2015 Corporate Presentation

2015 Corporate Presentation
May 2015
Corporate Profile
• Stock Symbol – TSX
• Shares Outstanding (2015/04/30)
 Basic
 Diluted (Avg. exercise price $1.27)
CDH
88,621,966
92,106,132
• Q1 2015 Average production rate
1,156 boepd
• Q1 2015 Positive working capital
$ 27.9 MM
• Q1 2015 Operating cash flow
• Q1 2015 Corporate Netback ($/boe)
• Net Asset Value* (per basic share)
 Reserves @P+P BT10% (2014/12/31)
 Working Capital (@ 2015/03/31)
Total
*
$ 7.6 MM
$73.13
$1.27
$0.31
$1.59
Excludes undeveloped land value
2
Land and Reserves
• Undeveloped Land (net acres)
778,000
New Brunswick
Anticosti - Quebec
 Old Harry - Quebec & NL
195,000
332,000
251,000


• December 31, 2014 Reserves (GLJ)
 Proved Developed Producing
 Total Proved
 Total Proved plus Probable
MM BOE
3.6
7.7
11.2
PV@BT10%
($mm)
$58.2
$69.2
$112.9
• Decline Rate
 Proved
 Proved + Probable
13.3%/yr
11.7%/yr
• RLI
 Proved
 Proved + Probable
17 years
25 years
3
2015 Guidance
• 2015 Production Capacity(1)
1,125 boepd
• 2015 Cash Flow from Operations
$8.7 MM
• 2015 Corporate netback ($/boe)
$35.15
• 2015 Capital Expenditures
 McCully
 Old Harry
 Anticosti* (carried)
 Corporate
 Total
$0.4
$1.8
$0
$0.2
$2.4
MM
MM
MM
MM
MM
• 2015 Year End Working Capital
$27.2 MM
* Anticosti Hydrocarbons LP
 2015 Capital Program (Gross)
~$13 MM
(1) Reflects corporate production capacity, 2015 production budget is 680 boepd as Corridor has elected to shut-in certain wells for a
period from May 1, 2015 to October 31, 2015 as set forth in a press release dated May 1, 2015.
4
Board of Directors
• J. Douglas Foster, LL.B., Chairman


President of Fostco Holdings (private investments)
Former Partner Bennett Jones LLP
• Phill Knoll


President of Knoll Energy Inc. (a private consulting company)
Former CEO, Corridor Resources from 2010 to 2015
• Norm Miller

Former CEO Corridor Resources from 1995 to 2010
• Robert Penner, C.A.


Independent Consultant
Prior thereto, Senior Tax Partner with KPMG LLP
• Mike Seth


Independent Consultant
Prior therero, President and Managing Director, McDaniel and Associates
• James McKee


Senior Vice President, Corporate Development, Trican Well Service Ltd.
Formerly Managing Director, Investment Banking of RBC Dominion Securities
• Martin Fräss-Ehrfeld

Chairman of AVE Capital Limited, provider of advisory services to the Children's Investment Fund (UK) LLP
• Steve Moran


President and CEO, Corridor Resources
Formerly President and CEO of Bellamont Exploration Ltd.
5
Three World Class Prospects
Focused on de-risking three high-impact prospects with tremendous upside
potential while demonstrating prudent financial management
Old Harry
Anticosti
•
Liquids-Rich
Shale
•
31 bboe
gross 6.7
bboe net
undiscovered
resources
•
Up to $100
MM program
funded by
third parties
Corridor has
21.67% in
Anticosti
Hydrocarbon
L.P.
One of the
largest
Canadian East
Coast
offshore
geological
structures
•
43,000 Acre
potential oil
prospect
Anticosti (Quebec)
330,000 Net Acres
Old Harry
251,000
Net Acres
(Sproule best
estimate*)
•
•
New Brunswick
195,000 Net Acres
New
Brunswick
•
•
Frederick Brook
Shale
67 TCF gross
discovered
unrecoverable
resources of
shale gas
(GLJ best estimate*)
* See Disclaimer and forward looking statement
6
Anticosti Island
Liquids-Rich Macasty Shale
• Stratigraphic equivalent to Ohio
Utica shale
• 30.7 bboe gross undiscovered
resources (6.65 bboe net)
(Sproule best estimate*)
• Over 1.5 million gross acres
licensed (~ 0.3 million net acres)
• Anticosti Hydrocarbon L.P.
 Corridor - 21.67%
 Corridor carried for up to $100
MM (gross) in exploration costs
 Quebec Government is a
partner – contributing up to
$55.0 MM to project
* See Disclaimer and forward looking statements
7
Anticosti Macasty versus
Ohio Utica shale
• Anticosti Island is large enough to cover the
productive Utica shale trend.
Utica Shale Liquids Trend with
Overlay of Anticosti Island
• Similar to Ohio, Anticosti is in thermal window
for oil, liquid rich gas and dry gas
• Oil window is < 1.1 Ro, liquid-rich gas is
between 1.1 and 1.4 and dry gas is > 1.4
• Pay thickness, total organic carbon, and clay
content are similar in Anticosti and Ohio
• Both contain light oil and NGL’s
• Current production from Ohio Horizontal Wells*:



748 producing wells
1.6 Bcf/d
35,540 bbls/d of oil
* Ohio Dept. of Natural Resources Q4, 2014
8
Anticosti Hydrocarbon L.P.
Capital Program Highlights
• Corridor’s cost is carried for
15 stratigraphic coreholes
and up to 3 horizontal wells
with multi-staged fracture
completions
• During 2014, 5 stratigraphic
coreholes drilled. Results
encouraging
• 10 additional coreholes
planned for 2015
• 3 horizontal wells planned
to be drilled and fracture
stimulated in 2016
9
Anticosti Coring Results to Date
• Eight core intersections of the Macasty have
been completed since 2012
Macasty Core from
Chicotte Corehole
• Mature source rock with residual Total Organic
Carbon (TOC) levels which, on a qualitative
scale, are ranked as very good to excellent
• Hydrocarbon concentrations in the rock (S1)
which, on a qualitative scale, are ranked as
very good
• Porosity that is within an expected range
• Permeability values that indicate the probability
of producing hydrocarbons based on
comparisons with similar source rocks in
productive shales
10
New Brunswick Assets
• Approximately 195,000 net acres
• McCully Natural gas production:

productive capacity of 9 mmcf/d
gross (6.5 mmcf/d net)
• Hiram Brook produces from
conventional tight sandstone
reservoirs
• Frederick Brook has substantial
unconventional shale resource
potential:
Black, hydrocarbon rich shale that is
up to 1100 m thick
 67 TCF (59 TCF net) discovered
unrecoverable resources within
assessed area (GLJ best estimate*)

NB
PEI
NS
* See Disclaimer and forward looking statements
11
Corridor’s New Brunswick
Facilities at McCully
• Natural Gas Facilities (100% WI)
include:

Gas Plant - processing capacity
of 35 mmcf/d

50 km of 8” transmission line to
M&NP

Gathering system (15 km of
pipe)

32 producing wells from 11
well pads
NB
PEI
NS
12
Northeast USA
Premium Natural Gas Markets
• Corridor’s production connected
to Maritimes and Northeast
Pipeline (MN&P)
• MN&P connected to premium
Northeast U.S. market
 Corridor
2014 Average NG
Sale Price - $8.59/mcf (CDN)
 Corridor
winter 2014/15
average NG sale price
$13.85/mcf (CDN)
 2500
mmbtu/d hedge in
place for Nov 2015 to March
2016 at US$9.25/mmbtu
• Expect premium winter market
to continue to at least 2018/19
13
Connecting Appalachian Gas
to the Maritimes
• Numerous greenfield
pipelines proposed
• Expect completion by
2018/2019
• M&NP is bi-directional,
will be reversed in time
• Significant tolls on new
Appalachian pipelines will
result in high NG prices
for New Brunswick
• Corridor anticipates a
$3/mmbtu (CDN)
premium to US NE Markets
for New Brunswick natural
gas
14
Long Term East Coast LNG
Market Potential for NB Gas
• Connecting Appalachian gas to
MN&P (est. 2018/19) will open up
LNG export potential on East
Coast of Canada.
• Multiple proposals for East Coast
LNG Export terminal
 Canaport facility (Repsol)
 Bear Head LNG (LNG Ltd.)
 Melford LNG (Hiranandani
Group)
 Goldboro LNG (Pieridae)
• Corridor’s lands are ideally
positioned to supply LNG export
projects
15
Frederick Brook Shale
Resources Estimates
• Resource estimate (67 TCF
gross, GLJ best estimate*)
conducted over wide area
(120,000 acres)
• Up to 600 bcf/section (GLJ
best estimate) due to gross
interval up to 1,100 m thick
• Potential for vertical or
horizontal development
• 13 wells drilled into FB shale
to date
• FB mapped over wide area
– potential for at least 1,400
well locations**
• Depth to top FB ranges from
1,600 to 4,000 m
* See Disclaimer and forward looking statements
** based on vertical wells and 80 acre spacing
16
Frederick Brook Shale
Gas tested over 20 KM extent
• FB shale is widespread and shale
interval is up to 1100 m thick
• 4 producing wells in McCully, 3 of
which came on-stream January, 2015
• 2 Elgin wells flow-tested gas
• 6 wells producing or tested gas
from separate stratigraphic
intervals
17
Frederick Brook Shale
Production History
•
•
•
F-58 production at ~180 mcf/d for
past 7 years (1.65 Bcf 2P EUR)
Very flat production curve with
annual decline ~ 2% annually
New wells have proved productivity
and reserves
All producing FB wells have small
single fracs to date
1000
Monthly Production Rate (mcf/d)
•
F-58 Frederick Brook Daily Production
100
2007 2008 2009 2010 2011 2012 2013 2014 2015
• G-41 in Elgin tested up to 12
mmcf/d
• encountered interbedded
sands with high deliverability
• Potential to occur elsewhere in
field
18
Frederick Brook
Completion Design
•
The 2010 frac program performed in two
Elgin horizontal wells did not appear to
create an effective completion
•
Despite the productive G-41 a few hundred
meters away, tremendous gas shows during
drilling, and much larger completions, the
Apache B-41 fracs were not successful
•
Based on a consensus of third party expert
consultants and Corridor’s technical staff:

The high regional stress profile and well
geometry was not fully considered during
frac design and led to delamination of the
shale or “pancake fractures”

This led to very poor connectivity with the
wellbore

Frac design should be optimized to create
more connected fracture networks taking
regional stress and well orientation into
account
Apache B-41 Well
Upper
Frederick
Brook Shale
Corridor G-41 Well
19
Frederick Brook Comparison to Glacier
Field (Alberta) Montney Producers
• Corridor’s F-58 well shows
comparable IP rates to
average vertical Glacier,
Alberta wells
• Glacier vertical wells decline
rapidly, F-58 decline rates are
very low indicating large
resource in place
• F-58 cumulative production
exceeds average Glacier
vertical well
* See Disclaimer and forward looking statements
20
Frederick Brook Comparison to Glacier
Field (Alberta) Montney Producers
• Technological
advancements over a
number of years in the
Glacier Field have
resulted in increased daily
average gas rates
• Similar technology
advancements in the
Frederick Brook could
result in comparable daily
average gas rates
21
Frederick Brook Shale Development
Potential Next Steps
• Work through government
moratorium for next 12 months
• Look for Joint Venture partner
• Develop next stage of pilot
program







Drill 6-10 regional vertical wells
Complete with high volume water
fracture stimulations
Identify “sweet spots”
Establish production and reserves
Optimize completion techniques
Reduce costs, optimize results
Consider horizontal wells for future
programs
Potential Delineation Wells
Potential Pipeline
22
Old Harry Offshore Potential
•
One of the largest undrilled geological
structures in Eastern Canada* (43,000
acres/67 sq miles) under simple four-way
closure
•
Several direct hydrocarbon indicators
identified: satellite seepage slicks,
frequency anomalies, amplitude
anomalies, and AVO anomalies
•
Over 1,000 km of modern 2-D seismic
•
Basin Modeling indicates light oil (~55
API) was initially generated and could
be filling the structure
*
* Hibernia producing area outline shown for illustrative purposes only. Canada Newfoundland Offshore Petroleum Board (1996) estimates Hibernia’s original-oil-in-place at 1.39 billion
barrels. As Corridor understands, this estimate of “original-oil-in-place” is equivalent to “discovered resources”. This disclosure is for illustrative purposes only and does not
constitute an evaluation of resources under National Instrument 51-101 – Standard of Disclosure for Oil and Gas Activities. See “Resources Disclaimer”
23
Controlled Source ElectroMagnetic (CSEM) Survey
• Corridor is purchasing a multi-client CSEM survey
on the west coast of Newfoundland (Est. $1.8mm)
• Recording instruments are placed on the sea
bottom and an electro-magnetic (EM) source is
towed behind a vessel (see right).
• Signals from the EM source travel through the
rock formations to the receivers. Anomalously
resistive layers (hydrocarbons) will stand-out
against a non-resistive background (see figure
upper right).
CSEM Survey:
Newfoundland Side of Old Harry
• Modelling shows Old Harry to be an ideal
candidate for CSEM imaging.
• A positive CSEM anomaly in a sand/shale
sequence provides confidence of hydrocarbon
bearing sands.
• Survey time 5-10 days, plus mob/demob time.
Survey expected to be acquired in the fall 2015.
24
Old Harry Go Forward Plan
• In the market for a JV partner to drill an
exploratory well (estimated $US55 MM)
• Corridor intends to use CSEM technology
to confirm hydrocarbons
• Regulator published Strategic
Environmental Assessment in May 2014
and it concludes that exploration and
development activities can be safely
undertaken
• Quebec Gov’t supports exploration of Old
Harry prospect pending completion of
impact studies and negotiations with
Federal Gov’t in 2015
• Quebec and Canada are proceeding with
a joint offshore accord to allow
exploration and development
25
Strategic Priorities
Corridor has sustainability combined with tremendous upside potential:
• Maximize cash flow and value of McCully assets
• Optimize strong pricing for gas production in Northeast U.S. market
• Emphasize Corridor’s strategic location advantage for LNG export facilities
• Influence progress on Anticosti Hydrocarbons L.P. coring program in
Summer/Fall 2015 and 3 horizontal well tests in 2016
• Seek opportunities for joint ventures for Old Harry and the Frederick Brook
Shale
• Continue to advance government and stakeholder relations, social
responsibility and regulatory agendas
• Take advantage of Corridor’s balance sheet strength and add new growth
projects to our inventory
26
Disclaimer
Forward Looking Information Disclosure
•
•
•
This presentation contains certain forward-looking statements and forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of
Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking information typically contains statements with words
such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should", or similar words suggesting future outcomes. In particular, this presentation
contains forward-looking statements pertaining to the following: the potential and characteristics of Corridor's properties; Corridor's and Anticosti Hydrocarbon L.P.’s business plans and
strategies, including strategic priorities; potential for LNG export; pipeline projects and capacity; natural gas production; potential regional supply basins; prices (including premiums) of
natural gas; reserves and resources; support and treatment under governmental regulatory regimes; and exploration and development plans.
Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown
risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur.
There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will in fact be realized. Actual results will differ, and the difference
may be material and adverse to Corridor and its shareholders. Forward-looking statements are based on Corridor’s current beliefs, including the agreements governing the Anticosti
Hydrocarbon L.P. as well as assumptions made by, and information currently available to Corridor, including information concerning anticipated financial performance, business prospects,
strategies, regulatory developments, future natural gas and oil commodity prices, exchange rates, future natural gas production levels, the ability to obtain equipment in a timely manner
to carry out development activities, the ability to market natural gas successfully to current and new customers, the impact of increasing competition, the ability to obtain financing on
acceptable terms, the ability to add production and reserves through development and exploration activities and the terms of agreements with third parties. Although management
considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. Unknown risks and uncertainties include, but are not limited
to: risks associated with oil and gas exploration, substantial capital requirements and financing, prices, markets and marketing, government regulation, third party risk, environmental,
hydraulic fracturing, dependence on key personnel, co-existence with mining operations, availability of drilling equipment and access, risks may not be insurable, variations in exchange
rates, expiration of licenses and leases, reserves and resources estimates, development and/or acquisition of oil and natural gas properties, trading of common shares, seasonality,
competition, management of growth, conflicts of interest, issuance of debt, title to properties and hedging. Further information regarding these factors and additional factors may be
found under the heading "Risk Factors" in the Annual Information Form for the year ended December 31, 2014. Readers are cautioned that the foregoing list of factors that may affect
future results is not exhaustive.
The forward-looking statements contained in this presentation are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of
the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
Oil and Gas Disclosure
•
The term "boe" refers to barrels of oil equivalent. All calculations converting natural gas to crude oil equivalent have been made using a ratio of six mscf of natural gas to one barrel of
crude equivalent. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of six mscf of natural gas to one barrel of crude oil equivalent is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
27
Disclaimer
(cont’d)
Resources Disclosure
•
•
•
•
"discovered resources" is equivalent to “discovered petroleum initially-in-place, and refers to that quantity of petroleum that is estimated, as of a given date, to be contained in known
accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves, and contingent resources; the remainder is
unrecoverable.
"undiscovered resources" refers to those quantities of petroleum that are estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of
undiscovered petroleum initially-in-place is referred to as prospective resources, the remainder as unrecoverable. Undiscovered resources carry discovery risk. There is no certainty that
any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot
be defined for this volume of undiscovered petroleum initially-in-place at this time.
"discovered unrecoverable petroleum initially-in-place", the equivalent of "discovered unrecoverable resources", refers to that portion of discovered petroleum initially-in-place 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;
Resources do not constitute, and should not be confused with, reserves. Actual reserves and resources will vary from the reserve and resource estimates, and those variations could be
material. There is no certainty that it will be economically viable to produce any portion of the resources.
• The resources assessment referred to in Slides #6, #11 & #16 was completed by GLJ Petroleum Consultants Ltd. effective June 1, 2009, as modified on March 25, 2014, setting forth
certain information regarding discovered unrecoverable resources of Corridor's interests in the Frederick Brook shale formation. The best estimate is the value that best represents
the expected outcome with no optimism or conservatism. There is no certainty that it will be commercially viable to produce any portion of these discovered resources.
• The reserves estimates referred to in Slides #2 & #3 was prepared by GLJ dated February 18, 2015 with an effective date of December 31, 2014 setting forth certain information
relating to certain natural gas, crude oil and natural gas liquids reserves of Corridor properties, specifically the McCully Field and the Caledonia Field, and the net present value of the
estimated future net reserves associated with such reserves.
• The resources assessment referred to in Slides #6 and #7 was prepared by Sproule Associates Limited effective June 1, 2011, as modified November 19, 2013 and updated effective
as of April 30, 2015 setting forth certain information regarding total petroleum initially-in-place of the Macasty shale formation on Anticosti Island. The best estimate reflects the
probability that the quantity actually in place is equal to or greater than the estimate is 50%. These resources are reported as Bboe to reflect uncertainty of hydrocarbon type across
the island. A recovery project cannot be defined for this volume or undiscovered resources. There is no certainty that any portion of these resources will be discovered.
If discovered, there is no certainty that it will be commercially viable to produce any of these resources.
• For further information on Corridor's resources and reserves, see the Annual Information Form for the year ended December 31, 2014.
28