/A
$51
500
N/A
N/A
$50
Estimated Cash Proceeds from Hedging for 2H 2015
WTI Prices
US$50/bbl
US$55/bbl
US$60/bbl
US$65/bbl
US$70/bbl
13
ECONOMIC
SENSITIVITIES
Parameter
Assumption
Change of:
Funds Flow Impact
($ millions)
WTI Oil
1,2
US$50.00/bbl
+/- $1.00
$2.0
Production (2H 2015)
29,440 boepd
+/- 1,000
$3.2
Natural Gas (AECO)
1
$3.00/mcf
+/- $0.10
$0.8
Exchange Rate (US$)
1
$0.77
+/- $0.01
$1.9
Sensitivities and assumptions on remaining six months of 2015
on funds flow from operations
Current 2015 plans are based on funds flow from operations meeting or exceeding
capital expenditures
We will make further adjustments to our plans as required to keep spending at or below
funds flow from operations
14
$0
$20
$40
$60
$80
$100
$120
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 $/ boeQuarterly Cash Costs and Oil Prices
CASH COSTS
In this low commodity price environment, we continue to
generate positive funds flow from operations
Production Expenses Royalties Transportation G&A Interest
WTI (USD) Edmonton Light Sweet(CAD)
15
BAKKEN ASSETS
Focus on optimization and EOR
Our assets produce light oil from the Bakken and the conventional Mississippian formations with a relatively
low decline rate. In 2015 we are continuing to focus on optimizing and expanding our natural gas EOR
projects in the Bakken. We have an extensive network of facilities that allows us to control operating costs.
LTS Land
LTS Gas Plant Sales Oil Pipelines Sales Gas Pipelines
LTS Operated Wells LTS Batteries EOR Wells
Business Unit
Bakken
1Results
Q2 2015 1H 2015
Average Production (boepd)
11,720
12,760
Oil/Liquids Weighting
93%
92%
Operating Income ($ million)
33
61
Capex ($ million)
8
27
Free Cash Flow ($ million)
25
34
2014 2P Reserves (mmboe)
69
Upside Opportunities
1Undeveloped Land (sections)
261
Drilling Inventory (net locations)
> 1,050
16
0 3 6 9 12 0 200 400 600 800 1000 1200 1400 1600Feb-08 Feb-09 Feb-10 Feb-11 Feb-12 Feb-13 Feb-14 Feb-15
Num b e r o f W e lls
EOR Benefit Primary Prod. From Inj. Well Base Production Producing well count
Original injection well drilled and placed on primary production Cal e n d a r Day O il ( bbls )
Natural Gas Injection commenced
IMPROVING TIGHT OIL
RECOVERIES
Future value generation through natural gas flooding
With Bakken EOR projects we expect to:
Attenuate declines and extend production life
Increase DPIIP recovery factors from 15% to potentially >25%
Improve economic returns with high
production-to-injector well ratios
13 section Creelman EOR Unit has been finalized
1 section Midale EOR Unit has been finalized
2 additional injection wells planned for 2015
1 conversion in Creelman and 1 in Midale
17
CARDIUM ASSETS
Generating positive operating cash flow
Our extensive land base stretches from southwest of
Calgary to northwest of Edmonton and our assets
primarily produce light oil from the Cardium formation.
We are continuously evolving our drilling and completion
techniques and we initiated water injection for EOR in
July 2014. This is an active area for industry, with
multi-zone potential.
Business Unit
Cardium
Results
Q2 2015
1H 2015
Average Production (boepd)
17,455
17,557
Oil/Liquids Weighting
60%
62%
Operating Income ($ million)
47
81
Capex ($ million)
12
54
Free Cash Flow ($ million)
35
27
2014 2P Reserves (mmboe)
79
Upside Opportunities
Undeveloped Land (sections)
126
Drilling Inventory (net locations)
> 460
West Pembina Brazeau West Pembina Brazeau Lochend LTS Land
18
0
100
200
300
400
500
0
5,000
10,000
15,000
20,000
25,000
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
2010
2011
2012
2013
2014
2015
N
et
W
ells
on
Prod
uct
ion
P
rod
u
ctio
n
(bo
e
p
d
)
Cardium Production and Cumulative Well Count
Production (boepd) On-Stream Well Count
CARDIUM GROWTH
* Production is after Q1 2014 asset dispositions of 1,200 boepd
19
AB / BC ASSETS
The Swan Hills is our next growth target
Production has grown to >2,500 boepd
New 3,500 bopd battery operational in Q2 2014
Future Operations
Reserve bookings confirm long-term prospectivity
Drilling not expected to resume before 2016 given
current economic environment
Capital expenditures reduced due to accrual
reversals on seismic, drilling and equipping activities
Business Unit
AB / BC
1Swan Hills
Results
Q2 2015
1H 2015
Q2 2015
1H 2015
Average Production (boepd)
2,791
3,246
1,787
2,166
Oil/Liquids Weighting
64%
66%
92%
92%
Operating Income ($ million)
5
9
5
10
Capex ($ million)
-
1
-
1
2014 2P Reserves (mmboe)
13
8
Upside Opportunities
Undeveloped Land (sections)
441
118
Drilling Inventory (net locations)
>295
95
LTS Land Sales Oil Pipelines LTS Operated Wells LTS Batteries
20
SWAN HILLS
PRODUCTION
Swan Hills production has increased our liquids weighting for
the Alberta/BC business unit
0
5
10
15
20
25
0
1,000
2,000
3,000
4,000
5,000
Q1 '13
Q2 '13
Q3 '13
Q4 '13
Q1'14
Q2'14
Q3'14
Q4'14
Q1'15
Q2'15
Net
W
e
lls
o
n
P
rod
u
ctio
n
P
rod
u
ctio
n
(bo
e
p
d
)
Swan Hills Production and Cumulative Well Count
Swan Hills Production
AB/BC Production
Swan Hills On-Stream Well Count
*
Q2 production decrease due to third party facility turnaround, increased downtime21
Assumptions:
WTI oil price year 1: US $65/bbl and $80/bbl thereafter, AECO gas price year 1: $3.00/Mcf and $4.00/Mcf thereafter, foreign exchange rate of US$/Cdn$ $0.80, differential of 7.5%, before tax, excludes land costs
Well counts are based on formation locations and are high graded to what we would drill today. 1. 2014 actual costs; no 2015 input cost savings are reflected
2. Internal estimates
