Normandville Montney oil

Report
HERE FOR THE LONG RUN
INVESTOR UPDATE – AUGUST 2013
TSX: LRE
LONG RUN PROFILE
Key Metrics
Listing
TSX:LRE
Shares Outstanding
126 million
Enterprise Value
~$800 million
Liquidity (shares/day)
~400,000
2013 Q1 Production
24,431 boe/d
Oil + NGLs
12,587 mbbl/d
Gas
71.1 MMcf/d
Average Oil Gravity
52% oil
48%
natural
gas
$450 million
credit facility
32° API
Tax Pools
$1.3 billion
Land Holdings
1.9 million acres
P+P RLI
9.1 years
LONG RUN EXPLORATION
2013 Q2 Production
$122
Undrawn
$328
Drawn
1
SECOND QUARTER 2013 HIGHLIGHTS
Increased Production and Funds Flow from Operations
• Average production of 24,431 boe/d, 52% crude oil and liquids
• Q2 ‘13 Peace Area production increased 6% from Q1 ‘13 to 9,952 boe/d
• Q2 ’13 Redwater production increased 6% from Q1’13 to 5,444 boe/d
• Funds flow from Operations of $63.2 million ($0.50 per share)
• Resource assessment identified Discovered Petroleum Initially-in-Place of
301.2 million barrels of oil (best case) on a portion of Long Run’s Montney
lands in the Peace area
LONG RUN EXPLORATION
2
PRODUCTION GROWTH
Forecast 2013 Annual Average Production of 25,000 boe per day
average annual boe per day
30,000
25,000
Natural Gas
25,000 boe per day
Oil & Liquids
20,000
15,000
10,000
5,000
0
2009
2010
2011
2012
2013
(forecast)
LONG RUN EXPLORATION
3
A TYPICAL BOE
Q2 Netback
2013 Target Funds Flow of $230 million
$52.72
-$4.38
-$13.98
-$2.36
Sales Price
Royalties
LONG RUN EXPLORATION
Operating
expenses
Transportation
$32.57
Field netback
-$2.47
G+A
-$1.63
$28.44
Interest
Corporate
netback
4
BUSINESS SUSTAINABILITY
Adding Production & Reserves
• Development of light oil play areas through horizontal technology
• Ongoing development work targeting oil at Peace in the Montney and at
Redwater in the Viking
• Multi-year inventory of locations
• Opportunistic Acquisitions
• Target rich environment
• Highly experienced M&A team
• Enhanced Recovery
• Current light oil assets highly amenable to EOR
• Strong technical team with significant experience in initiating and maintaining EOR
LONG RUN EXPLORATION
5
BUSINESS LANDSCAPE
Investor Demand
• This junior/intermediate yield sector has been in favour with investors over
the past two years, generating returns in excess of the broader energy index
on a total return basis (including yield)
• Growing investor demand for yield product that achieve a blend of capital
appreciation and income
• Growing yield sector in junior / intermediate energy companies as demand
for yield products continues to outstrip supply
• Tightening of capital markets with diminished support for equity issuances
from growth (non-yield) energy companies
LONG RUN EXPLORATION
6
RESERVES
Strong Year -Over-Year Growth
Reserve Growth (mmboe)
100
Reserves (mmboe)
Probable
80
Proved
29.5
60
Natural Gas
47 mmboe
40
Oil & Liquids
36 mmboe
53.6
20
0
2009
2010
2011
2012
2012 Reserve Highlights
• P+P Net asset value of $9.60 per share
• P+P reserve life index of approximately 9.1 years
LONG RUN EXPLORATION
7
2013 CAPITAL BUDGET
Targeting Growth
Capital Spending ($275 MM)
Number of wells
Land / Seismic /
Exploration $30
Montney Oil
$110
Optimization /
Other $10
14
Other Oil & Gas
Facilities $15
Other Oil & Gas
$28
68
132
wells
Viking Oil
Peace River
Montney Oil
50
Montney Oil
Viking Oil
$82
LONG RUN EXPLORATION
8
KEY PROPERTIES
Exploration and Development Focused
Northern Gas
Peace River
Exploration
Edmonton Area
LONG RUN EXPLORATION
9
PEACE RIVER AREA
Dominant Position in Multi-Zone Play
• 600,000 net acres
• Primary targets are Triassic
age resource plays
targeting oil and liquidsrich gas
Worsley
Peace
• Current development
focus area is Girouxville/
Normandville Montney oil
LONG RUN EXPLORATION
Smoky
Normandville/
Girouxville
10
MONTNEY
Normandville / Girouxville
• Current production of 9,450
BOE/d (60% oil)
• Resource Assessment evaluated
92 sections of land in Montney
fairway
Normandville
Peace River Area
Girouxville
• Have drilled 60+ wells to-date
• Multi-year development
inventory
•
Initial development plan average up to 6
wells/section
•
Have started injection on initial EOR pilot
• 50 wells planned in 2013
• Have reduced spud to rig-release
time from 11 days to 9 days over
last 30 wells
Potential water injection wells
Identified Montney Oil
Historical Hz well
New Hz well
LONG RUN EXPLORATION
11
MONTNEY
Resource Assessment Identifies Significant Resource In-Place
For the purpose of the Resource
Assessment, 48% of LRE’s Montney acreage
was evaluated by third-party engineers
Unevaluated
Evaluated
64,529
acres
58,783
acres
301.2 mmbbls of oil DPIIP
Total Normandville/Girouxville
Montney = 123,312 Acres
25 mmbbls illustrative
unbooked oil - secondary(2)
13.6 mmbbls booked
15 mmbbls illustrative
unbooked oil – primary(2)
(1)
(best)
40 mmbbls
potential
unbooked oil
upside (2)
1.9 mmbbls oil produced
Notes:
(1) Discovered oil initially in place ("DOIIP") is evaluated in an independent resource assessment (the "Resource Assessment") prepared by Sproule Associates Limited ("Sproule") effective December 31, 2012 on a portion of Long Run's lands (the "Evaluated Areas") covering the Montney formation at Normandville and
Girouxville which evaluated the discovered petroleum initially in place ("DPIIP"). The DOIIP and DPIIP currently cannot be further subcategorized as it is not possible at this time to define a recovery project for this DOIIP or DPIIP. See "Advisory" section of this Presentation with respect to additional advisories on DOIIP
and DPIIP.
(2) Included for illustration purposes only. Primary assumes 10% recovery of best case DOIIP; secondary recovery assumes 8% recovery of best case DOIIP. While included for illustration purposes, it should be noted that while waterflood technologies have been used in what Long Run believes to be analogous pools,
the effectiveness of such techniques in the Evaluated Areas covered by the Resource Assessment has not been established. There is no certainty that enhance recovery techniques and additional infill drilling which is planned, will increase recoveries. Enhanced recovery projects have historically been developed
sequentially over a number of drilling seasons and are subject to annual budget constraints. Long Run's policy of orderly development on a stage basis, the short and long-term view of Long Run on commodity prices, the results of exploration and development activities of Long Run and others in the area and
possible infrastructure capital constraints will determine the pace of development.
LONG RUN EXPLORATION
12
MONTNEY EXISTING FACILITIES
Substantial Throughput Capacity
Normandville
Oil Battery
5,000 bopd
15 MMcf/d
Peace River Area
Donnelly Gas Plant
28 MMcf/d to sales
Girouxville
Oil Battery
5,000 bopd
12 MMcf/d
LONG RUN EXPLORATION
13
MONTNEY
Horizontal Type Curve Economics
300
• 12-month capital efficiency of approximately $16,000/boe/d
• Current differentials provide average operating netback of $56.34/boe
250
boe per day
200
IP 30
250 boe/d
IP 90
200 boe/d
NPV BT @ 8%
$3.5 million
On-stream cost
~$2 million
Payout
12 months
Recycle ratio (12 month)
Estimated ultimate recovery
150
3.9x
175 mboe
Profit to investment ratio
2.75x
Average working interest
98%
API gravity
100
IRR
28 degrees
137%
50
0
1
2
3
4
5
6
7
8
9
10
11
12 13 14
Time (Months)
15
16
17
18
19
20
21
22
23
24
Recent horizontal Montney oil wells using 25-stage, cemented liner completions (28 wells – Q4 2012, Q1 2013)
Historical Montney oil type curve
LONG RUN EXPLORATION
14
EDMONTON CORE AREA
Cherhill & Redwater
• Cherhill & Redwater
produce a combined
6,800 boe/d (82% oil)
• Primary targets are Viking
/ Mannville and
Mississippian oil horizons
• Significant infrastructure
in-place
Edmonton
• Land position of 80,000
net acres
Viking Shoreface
LONG RUN EXPLORATION
15
VIKING - REDWATER
Significant Development Inventory
•
Current production ~4,500 boe/d
(90% oil)
•
Viking oil horizontal
multi-frac / multilateral play
•
38° API oil
•
40,000 net acres (62 sections)
of horizontally undeveloped
land
•
Up to 32 wells per section
•
68 wells planned in 2013
•
Currently employing revised
completion technique
LONG RUN EXPLORATION
16
REDWATER FACILITIES
Redwater North
Compressor Station
•
2-2.5 MMcf/d
Redwater North
Oil Battery
•
•
3,000 bopd
2.0 MMcf/d
Bruderheim North
Oil Battery
•
•
2,000 bopd
500 Mcf/d
Bruderheim South
Oil Battery
•
•
1,200 bopd
2.0 MMcf/d
LONG RUN EXPLORATION
17
REDWATER
Type Curve Economics
80
• 12-month capital efficiency of approximately $29,000/boe/d
• Average operating netback of approximately $63.48/boe
70
IP 30
65 boe/d
IP 90
50 boe/d
NPV BT @ 8%
$1.0 million
On-stream cost
$1.2 million
60
Payout
Recycle ratio (12 month)
boe per day
50
Estimated ultimate recovery
40
18 months
2.1x
40 mboe
Profit to investment ratio
1.8x
Average working interest
90%
API gravity
30
38 degrees
IRR
54%
19
20
20
10
0
1
2
3
4
5
6
7
8
9
10
11
12
13
Time (Months)
14
15
16
17
18
21
22
23
Recent horizontal Viking oil wells (41 wells – Q4 2012, Q1 2013)
Historical Viking oil type curve
LONG RUN EXPLORATION
18
BUSINESS PLAN
• Focus on operational efficiency and ingenuity
• Maximize ‘bang for the buck’ with targeted capital spending
• Maintain a reasonable balance sheet
• Provide growth through development of tight oil and natural gas, strategic
acquisitions and enhanced oil recovery
• Create a strong, balanced, mid-cap oil and natural gas exploration company
LONG RUN EXPLORATION
19
CORPORATE INFORMATION
TSX:LRE
Contacts
Bill Andrew
Chair and CEO
(403) 261-6012
Dale Miller
President
(403) 261-6012
Jason Fleury
Vice President, Capital Markets
(403) 261-8302
Main:
Toll-Free Investor Line:
Email:
Web:
LONG RUN EXPLORATION
403-261-6012
1-888-598-1330
[email protected]
www.longrunexploration.com
Corporate Office
Long Run Exploration Ltd.
Livingston Place, West Tower
Suite 400, 250 – 2nd Street SW
Calgary, AB T2P 0C1
20
ADVISORY
Forward Looking Statements
Certain information herein may constitute forward-looking statements under applicable securities laws. Forward-looking statements herein include
management's go-forward business strategy, management's assessment of future plans and operations, drilling plans and the number of wells to be drilled
in 2012, type curves for various plays and the performance of wells to be drilled based on such type curves, 2012/2013 capital budget and expenditures
and the allocation thereof, 2012/2013 funds flow, 2012/2013 average production and production growth, anticipated commodity mix for 2012/2013. Plans
to build facilities and timing thereof, estimated well and on stream costs of wells, plans to use secondary recovery methods including waterflood and infill
drilling to increase recovery from Long Run’s Montney resource and pro forma information about the company. Forward-looking statements necessarily
involve risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain
drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not
performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and
external sources and other risks identified in Long Run's annual information form date March 2012 and available for review under Long Run's SEDAR profile
at www.sedar.com. Forward-looking statements or information are based on a number of factors and assumptions as stated herein which have been used
to develop such statements and information but which may prove to be incorrect. Although Long Run believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Corporation
can give no assurance that such expectations will prove to be correct. The forward-looking statements contained herein are made as at the date hereof
and Long Run does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new
information, events or otherwise, except as may be required by applicable securities laws.
Included herein is an estimate of Long Run's 2013 funds flow related thereto which is based on the various assumptions as to production levels, commodity
prices and exchange rates and that drilling and service costs for 2013 will be similar to the 2012 cost level and other assumptions stated herein. To the
extent such estimate constitutes future oriented financial information or a financial outlook, they were approved by management of Long Run on May 22,
2012, and such future oriented financial information or financial outlook is included herein to provide readers with an understanding of Long Run's
anticipated funds flow and Long Run's ability to fund its expenditures based on the assumptions described and estimated herein. Readers are cautioned
that the information may not be appropriate for other purposes.
Netbacks are calculated by subtracting royalties, transportation costs and operating costs from revenues. Disclosure provided herein in respect of barrels
of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on
the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis
may be misleading as an indication of value.
Type curves presented herein are not necessarily reflective of the performance of future wells.
LONG RUN EXPLORATION
21
ADVISORY
Forward Looking Statements
The Resource Assessment mentioned was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the "COGE
Handbook") and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
The following definitions from NI-51-101 and COGE Handbook are used in this presentation:
“Production” means the cumulative quantity of petroleum that has been recovered at a given date.
"Discovered Oil Initially in Place – DOIIP and DPIIP referred to herein is based on the Resource Assessment effective December 31, 2012 prepared by Sproule. DPIIP means the quantity of
petroleum that is estimated, at a given date, to be contained in known accumulations prior to production. The recoverable portion of petroleum-initially-in-place includes cumulative
production, reserves and contingent resources; the remainder is categorized as unrecoverable. The 301.2 Mmbbl (best case) DOIIP referred to in this presentation, includes 13.6 Mmbbl of
proved plus probable reserves as evaluated in the independent reserve evaluation prepared by Sproule effective December 31, 2012 and 1.9 MMBBL of cumulative production to December 31,
2012. All estimates of DPIIP and DOIIP, including reserves and production, represent gross resources, meaning the company's working interest share in the resources before deducting royalties
and without including any royalty interest of the company. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely
that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual
quantities recovered will equal or exceed the estimate. In the case of reserves, the best estimate is proved plus probable reserves. The DPIIP and DOIIP estimates include unrecoverable
volumes and are not an estimate of the volume of the substance that will ultimately be recovered. For low, best and high estimates of the DPIIP and DOIPP, further definitions related thereto,
positive and negative factors relating to the DPIIP and DOIIP and risk factors relating thereto, please refer to the presentation of the Corporation dated July 2, 2013. There is no certainty that
it will be commercially viable to produce any portion of the resources.
BOES – Disclosure provided herein in respect of barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1Bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of
crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1; utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Reserve Disclosure – The estimates for reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
Reserves are further classified according to the level of certainty associated with the estimates as follows: 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. 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. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed
the sum of the estimated proved plus probable plus possible reserves. "Unrecoverable" is that portion of DPIIP quantities which is estimated, as of a given date, not to be recoverable by future
development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion
may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. All estimates of DPIIP, including reserves and production,
represent gross resources, meaning the company's working interest share in the resources before deducting royalties and without including any royalty interests of the Company. DPIIP estimates
were determined using probabilistic methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic
sums shown in the table. Uncertainty ranges are described in the COGE Handbook as, low, best and high as for reserves and resources as follows: Low estimate is considered to be a
conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at
the low end of the estimate range have the highest degree of certainty - a 90 percent confidence level - that the actual quantities recovered will equal or exceed the estimate. In the case of
reserves, the low estimate is proved reserves. Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50 percent confidence level that the actual
quantities recovered will equal or exceed the estimate. In the case of reserves, the best estimate is proved plus probable reserves. High estimate is considered to be an optimistic estimate of
the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the
high end of the estimate range have a lower degree of certainty - a 10 percent confidence level - that the actual quantities recovered will equal or exceed the estimate. In the case of reserves,
the high estimate is proved plus probable plus possible reserves. The Discovered Petroleum-Initially-In-Place estimates include unrecoverable volumes and are not an estimate of the volume of
the substances that will ultimately be recovered.
LONG RUN EXPLORATION
22

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