Sneaking a peek – initiating coverage on private

Transcription

February 18, 2014
Grant Daunheimer, CFA
[email protected]
403-543-3039
Stacey McDonald
[email protected]
403-543-3042
Aaron Swanson, CFA
[email protected]
403-543-3563
David Beddis, CFA
[email protected]
403-543-3588
R. Jason Konzuk, CA, CFA
[email protected]
403-543-3587
Sneaking a peek – initiating coverage on private E&Ps
Eleven private energy companies worth looking at
Private Canadian energy companies map
Within this report we are introducing eleven private oil and gas
Beaumont Energy Inc.
Broadview Energy Ltd.
companies that we believe have established top-tier asset
Caltex Resources Ltd.
bases, contain a strong financial structure and are led by highCarmel Bay Exploration Ltd.
quality management teams. The point of this report is to provide
New Star Energy Ltd.
investors with a sense of who is running the companies, what
Petrus Resources Ltd.
Seven Generations
the go-forward plans may include and to give some key financial
Spur Resources Ltd.
and operating takeaways. Going forward, our intention is to
T eine Energy Ltd.
provide respective company updates on an as-needed basis.
Venturion Oil Ltd.
Verano Energy Ltd. – Llanos Basin, Columbia
A flavour for everyone: Respective production volumes and
asset bases of the included companies vary widely. We have
included companies in their growth stages (Verano Energy), all
the way up to more established companies producing over
30,000 boe/d (Seven Generations). Asset bases are equally
diversified with companies having interests in Colombia, SAGD
heavy oil, conventional and unconventional domestic oil and
gas. Operating areas of the respective companies can be found
in the maps on the left.
Themes discovered along the way: Described in more detail
on the following page, a number of themes were uncovered
while working on this report, namely: 1) it takes a lot of money to
get going – you need to be able to attract capital, 2) many of the
private companies fit into the “growth” category, and 3) have
strong management teams with a history of value creation at
both public and private energy companies.
A word of caution: Given the private nature of the companies in
the report, disclosure levels and share pricing methodologies
vary widely. For these and other reasons, GMP does not
maintain price targets and ratings on private companies. In this
report, GMP provides financial forecasts that may differ from
management’s forecasts. For reference, the GMP commodity
price forecast can be seen in the table on page 4.
Private companies included
Company
Broadview Energy Ltd.
Carmel Bay Exploration Ltd.
Seven Generations Ltd.
Spur Resources Ltd.
Teine Energy Ltd.
Venturion Oil Ltd.
Verano Energy Ltd.
Analyst
SM
JK
GD
SM
SM
AS
SM
AS
AS
GD
DB
Production (2014E)
4,000
908
3,350
n/a
5,000
4,910
35,000
7,663
15,000
2,100
3,200
Source: Company reports, GMP Securities
Prepared by GMP Securities L.P.
See important disclosures on the last page of this report
Description
Large OOIP Kerrobert Viking pool
Value underpinned by cold flow while thermal provides upside
Engineering focus on heavy oil with material resource potential
Over 60,000 acres between the Nig, Jedney and Mica area in northeastern BC
High quality Highvale oil pool with visibility for growth
High impact Cardium oil complemented by early stage Montney oil development
World Class Kakwa River Montney Project
Well funded, resource rich junior growth company
Largest landowner and producer in the Dodsland Viking play
Conventional reservoirs with recovery factor upside
Fully funded Colombian junior with production and high-impact exploration
February 18, 2014
TABLE OF CONTENTS
Report overview and themes
3
Report assumption details
4
Beaumont Energy Inc.: Experienced team with large repeatable Kerrobert Viking asset
5
Broadview Energy Ltd.: Out in front of the pack
7
Caltex Resources Ltd.: Worked so well they are doing it again
9
Carmel Bay Exploration Ltd.: Carmel Bay led by successful team behind Monterey Exploration 11
New Star Energy Ltd.: High-quality oil pool with visibility for growth
13
Petrus Resources Ltd: Diversified asset base with oil upside
15
Seven Generations Ltd.: World-class Kakwa River Montney project
17
Spur Resources Ltd.: Earning their spurs
19
Teine Energy Ltd.: Amassing a fortune in Dodsland
21
Venturion Oil Ltd.: Not their first rodeo
23
Verano Energy Ltd.: Colombian Private primarily focused in the Llanos Basin
25
February 18, 2014
REPORT OVERVIEW
This report highlights our forecasts and key takeaways for ten domestic private energy companies and one
Calgary-based international private company. Within our two-page write up on each company you will find a
brief management and company history, asset details, go-forward plans, operational highlights, and
potential next steps. As previously mentioned, the report encompasses a wide range of companies with
estimated market capitalizations ranging from $49 million to over $2 billion and average 2014 forecast
production from 900 boe/d to 35,000 boe/d. Although the focus appears to be on oil weighted production, we
do present a number of companies with balanced production bases offering material upside to natural gas.
Details can be seen in the table below.
GMP forecast 2014E production and liquids weighting
2014E Production (boe/d)
85%
Oil Weighting (%)
Broadview
Venturion
Verano
Caltex
40%
Beaumont
0
Petrus
55%
New Star
3,000
Spur
70%
Teine
6,000
Liquids Weighting (%)
35,000
9,000
100%
Seven
Generations
2014E Production (boe/d)
12,000
Source: Company reports, GMP Securities
THEMES
Apart from operating out of the public’s watchful eye, generally speaking, the private companies found in
this report operate in a very similar manner to their public counterparts. The companies presented in this
report exhibit a number of common characteristics, namely, 1) have established asset bases with drilling
and inventory upside, 2) strong management teams with a history of value creation at both public and
private energy companies, 3) strong balance sheets with the ability to attract capital.
The following graph highlights the capital raised by each respective company. With horizontal wells, multifrac technology, and larger land bases with material drilling inventories often a requirement, raising capital to
start a private company is no small feat.
February 18, 2014
Total equity capital raised
$801
$357
Teine
$200
Seven
Generations
Total Capital Raised ($mm)
$240
$160
$120
$80
$40
Broadview
Caltex
Venturion
Spur
New Star
Beaumont
Petrus
Verano
$0
Source: GMP Securities
The companies in this report are all well financed with either cash in the bank or minimal debt. This counters
many of our publicly traded companies that rely more heavily on bank debt to operate. With access to
capital potentially more challenging in the private arena, having ample capital appears to us to be a good
strategy. That being said, many of the companies have large private equity partners with deep pockets,
enabling continued acquisitions or expansions to their field operations.
Each respective private company has a different strategy and asset focus. Companies in this report range in
strategy from targeting large unconventional resources, SAGD projects, legacy conventional oil pools that
will never receive a horizontal well, and international growth stories.
REPORT ASSUMPTION DETAILS
Please note that all of our private companies in this report are priced based on either information provided
by the company, the most recent equity raise, the last over-the-counter (OTC) market price or the last price
as indicated from our trading desk. If pricing is listed as “N/A” this is due to dated or a lack of pricing
information. In this report, GMP provides financial forecasts that may differ from management’s forecasts.
Our financial forecasts are reported in Canadian dollars and are based on available company information,
GeoSCOUT data, and our commodity price assumptions (outlined below). Many of the stocks included in
this report trade actively on the OTC market but some listed have limited liquidity. None of the companies
included in the report are reporting issuers. Due to this, we have not included target or recommendations for
any of the companies.
GMP commodity forecasts
WTI (US$/b)
Brent (US$/b)
Edm. Par (C$/b)
WCS (C$/b)
Henry Hub (US$/mmbtu)
Alberta Spot (C$/mcf)
FX Rate (US$/C$)
Source: GMP Securities
2014E
$95.00
$107.50
$91.08
$78.78
$4.12
$3.68
$0.95
2015E
$90.00
$102.50
$87.37
$77.89
$4.25
$3.68
$0.95
Stacey McDonald
[email protected]
403-543-3042
Associate: Holly Smart
[email protected]
403-695-1403
February 18, 2014
Private Company Research
SHARE DATA
Shares o/s (mm, basic/f.d)
Share Price ($/share)
Market Capitalization (f.d. mm)
Net Debt ($mm) - 2013E
Dilutive Proceeds
Enterprise Value ($mm)
PRODUCTION DATA
Oil and NGLs (b/d)
Natural Gas (mmcf/d)
Total (boe/d) 6:1
Equivalent growth
68.0 / 91.6
$4.75
$435.1
$29.7
$77.4
$387
2013E
1,632
0.4
1,700
154%
2014E
3,840
1.0
4,000
135%
2015E
5,088
1.3
5,300
33%
2013E
$91.43
($1.83)
($25.50)
$64.10
($4.34)
$59.76
$55.41
$34.5
$0.38
$80.9
$29.7
0.9x
2014E
$88.08
($1.76)
($21.00)
$65.32
($0.80)
$64.52
$60.05
$87.7
$0.96
$97.0
$39.0
0.4x
2015E
$84.37
($1.69)
($20.00)
$62.68
$0.00
$62.68
$58.39
$113.0
$1.23
$100.0
$26.0
0.2x
VALUATION
2013E
P/CF
12.6x
EV/DACF
11.3x
EV/boe/d
$227,841
EV/2P reserves (Aug 31, 2013)
2014E
5.0x
4.5x
$96,833
2015E
3.9x
3.5x
$73,081
$23.91
FINANCIAL DATA
Revenue ($/boe)
Net Royalties ($/boe)
Operating ($/boe)
Field Netback ($/boe)
Hedging ($/boe)
Operating Netback ($/boe)
Corporate Netback ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
MANAGEMENT TEAM & DIRECTORS
Bob Chaisson
President & CEO, Board of Directors
Boyd MacDonald
COO
Ken McNeill
Executive VP Corporate Development
Shane Helwer
VP Finance & CFO
Frank Madadi
VP Exploration
Ron Davidson
VP Engineering
Jeff Johnston
VP Operations
Ted Hanlon
Board of Directors
Howard Crone
Board of Directors
Daryl Gilbert
Board of Directors
Richard Lewanski
Board of Directors
James (Pep) Lough
Board of Directors
Jim Nieuwenburg
Board of Directors
INSIDER OWNERSHIP FD (%)
33%
EQUITY FINANCING HISTORY (2012-CURRENT)
DATE
OFFERING SHARES (mm)
PRICE
2012-2013
CS
68.0
$2.00
TOTAL EQUITY RAISED
68.0
$2.00
TOTAL ($mm)
$135.9
$135.9
** Last trade price – $4.75 in Jan 2014
Last: $4.75**
Experienced team with large repeatable
Kerrobert Viking asset
Beaumont Energy was formed in December 2012 and is run by Bob Chaisson. Mr.
Chaisson was previously the President & CEO of Cutpick Energy. The
management team is largely the same team that successfully grew and sold
Cutpick Energy. The Beaumont Board of Directors includes many recognizable
names such as: Ted Hanlon, Howard Crone, Daryl Gilbert, Richard Lewanski,
James Lough, and Jim Nieuwenburg.
Growing production through infill drilling and waterflooding
Beaumont’s current asset base consists of one large OOIP Viking oil pool in
Kerrobert, Saskatchewan. In December 2012, Beaumont paid $110 million for its
Kerrobert property, after which it raised $136 million at $2.00/share to fund
acquisitions and for drilling. Since then, it has grown production to 3,500 boe/d,
from 668 boe/d. This is impressive production growth in a short period of time. The
Kerrobert property currently has a recovery factor of 3% (produced) compared to
analogous waterfloods that range from 15–25%. Beaumont’s strategy is to use its
experienced team to grow production and increase its recovery factor to a range of
20%–25% through the use of repeatable infill horizontal drilling and waterflood
schemes. We believe this strategy has worked well to date as the company has
significantly increased corporate production in a short period of time.
Kerrobert Viking pool has an estimated 600 mmb of OOIP
Beaumont has 74.3 (70.4 net) sections of Viking land in the Kerrobert oil pool and
management estimates 600 mmb of OOIP, of which 20% or 120 mmb (as a
minimum) could be ultimately recoverable. Current recovery factor for the pool sits
at ~3%, which was largely achieved through the use of vertical drilling (previous
owners). Based on the most recent reserve report (August 31, 2103), Sproule has
only assigned estimated recoverable reserves of ~5% (32.4 mmb). This leaves a
very large prize yet to be recovered of close to 100 mmb (under 20% RF scenario)
and should keep the company active for many years to come. Management has
identified a total inventory of 1,050 wells, of which 500 would be production wells
and 550 would be injection wells.
Keep growing or perfect asset for a dividend
Beaumont has been very successful in growing production quickly from the
Kerrobert asset. Beaumont’s land is in the heart of the pool with extensive vertical
production, and other operators have drilled on the halo of the pool with success.
Based on the vertical well control and horizontal success to date we see almost
zero geological risk. We believe that Beaumont has a large inventory of repeatable
drilling prospects with additional upside with waterflooding. Ultimately, we believe
the company will have the luxury of multiple “exit” strategies as the asset is suited
to continue growing supported by 500 drilling locations, using FCF for a dividend,
or the asset is suited to be rolled into a public yield–orientated E&P.
February 18, 2014
KERROBERT POOL IS LOW RISK; PLAY IN FULL MANUFACTURING MODE
Land position
Drilling results tracking ahead of type curves
The current company type curve calls for an IP30 of ~63 b/d and
an EUR 45 mb, which drives a NPV10 of $1.3 million and a ROR
of 115%. As shown in the graph on bottom left, the actual results
to date have significantly exceeded the current company type
curve with IP30 rates of ~80 b/d and production profiles tracking
closer to the Tier 7 or 8 curves used by Sproule. Based on the
success to date, we believe that the Viking wells should see
even quicker payouts and also see increased reserve bookings.
Should be self-funding in H2 2014
Corporate production
Beaumont is planning to drill 80 horizontal wells in 2014, which is
up from 65 horizontals in 2013. Management has budgeted to
spend $97 mm in 2014, should grow average production from
1,700 boe/d in 2013 to ~4,000 boe/d in 2014 and exit at over
5,000 boe/d. This equates to 13/14 average production growth of
135%, which we believe would be top decile growth compared to
private and public companies of its size. Driven by the strong
economics of the Viking play, we are forecasting that Beaumont
will generate $87 million in cash flow, which is close to the $97
million of the planned capital program. In fact, based on the 2014
spending and production profile, we believe that Beaumont will
begin generating free cash flow in the fourth quarter of 2014 and
this attribute places the company among a small group of private
and public E&Ps.
Waterflood provides additional low-risk upside
Kerrobert type curve
Source: Company reports
Of the 80 wells planned for 2014, 20 will be drilled inside of the
waterflood project area, with ~20% of its land or 14 sections
under waterflood by the end of the year. The company drilled 4
horizontal wells inside the waterflood inject area last year. To
date, there is only about 6 months of production data but the
wells are tracking above the highest type curve (graph to left).
Beaumont will convert an additional 64 vertical producing wells to
water injectors in Q1/14 and plans to commence Phase 2 water
injection in Q2/14. It’s still early days but the initial results are
encouraging and for 2015 we wouldn’t be surprised to see half
the horizontal drilling wells placed inside of the waterflood project
area. Over the longer term, we believe the waterflood will have
several significant positives on the company: 1) waterflood
horizontals appear to have higher IP rates and shallower
declines, 2) significantly increase RF from the pool from 9%
under primary to an estimated 20–25%, and 3) lower overall
decline rate moving the company towards FCF earlier (Q4/14).
R. Jason Konzuk, C.A., CFA
[email protected]
403-543-3587
Associate: Gabriel Chow
[email protected]
403-543-3035
February 18, 2014
Broadview Energy Ltd.d
SHARE DATA
Shares o/s (mm, basic/f.d.)
Market Capitalization (mm)
Net Debt (mm) 2014E
Dilutive Proceeds
Enterprise value (mm)
37.5/41.7
$2.25
$93.7
($6.9)
$5.0
$86.9
PRODUCTION DATA
Oil and NGLs (b/d)
Total (mboe/d) 6:1
Equivalent growth
2013E
252
0.0
259
1,016%
2014E
827
0.5
908
250%
Reserves (McDaniels - at December 31, 2012)]
Thermal
Conventional
2P (mmboe)
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Hedging ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
VALUATION
P/CF
EV/DACF
EV/boe/d
EV/2P reserves (December 31, 2012)
2015E
1,229
0.6
1,335
47%
26.9
1.0
27.9
2013E
$74.36
$8.52
$12.24
$53.61
$0.00
$53.61
$37.14
$3.51
$0.09
$8.59
($3.0)
nm
2014E
$78.06
$8.28
$10.75
$59.03
$0.00
$59.03
$53.90
$17.87
$0.43
$14.00
($6.9)
nm
2015E
$78.33
$9.26
$12.00
$57.07
$0.00
$57.07
$53.07
$25.86
$0.62
$20.00
($12.7)
nm
2013E
25.6x
25.4x
$344,030
2014E
5.2x
4.9x
$95,612
2015E
3.6x
3.1x
$60,676
$3.11
Dan Polley
President & CEO, Director
Ian Langdon
VP Development, Director
Craig McClelland VP Land, Director
Doug Seams
VP Business Development, Director
Ian Temple
VP Geosciences, Director
John Festival
Director
Bruce Chernoff
Director
Steve Smith
Director
INSIDER OWNERSHIP (%)
58%
EQUITY FINANCING HISTORY
DATE
OFFERING
Mar-10
CS
Jun-10
CS
Nov-10
CS
Jul-11
CEE
Jul-11
CDE
Nov-11
CS
Jul-13
CDE
Jul-13
CS
Dec-13
CEE
Dec-13
CDE
Misc
CS,FT,WRTS
TOTAL EQUITY RAISED
SHARES (mm)
11.2
3.5
11.0
1.3
0.3
6.0
1.4
0.5
0.2
0.4
1.6
37.5
PRICE
$0.25
$0.35
$0.75
$2.50
$2.25
$2.00
$2.43
$2.25
$2.61
$2.43
$1.11
TOTAL ($mm)
$2.80
$1.23
$8.27
$3.13
$0.75
$12.00
$3.47
$1.22
$0.50
$1.00
$1.76
$36.12
** Last equity issue price – $2.25 in Dec 2013
Last: $2.25**
Out in front of the pack
Broadview was founded in March 2010 by the former technical team of Breaker
Energy, which was sold to NAL Oil & Gas Trust in December 2009 and delivered a
32% after-tax CAGR to investors over its five-year life. Broadview is following a
three-pronged oil-focused strategy, pursuing thermal oil development in
Saskatchewan, applying horizontal multi-frac technology in shallow, accessible
heavy to medium gravity oil reservoirs and the exploration and development of
conventional heavy oil. The company has also demonstrated considerable
foresight by building land positions in large oil resource opportunities long before
the play concepts entered mainstream consciousness.
Horizontal multi-frac success to drive near-term production growth
Near-term production growth is expected to be driven by continued appraisal
drilling at Medicine Hat, Alberta following the significant discovery made in 2012,
and development drilling at Wainwright, Alberta following the first successful
horizontal well drilled into the Wainwright Sparky complex during Q3’13.
At Medicine Hat, the company holds ~10,000 acres (16 sections) at 100% working
interests and is targeting 16° API oil in the Cretaceous Glauconitic formation.
Broadview’s discovery well (1-14-11-6 W4, or “1-14”) delivered initial production of
almost 400 bbl/d, and has recovered 62,000 bbls of oil in its first 14 months on
stream. The well cost $2.4 Mm to drill, complete and equip, and we estimate
reached payout in six months. A second horizontal well has been drilled to the
north, which encountered thicker pay than 1-14, and has recently been placed on
production. Broadview has yet to determine the areal extent of the pool.
At Wainwright, Broadview holds ~2,690 acres (4.5 sections) at 100% working
interest targeting an undeveloped medium gravity (23° API) oil pool in the Sparky
formation. Broadview has drilled two wells to date with resounding success, with
initial production (IP30) of 375 bopd from the “discovery” well (16-28) and 25,000
bbls of oil recovered in its first three months. At an all-in cost of $2.2 Mm, we
estimate this well would pay out in just over four months and, assuming an ultimate
recovery of 125,000 bbls, would deliver an NPV of $2.1 Mm. A second horizontal
well (8-28) has just been brought on production. Broadview’s lands at Wainwright
could potentially support an inventory of 11 additional primary locations as well as
infill and waterflood development potential.
Value underpinned by cold flow; thermal provides upside
With Broadview’s shares trading at ~$2.25 in the OTC market, the implied EV for
the company is $87.5 Mm. At this price, we believe the company’s valuation is
more than underpinned by its two visible medium gravity multi-frac oil discoveries,
Medicine Hat and Wainwright. It also appears to us that OTC market activity
reflects little value for Edam, the company’s thermal heavy oil project. We
calculate an NPV of $6.44/share (AT, 10%) alone for just this project. While some
financing risk remains with respect to funding Edam, we believe the discount
currently being reflected by OTC market activity is excessive.
February 18, 2014
GO, RIDERS! SUPERIOR ECONOMICS OF SASKATCHEWAN SAGD PROJECTS WIDELY UNDERAPPRECIATED
Broadview’s operating areas
Edam thermal SAGD project is the real prize
While Broadview’s suite of cold-flow horizontal multi-frac projects
will drive production growth in the near term, the largest driver of
value within the company is Edam, a 5,000 bbl/d thermal heavy
oil project targeting the Lloydminster formation. Broadview has
mapped 55.4 Mmbbls of Exploitable Oil in Place (>10 M pay
thickness), and has booked 2P reserves of 26.9 mmbbls to the
project. The project is anticipated to cost $145 Mm and we
believe has an NPV of ~$250 Mm ($6.44/share). The project has
received EOR and Environmental Protection plan approval from
the Saskatchewan government.
Husky’s SAGD projects
Source: Company Reports, GeoSCOUT, GMP
There are a number of differentiating features of Edam relative to
typical Athabasca region projects that both enhance project
economics while mitigating many of the risks associated with
thermal developments. Firstly, oil quality is superior, as Edam is
expected to produce 11° API heavy oil that is mobile at reservoir
temperatures rather than immobile 8° API bitumen. Superior oil
quality results in both improved recovery but also better pricing.
Secondly, the reservoir consists of a homogeneous shoreface
sand rather than a heterogeneous fluvial system characterized
by many McMurray formation projects. Lastly, jurisdiction
matters. Saskatchewan offers a better fiscal and regulatory
environment compared to Alberta; the latter feature contributes
to significantly lower capital costs relative to Alberta projects.
Nearby projects just recently announced by Husky Energy also
provide validation for Edam, as Husky’s 10,000 bbl/d Edam East
project is a few miles west of Broadview’s project and Husky’s
10,000 bbl/d Vawn project is in the same oil pool and
immediately adjacent to Broadview’s project.
52% percent financed and counting …
Broadview has an innovative financing solution for approximately
half of the capital required for Edam. The fabricator of the
modularized processing plant will cover the costs of designing,
building and commissioning the steam plant and associated
processing equipment on a turnkey basis, eliminating cost risk to
Broadview on more than half of the total project expenditures.
In return, the fabricator will receive 6.5% interest on a declining
balance of its funding contribution commencing after
commissioning and will be repaid by 50% of operating cash flow
until payout, which we expected in 24 months following start-up.
After payout, 100% of the project cash flows will revert back to
the company. Broadview continues to work toward putting in
place financing for the remaining project capital.
[email protected]
403-543-3039
Associate: Graham Smith, CFA
[email protected]
403-543-3032
February 18, 2014
Last: $2.90**
Worked so well they are doing it again
SHARE DATA
Net Debt ($mm) - Q4 2013E
Dilutive Proceeds ($mm)
2013E
2014E
Caltex Resources was created following the sale of Caltex Energy to Crew Energy
in 2011. This is essentially the same team that created material shareholder value
at Caltex Energy (a >6x return). Management is led by Tom Bieschke, who also
sits on the Board of Directors, which includes Dave Ambedian, Peter Williams,
Craig Glick, Brett Wrathall, and Brent Bracken. Three of the four key management
team members have worked together for over ten years creating significant
continuity in leadership.
Average production (boe/d)
% oil
1,050
100%
3,350
100%
If it ain’t broke, don’t fix it
Exit production (boe/d)
% oil
2,200
100%
4,500
100%
Cash flow ($mm)
CFPS ($/f.d. share)
$10.5
$0.18
$46.5
$0.78
Capex ($mm)
$40.0
$55.0
Net debt ($mm)
Credit facility ($mm)
% drawn
$0.0
$20.0
0%
$8.5
$20.0
43%
This version of Caltex has a strategy similar to the predecessor with a focus on
large resource in place pools with low recovery factors. Caltex has de-risked a
material pool at Druid and this year should grow volumes significantly while looking
to expand its inventory. To ensure the long-term profitability of the Druid play,
Caltex is making sure all infrastructure is in place, that costs are driven down as
much as possible, and the asset base is de-risked in a prudent manner. By doing
this, Caltex hopes to create an asset with the ability to grow or maintain volumes
and spin off material free cash flow.
46.2 / 60.0
$2.90
$174.0
$0.0
$12.3
$162
Reserves
Proved (mmboe)
% oil
Proved + Probable (mmboe)
% oil
YE 2012
n/a
n/a
5.80
100%
Heavy oil with low costs = significant value
Caltex is focused in SW Saskatchewan with 132 net sections of land targeting
heavy oil. In total, Caltex enjoys up to 500 mmboe of OOIP with over half of that
coming from its core Druid property. With recovery factors of less than 1%, there is
clearly material resource upside to the name. To appropriately exploit this asset,
Caltex believes it has over 250 drilling locations with up to two-thirds at Druid.
Tom Bieschke
Brett Wrathall
Brent Bracken
Darren Grandoni
Dave Ambedian
Peter Williams
Craig Glick
President & CEO, Chairman
SVP Exploration, Director
CFO, SVP Finance, Director
VP Land
Director
Director
Director
76%
DATE
OFFERING
SHARES (mm)
Oct 2011
Internal
8.000
Oct 2011
Internal (Flow-Thru)
1.000
Jan 2012
Internal
11.166
Feb 2012
TriWestern Acq'n
5.761
Various 2012
External
10.370
Dec 2012
Internal (Flow-Thru)
0.129
Feb 2013
External
9.685
PRICE
$0.25
$1.00
$1.00
$1.41
$1.45
$3.50
$2.90
TOTAL ($mm)
$2.0
$1.0
$11.2
$8.1
$15.0
$0.5
$28.1
TOTAL EQUITY RAISED
$1.43
$65.9
46.1
**Last equity issue price – $2.90 in Feb 2013
2014 capital spending will be focused at Druid, and with 2013 focused on
delineating the central part of Druid, we expect 2014 will become a year of low-risk
development drilling with material growth in production. With such a robust drilling
program this year (~45 wells), Caltex believes it can more than double production
from ~2,200 boe/d in December 2013 to greater than 4,500 boe/d by the end of
2014. Key to the company’s success has been its ability to drive down operating
costs and use the latest technology to improve drilling results. In addition to its
core Druid drilling, Caltex will be pushing the bounds of its play outward. Recent
land acquisitions have expanded the company’s presence in the area and, with
success, could lead to a material expansion in the company’s drilling inventory.
A big year of growth planned
2014 capital spending of ~$55 million will fund about 45 wells, expand
infrastructure, and grow exit to exit production by over 100%. This is a major year
of development drilling for Caltex with production growth expected to follow suit.
With no debt currently and a capital program approximating cash flow, we expect
Caltex will maintain its strong financial position.
February 18, 2014
ASSETS – HIGHLY ECONOMIC HEAVY OIL FOCUS
Heavy oil with cost control, an attractive combination
Druid: A core asset
Caltex is focused on heavy oil with its key property at Druid in
SW Saskatchewan. This is a conventional heavy oil asset,
although with no sand issues, the property is able to be drilled
horizontally, improving economics. With over 500 mmboe of
OOIP across its assets and over half at Druid there is clearly a
lot of work left to be done here. Recovery factors at Druid of less
than 0.35% currently and 2.8% on a 2P basis leave considerable
upside for shareholders.
In what we term the central de-risked portion of Druid (see map
at left) there is an additional 145 locations left to be drilled. We
expect part of the 2014 drilling program to focus on proving up
extensions of the play; this could lead to a significant inventory
expansion.
Note: much of Caltex’s land base is not in the company name hence we only
show a scattering in the map above; we believe that the actual ownership is
much larger.
Economics shine with cost control (GMP type curve)
80
Risked Production (bbl/d)
Risked payout
75
60
50
40
25
20
0
0
1
6
11
16
21
26
31
36
Months on production
Oil (bbls/d)
41
46
51
Cumulative (mbbl)
Unrisked Assumptions
Well Cost ($mm)
$1.0
Risked Economics*
BT NPV10 ($mm)
$1.6
IP 30 (bbl/d)
EUR (mbbl)
% Liquids
Year 1 Decline (% )
ROR (% )
Well Payout (months)
Half Cycle F&D ($/boe)
PIR (times)
Year 2 Decline (% )
* Assumes a 90% chance of success
100
100
100%
40%
50%
Recycle Ratio (times)
Source: Company Reports, GeoSCOUT
169%
9
$9.50
2.5x
3.1x
56
61
Cumulative Production (mbbl)
100
In heavy oil, controlling costs is key, and Caltex excels in this
regard, in our opinion. All Druid production flows into multi-well
batteries where produced water is piped to injection facilities and
clean oil is trucked to rail or pipeline sales points. With only clean
oil on wheels Caltex has been able to drive operating and
transportation costs down to ~$16/boe and expects this to fall to
~$13/boe in 2014. With this type of cost structure and low
royalties of ~11%, Caltex is able to generate operating netbacks
in the $40s and possibly $50s, given recent strong pricing.
In the short term, Caltex will continue to engineer the pool, adding
infrastructure where required and expanding the current waterflood
scheme. To complete its planned drilling schedule, Caltex is on
track to rig release one well per week while the weather permits;
this is not a team that shies away from staying active.
Resource upside and economics
Analog pools have shown recovery factors of over 20%. For Caltex,
this could equate to an incremental 40 mmboe of reserves.
With the low cost structure, Caltex is able to deliver strong
economics based on GMP’s type curve. With well costs of ~$1
million, IP rates of ~100 bbl/d, EURs of 100 mboe, and a
reasonable cost structure, wells can payout in less than a year
and deliver an NPV of over $1.6 million. Details of our well
assumptions can be seen to the left.
End game
An asset base with large OOIP, low geological risk, decline rates
that are being mitigated with waterflood, and an incredibly low
cost structure for heavy oil should attract the attention of
numerous potential buyers in today’s marketplace. Or Caltex can
spin off the free cash to its shareholders.
Stacey McDonald
[email protected]
403-543-3042
[email protected]
403-695-1403
February 18, 2014
Carmel Bay Exploration Ltd.
Patrick Manuel
President, CEO & Board of Directors
John Mah
VP Finance & CFO
Nathan MacBey
VP Land
Darren Manum
VP Production
Paul Neave
VP Engineering
Doug Smith
VP Exploration
Brad Wilson
VP Operations
Murray Nunns
Board of Directors
John Brussa
Board of Directors
Don Copeland
Board of Directors
Brett Herman
Board of Directors
Garry Tanner
Board of Directors
Dheeraj Verma
Board of Directors
Montney land position
Last: N/A**
Led by the successful team behind Monterey
Exploration
Carmel Bay was founded in late 2011 and is led by the former Monterey Exploration
team. This includes Patrick Manuel as Carmel Bay’s President and CEO, John Mah
as VP Finance and CFO, Nathan MacBey as VP Land, Darren Manum as VP
Production, Paul Neave as VP Engineering, Doug Smith as VP Exploration and
Brad Wilson as VP Operations. The management team is also complemented by a
well-rounded, experienced Board of Directors which includes Murray Nunns as
Chairman, John Brussa (Burnet, Duckworth & Palmer), Don Copeland (oilfield
service entrepreneur), and Brett Herman (TORC). Carmel Bay has been funded with
a majority investment from Quantum Energy Partners, a US-based Private Equity
firm, and Quantum has two members (Garry Tanner, Dheeraj Verma) on Carmel
Bay’s Board of Directors.
Positive past performance – Monterey sold for $375 mm
Jedney
The Carmel Bay management team has a track record of success with a history of
building attractive assets and monetizing value for investors through corporate
sales. A key example of this is Monterey Exploration, which was anchored in its NE
BC Groundbirch Montney asset (a similar asset base to Carmel Bay). In July 2010,
Pengrowth Energy Trust (PGF.u) acquired Monterey Exploration (MXL-TSX) for
total consideration of $375 mm, which represented a 94% premium to market. The
company, which was producing ~1,800 boe/d, attracted a strong metric of over
$200,000/boe/d. The high metric was driven by the company’s Groundbirch
Montney project on which MXL had 20 mmcf/d net of tested behind pipe production.
After adjusting for the behind pipe production (total production of ~5,100 boe/d) we
still calculate a strong transaction metric of $73,500 boe/d. On a land basis and
after adjusting for production value, the sale implied a value of $6.3 million/section
($9,843/acre) for MXL’s 19 net sections at Groundbirch. This management team has
a proven track record of building strategic land positions and strong growth. MXL
showed a 958% share price return over its last two years of operations and strong
reserve growth from 0.0 mmboe in December 2005 to 23.8 mmboe in April 2010.
Nig
Source: GeoSCOUT, GMP
**no recent trade or equity price
Fully funded to de-risk its asset base
Carmel Bay’s leading shareholder, Quantum Energy Partners, provided a $200
million equity commitment in December 2012. This financial flexibility will enable the
company to delineate its highly prospective Montney asset base. Based on the
spending to date, we believe that Carmel Bay has at least $100 million of the equity
line available to draw on.
Identified Montney resource prospectivity early
The Carmel Bay team has a track record of appropriately delineating and developing
Montney assets. Carmel Bay was early in identifying a Montney opportunity at Nig/
Jedney and established a significant land position in an attractive liquids-rich
overpressured Montney play. Since then, competitors have moved into the area
and the play has transitioned from the land capture stage to commercial development.
February 18, 2014
OVER 60,000 ACRES BETWEEN THE NIG, JEDNEY AND MICA AREA IN NORTHEASTERN BC
Strategic land position in high-quality Montney fairway
Land position at Nig, BC
Carmel Bay has amassed a significant NE BE Montney land
position at Nig and Jedney. In total, they have 86 sections (100%
WI) in a regional extensive Montney fairway. The Nig and Jedney
lands are offset by active Montney operators such as Tourmaline
Oil (TOU), Storm Resources (SRX), Shell (RDS), and Progress
Energy Canada (Petronas). The thickness, quality, and pressure
of the Montney varies but the Montney on Carmel Bay’s lands is
thought to be at least 200 metres thick (50 metres in the Upper
Montney) and overpressured. We believe this could support fullscale Montney development of 8 wells per section.
Early Montney results are encouraging
Development of the Montney at Nig/Jedney is behind other
Montney areas (Groundbirch, Town, Swan, etc.) but the early
results have been encouraging and activity levels are steadily
increasing. Test rates in the area have ranged from 4 to over 10
mmcf/d and IP30 rates from 3–4 mmcf/d with estimated EURs of
3–5 bcf per well. The company’s first test well of four came off of
confidential status in early January. At the end of a six-day period,
the well tested in excess of 13 mmcf/d at 1,500 psi flowing
casing pressure. As completions are optimized for the Montney
wells, we believe IP rates and EURs could improve further. We
expect activity to remain high at Nig with numerous horizontal
wells licensed by CNRL (CNQ), Paramount (POU) and Storm
(SRX), which will continue to de-risk Carmel Bay’s land position.
Land position at Jedney, BC
Recent transaction values land at $4,700/acre
Nig/Jedney – potential land value
High
Approx.
$6,000/acre
Acres
($mm)
Nig
34,815
$208.9
Jedney
24,787
$148.7
Total
59,602
$357.6
Source: Company Reports
Medium
$4,000/acre
($mm)
$139.3
$99.1
$238.4
Low
$2,000/acre
($mm)
$69.6
$49.6
$119.2
On January 23, Storm Resources (SRX) announced it was
acquiring Yoho Resources’ (YO) Montney assets in NE BC for
total consideration of $87.7 million (cash and shares). The assets
included 29 sections of undeveloped land in the Umbach–Nig
area adjacent to Carmel Bay. We calculate a land metric of ~$3.0
million per section or $4,700/acre, which is an impressive metric
for what we would consider a relatively newer Montney
development area. We believe the metric speaks to the quality of
the land and resource opportunity. Over time, we believe metrics
for this Montney fairway could increase as the play moves further
along in its development. To the left, we show a potential land
value table with a range of land values from $2,000–$6,000/acre,
which drives a land value of approximately $119–$358 million.
The key takeaway being that Carmel Bay has amassed a
sizeable land position in a highly prospective and desirable
fairway.
Stacey McDonald
[email protected]
403-543-3042
[email protected]
403-695-1403
February 18, 2014
SHARE DATA
Dilutive Proceeds
PRODUCTION DATA
Oil and NGLs (b/d)
Total (boe/d) 6:1
Equivalent growth
131.8 / 163.9
$1.90
$311.5
$35.8
$52.1
$295
2013E
1,700
9.3
3,250
104%
2014E
2,500
15.0
5,000
54%
2015E
3,200
20.0
6,533
31%
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Hedging ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
2013E
$56.38
($7.61)
($14.00)
$34.77
($1.00)
$33.77
$30.78
$36.6
$0.22
$72.0
$35.8
1.0x
2014E
$54.75
($7.67)
($13.00)
$34.09
$0.00
$34.09
$31.41
$57.3
$0.35
$55.0
$33.5
0.6x
2015E
$54.03
($7.56)
($13.00)
$33.47
$0.00
$33.47
$31.61
$75.4
$0.46
$55.0
$13.1
0.2x
VALUATION
P/CF
EV/DACF
EV/boe/d
2013E
8.5x
8.2x
$90,819
2014E
5.4x
5.3x
$59,032
2015E
4.1x
4.0x
$45,178
Paul Colborne
Chariman
Steve Sugianto
Jack Smith
VP Finance & CFO
H. Scott Oldale
VP Exploration
Darrin Hanik
VP Operations
Chris Tibbles
VP Land
Peter Bannister
Director
Don Cowie
Director
Kel Johnston
Director
Josh Woitas
Director
Randy Brockway
Director
28%
DATE
April-12
CS
13
April-12
CS
118.2
November-12
CDE
0.6
TOTAL EQUITY RAISED
131.8
PRICE
$0.75
$1.00
$1.50
$0.98
TOTAL ($mm)
$10
$118
$0.9
$128.9
**Last trade price – $1.90 in Jan 2014
Last: $1.90**
High-quality oil pool with visibility for growth
New Star is anchored by its Highvale Banff oil pool in central Alberta. The property is
located 30 miles west of Edmonton, AB and targets light oil, medium oil and natural
gas. The property covers 83,261 gross acres (92% WI) which New Star operates.
Highvale is an elite and best-in-class oil asset with a large OOIP pool, estimated at
358 million barrels in place on New Star’s land with only 3.3% recovered to date.
The company plans to use horizontal drilling and enhanced oil recovery methods
such as waterflooding to drive growth. Currently, New Star has identified ~130
horizontal Banff drilling locations which could take primary recovery factor on the
pool to ~10%
New Star is run by an experienced management team and directors
New Star was founded in early 2012 when it acquired the Highvale Oil pool from
EOG. New Star is run by Steve Sugianto, who has over 26 years of experience in
the Oil & Gas industry such as VP Engineering and Business Development at
KeyWest, and President and CEO of Galleon. The Board of Directors includes many
recognizable names such as: Paul Colborne, Peter Bannister, Kel Johnston, Josh
Woitas, Don Cowie, and Randy Brockway.
Waterflood could significantly increase recovery factors
Beyond the Banff drilling inventory we also see the potential for New Star to
significantly increase the recovery factor from the pool through waterflood. We
believe that primary recovery (horizontal drilling) can take recoveries to 10% but
waterflood could bring pool recoveries to over 20% of the OOIP. Under this
scenario, waterflood could add an incremental +30 mmbbls of recoverable oil.
There are several analogue waterflood schemes already in place in the Greater
Highvale area. The Cherhill and St. Anne Banff pools have seen recoverable factors
so far reach 12–25% and see ultimate recoveries of 20–30%. Currently, New Star
has 7 water injectors in place with plans to add another 6 injectors by the end of
2014. Based on potential recoveries and analogue pools, management believes that
waterflood recovered barrels are very low-cost for only ~$5.00/boe.
Fully funded for growth
In addition to having a low-risk development play, we believe New Star is also well
capitalized to finance whatever growth model it wants. As of September 30, New
Star had only $25 million on its $65 million revolving credit facility. For 2014, we are
forecasting net debt of $33.1 million versus $57.3 million of cash flow or only 6.0x
D/CF. This clean balance sheet enables the company to expand its drilling program
if needed or to be an attractive acquisition candidate.
Highvale can be a growth model or dividend model asset
We believe that New Star has a low-risk inventory of repeatable drilling prospects
with additional upside with waterflooding. Ultimately, the company will have the
luxury of multiple “exit” strategies as it has structured and developed its asset base
in a manner that gives it optionality.
February 18, 2014
NEW STAR FOCUSED ON SUSTAINABILITY AND COST MANAGEMENT
Highvale land position
Well results exceeding type curves
The Highvale Banff horizontal type curve calls for an IP90 of 90
b/d, which drives EUR of 100 mb of oil and 0.2 mmcf of natural
gas. This type curve results in highly economic wells with a
payout of one year, NPV10 of $3.5 million and a recycle ratio of
over 2.5x. The economics are attractive based on the current
type curve alone but it is important to note that the well results
are tracking ahead of type curves. As shown in the graph to the
left, the production data to date (based on 19 wells) is tracking
significantly ahead of the type curve with IP30 wells over 200
b/d. Based on the success to date, we believe that the Banff
wells should see even quicker payouts and also increased
reserve bookings.
Corporate production and GMP forecasts
Should be self-funding in 2014
7,500
Gas
Oil & NGL
New Star is planning to drill 19 horizontal wells in 2014, which is
up from 15 horizontals in 2013. We are forecasting that New
Star will spend $55 mm in 2014 and will grow production from
~4,500 boe/d to exit at close to 6,500 boe/d. This equates to
2014 average production of ~5,000 boe/d (50% liquids), which
represents YoY growth of 54%. Driven by the strong economics
of the Banff play, we are forecasting that New Star will generate
$57.3 million in cash flow, which is greater than the planned
capital program. New Star’s FCF generation makes it unique
among the private E&Ps.
6,000
boe/d
4,500
3,000
1,500
0
Q2/12 Q3/12 Q4/12 Q1/13 Q2/13 Q3/13
^Approximate production based on company presentation
Asset can continue growing, be an attractive
acquisition target or pay a dividend
2014E 2015E
Type curve
We are impressed with New Star’s ability to become self-funding
only two years after its inception. Looking beyond 2014, we see
the company producing over 7,000 boe/d and generating a
meaningful amount of FCF. This puts it in an enviable position of
having multiple paths for shareholder returns 1) continuing to grow
production, 2) paying a dividend with its excess FCF (2015
possibility), and 3) selling the company to a dividend yield co. as
it has created an attractive asset for a yield-orientated E&P.
1,200
1,000
Average
boe/d
800
600
400
Taking a closer look at potential dividend scenario
200
0
1
2
3
4
5
6
7
8
9
months
10
11
12
13
14
15
With New Star shifting towards FCF in 2014 we thought it was
worthwhile to take a look at a potential dividend scenario.
Assuming production of ~7,000 boe/d (reach in 2015) and a
$31.00/boe cash flow netback would generate ~$80 million of
cash flow. We estimate that New Star would only require about
$45 million to hold production flat, leaving $35 million
(~$0.25/share) available for a dividend. Admittedly, we do not
know what route New Star will take a couple of years out, but the
key takeaway is that it has multiple options.
Aaron Swanson, CFA
[email protected]
403-543-3563
Associate: Jordan McNiven
[email protected]
403-695-1401
February 18, 2014
Last: $2.00**
Diversified asset base with oil upside
SHARE DATA
Net Debt ($mm)
Dilutive Proceeds
PRODUCTION DATA
Oil and NGLs (b/d)
Total (boe/d) 6:1
Equivalent growth
86.4/96.4
$2.00
$193
$25.3
$7.0
$211
2013E
1,401
10.4
3,128
66%
2014E
2,941
11.8
4,910
57%
2015E
4,109
13.7
6,384
30%
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Hedging ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
2013E
$49.04
($7.62)
($11.29)
$30.14
($2.47)
$27.66
$26.73
$30.5
$0.32
($58.0)
$25.3
0.8x
2014E
$57.89
($12.16)
($12.25)
$33.48
($0.70)
$32.78
$30.07
$53.9
$0.56
($74.0)
$45.4
0.8x
2015E
$57.89
($12.16)
($12.25)
$33.48
$0.00
$33.48
$30.71
$71.6
$0.74
($80.0)
$53.8
0.8x
VALUATION
P/CF
EV/DACF
EV/boe/d
2013E
6.3x
6.9x
$69,705
2014E
3.6x
4.3x
$48,492
2015E
2.7x
3.3x
$38,621
Don Gray
Chairman
Kevin Adair
President & CEO
Cheree Stephenson
VP, Finance & CFO
Neil Korchinski
VP, Engineering
Joe Looke
Peter Verburg
Pat Arnell
After raising a small amount of seed capital in April 2011, Petrus officially put a pin on the
map in October of 2011 when the company acquired a 50% working interest in an Alberta
Foothills asset with gas production (1,300 boe/d net) plus Cardium oil drilling upside. The
leadership team was assembled by Don Gray, founder and Chairman of Peyto
Exploration and Development Corp. (Peyto) and has a number of former Peyto
employees at the helm, including Neil Korchinski (VP Engineering) and Cheree
Stephenson (CFO). Kevin Adair is the President and CEO of Petrus. Kevin’s background
includes being the co-founder of Spry Energy, a small-cap Cardium oil producer that sold
for $225 million in the spring of 2011; he was also former President, COO and Director of
Petrobank Energy and Resources.
Transformed into a balanced producer with oil drilling upside
In 2011, Petrus was 94% gas weighted, however, through a combination of its Peace
River Arch acquisition and successful oil drilling on its Foothills assets, the company is
now a balanced producer with 56% of current production weighted to oil and liquids.
Going forward, we see the oil weight further increasing as the company’s drilling activity
is focused on furthering its Foothills oil production and developing its Montney oil upside
in the Peace River Arch, most notably in the greater Tangent area. As it stands right now,
Petrus has over 40 Cardium oil drilling locations on its Foothills land and 150 locations
across its Peace River Arch acreage.
Foothills Cardium wells driving light oil growth
Director
Director
Director
24%
DATE
OFFERING SHARES
PRICE
September-11
CS
11.05mm
$1.00
November-11
CS
18.1mm
$2.00
November-11
FT
3.0mm
$2.40
June-12
CS
53.6mm
$1.75
June-12
FT
0.62mm
$2.10
April-13
CS
0.05mm
$2.00
April-13
FT
0.03mm
$2.40
August-13
CS
$0.01mm
$2.00
TOTAL EQUITY RAISED
72.2mm
Leadership has a distinct Peyto flavor
TOTAL
$11.1mm
$36.2mm
$7.0mm
$93.7mm
$1.3mm
$0.1mm
$0.1mm
$0.02mm
$149.4mm
**Last equity issue price–$2.00 in Aug 2013
Since acquiring the asset in the fall of 2011, Petrus has participated in over 20 Cardium
oil wells on its Foothills land base. Looking at the cumulative production data, these wells
are some of the most prolific oil producers in western Canada, with the average well
paying out in 9 months and delivering an estimated NPV of $7.9 million. Through the
second half of 2013, Petrus participated in a 4-well Cardium pad (33% working interest)
located in the heart of its Stolberg land base. Although the wells produced intermittently,
as the operator was constructing permanent facilities, judging by current and cumulative
production levels, all four of these wells appear positioned to exceed our type curve for
the area. This suggests cumulative production of 80,000 bbls in the first 8 months of
production. We believe these wells are currently contributing roughly 750 bbls/d of the
company’s 4,000 boe/d of production.
Strong balance sheet and Natural Gas Partners backing provides flexibility
We see Petrus’ balance sheet comfortably under 1.0x trailing 2014 estimated cash flow,
couple this with the private capital backing from Natural Gas Partners (NGP) and we
believe Petrus has the flexibility to either expand on its 2014 drilling program or take
advantage of one of the number of attractive assets for sale on the market.
Focus will be capturing asset value
We believe in the near term Petrus will focus on capturing the value of its asset base
through delineation drilling, particularly in the Peace River Arch where we see the most
significant upside. We would also not be surprised to see them take advantage of the
buyer’s market and make a complimentary asset acquisition.
February 18, 2014
DEVELOP FOOTHILLS, DE-RISK PEACE RIVER LAND BASE
Stolberg Cardium delivering big results
Prolific Stolberg wells worth highlighting
Nearly two-thirds of Petrus’ production comes from its foothills land
base and, more specifically, from Stolberg. To be more specific
still, section 29 has been the real bread-winner for Petrus,
delivering nearly 750,000 bbls in the last two years. Drilling in 2013
focused on section 21 (wells labelled 2 through 5 in the figure) and
while it hasn’t been as prolific as section 29, it’s certainly holding
its own and Petrus holds a higher working interest at 33%.
Through November, the 4-well pad on section 21 has delivered
over 150,000 bbls of oil, despite several wells being shut-in for
significant periods of time while awaiting government approval and
facility construction. All 4 wells have posted monthly production
rates in excess of 450 bbl/d.
Petrus land
2013 Petrus well
Petrus well
4
1
5
2
3
Most recent well results
Test rate
(boe/d)
Well
WI
1
2
3
4
5
474
789
828
848
1,029
21%
33%
33%
33%
33%
Poised for significant reserve growth
Production history and GMP forecast
6,000
Oil and liquids (bbl/d)
Natural gas (boe/d)
% oil and liquids
60%
50%
4,000
40%
boe/d
5,000
3,000
30%
2,000
20%
1,000
10%
Tangent Montney oil activity
2013 and 2014 drilling
activity - De-risking the
Montney. Test rates
up to 190 bbl/d.
Petrus lands
Petrus wells
14Q4E
14Q3E
14Q2E
14Q1E
13Q4E
13Q3A
13Q2A
13Q1A
12Q4A
12Q3A
12Q2A
0%
12Q1A
-
Despite nearly a 2.5x increase in per share (debt adjusted) oil and
liquid reserve volumes on the company’s 2012 reserve report, we
see the potential for another significant increase in liquids weight
on the company’s 2013 reserve report. A conservative reserve
report and successful 2013 drilling program are the factors
supporting our conviction. Petrus’ 2012 report included no proven
undeveloped locations and 9 probable locations booked at very
conservative values. Factor in the 2013 drilling program and the
fact that previously booked locations are outperforming reserve
engineer estimated production levels, and we see Petrus
positioned to deliver strong year-over-year reserve growth and
value, particularly since many of the new bookings will be oil
weighted.
Montney oil at Tangent near-term focus, still lots to learn
Petrus’ winter drilling program is set to include 10 (9.3 net)
Montney oil wells with up to 15 additional locations to be drilled
through the summer. Recent focus has been in the greater
Tangent area, where the company drilled three vertical and one
horizontal well through the summer of 2013. Each of the wells
successfully tested oil and the four wells had a combined rate of
305 boe/d (90% oil weighted). The company plans to de-risk the
area through a combination of vertical and horizontal wells. Much
of the horizontal drilling is taking place in the North Tangent block
where the company has 4 horizontals drilled, is currently drilling one
other location and has an offsetting location licensed. Historically, the
company has drilled a vertical well into the Montney formation and
has followed this up with a horizontal leg.
Given Petrus owns over 130 net sections of land in the Peace
River area, much of it prospective for Montney oil, we see this
asset base offering long-term upside and believe the company is
in the early stages of discovering true value of the land.
Stacey McDonald
[email protected]
403-543-3042
[email protected]
403-695-1403
February 18, 2014
Seven Generations Energy Ltd.b
SHARE DATA
Dilutive Proceeds
93.6 / 116.8
$25.00
$2,921.0
$721.7
$227.4
$3,415
PRODUCTION DATA
Oil and NGLs (b/d)
Total (boe/d) 6:1
Equivalent growth
2013E
4,675
23.0
8,500
103%
2014E
19,250
94.5
35,000
312%
2015E
34,800
139.2
58,000
66%
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Hedging ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Convertible Debentures ($mm)
Net Debt ($mm)
D/CF
2013E
$42.00
($7.56)
($6.00)
$28.44
$0.00
$28.44
$25.16
$78.3
$0.67
$620.0
$400.0
$208.1
2.7x
2014E
$44.50
($6.23)
($5.75)
$32.52
$0.00
$32.52
$30.25
$386.4
$3.31
$900.0
$400.0
$721.7
1.9x
2015E
$44.20
($6.19)
($5.75)
$32.26
$0.00
$32.26
$30.03
$635.6
$5.44
$900.0
$400.0
$986.1
1.6x
VALUATION
P/CF
EV/DACF
EV/boe/d
EV/2P reserves (Oct 31, 2013)
2013E
37.3x
44.6x
$401,797
2014E
7.6x
9.3x
$97,579
2015E
4.6x
5.7x
$58,884
$12.01
Pat Carlson
CEO, Board of Directors
Ron Schmitz
Chief Engineer
Steve Haysom
Senior VP
Harry Cupric
CFO
Randy Evanchuk
Executive VP
Chris Law
VP Corporate Planning
Glen Nevokshonoff
VP Development
Kevin Brown
Board of Directors
Jeff Donahue
Board of Directors
Jeff van Steenbergen
Board of Directors
Craig Glick
Board of Directors
Robert E. Hougie
Board of Directors
Kent Jespersen
Board of Directors
Michael Kanovsky
Board of Directors
Kaush Rakhit
Board of Directors
INSIDER OWNERSHIP (%, fd)
DATE
OFFERING SHARES (MM)
12/18/2013
CS
10.0
5/17/2012
CS
18.2
5/17/2012
CS
4.7
May 2008
CS
59.8
TOTAL EQUITY RAISED
92.7
World-class Kakwa River Montney project
Seven Generations Energy is a large Deep Basin–focused producer with a strategic
Montney land position in what we consider to be one of the top plays in North America.
The company’s land spans over 433 net sections covering the Cretaceous to the
Duvernay formations. Most of the activity to date has been focused on the Montney
zone, on which Seven Generations has 403 net sections of largely contiguous land.
We consider the Kakwa Montney to be one of the top plays for several reasons:
1) the Montney has high liquids yields of 50 to over 300 bbls/mmcf of wellhead
liquids, 2) high deliverability from wells (avg. IP30 of ~1,400 boe/d), and 3) the
scale of resource is immense, with over 3,100 locations in the upper and middle
Montney.
All about scale; 2 bcf/d and 200,000 b/d of liquids
One of the key defining characteristics of Seven Generations is the scale of its
Montney project. The company estimates that it has 3,100 upper and middle
Montney locations at Kakwa River and an estimated 1,400 lower Montney locations
in a P50 scenario. This deep inventory can support a 15-year production life at a
rate of 2 bcf/d and >200,000 b/d of liquids (50% condensate). In order to develop
the property, management forecasts that it would cost $41 billion for drilling and
completions and $6.6 billion for infrastructure over time. The key to this project is
that management expects it to be self-financing (generating free cash flow) in later
2015 and to have cumulative free cash flow in 2017.
Experienced management team with backing of well-known investors
Seven Generations was founded in 2008 and is run by Pat Carlson, CEO. Mr.
Carlson has run other successful companies including North American Oil Sands
and Krang Energy. The company’s Board of Directors is comprised of Pat Carlson,
representatives from the five largest shareholders (ARC Financial, CPPIB, KERN
Partners, Natural Gas Partners, and ZBI Ventures) and three independent
directors. In total, the five largest shareholders and management own 81% of the
fully diluted stock, strongly aligning interests with the remaining shareholders.
Initial wells exhibit robust liquids ratio and deliverability
81%
PRICE
$25.00
$11.00
$11.00
$5.00
$8.65
Last: $25.00**
TOTAL ($MM)
$251.0
$200.0
$51.3
$299.0
$801.3
**Last equity issue price – $25.00 in Dec 2013
Seven Generations has demonstrated some of the best well production rates in
North America. Its highest gas rate tested at 28.4 mmcf/d of gas and its highest
wellhead liquids rate tested at 3,372 b/d. Based on 8 delineation wells within its
core “nest”, the company has seen average rates of 1,400 boe/d (IP30) and 1,200
boe/d (IP90). The wells also exhibited impressive performance over the long term.
One of its longest producing wells (Pad 18 #1) had a strong IP90 rate of 2,284
boe/d and in only 13 months produced 588 mboe (26% liquids).
February 18, 2014
LIQUIDS-RICH KAKWA RIVER PROJECT COMBINES STRONG PRODUCTION RATES AND IMPRESSIVE ECONOMICS
Land position with liquids/gas ratio
High liquid yields drive economics
Seven Generations builds out its 2014 guidance based on an IP90
type well that produces 6.0 mmcf/d of gas and 750 b/d of C5+. One
of the main reasons for our positive view on the company is its high
liquids yield, which significantly improves the economics of the
Montney play. So far, Seven Generations has had 5 wells with
cumulative condensate production of over 100,000 barrels. Wellhead
liquids ratios from the area have exhibited rates of 50 to 300+
bbls/mmcf with an additional 40 to 80 bbls/mmcf of NGLs sales. The
goal is to reach optimized well costs of $7.6 million, which drives
best in class IRR’s of 200%–803% and payback periods of 0.4–0.7
years. Most of Seven Generations 2014–2015 pad drilling will be
focused on its “rich gas 2” band that returns the best economics.
With strong liquids pricing, Seven Generations estimates that it could
supply its natural gas at a loss of US$2.82–US$4.46/mmbtu and still
break even. This enables the company to remain competitive in an
oversupplied gas market.
Corporate production profile
400
350
Oil & NGL
Large contingent and prospective reserve base
Gas
As of October 31, 2013, Seven Generations had its reserves
evaluated by McDaniels. The evaluator estimated that the company
had 2P reserves consisting of 840.1 bcf of natural gas and 144.4
mmb of recoverable liquids or 284 mmboe for total 2P reserves.
Based on this, McDaniels determined a NPV10 value of $2.9 billion
for 2P reserves. Based on an ultimate development plan for Kakwa
River, Seven Generations estimated a P50 EUR of 6.1 billion boe
and a P50 NPV10 value of $21.2 billion.
mboe/d
300
250
200
150
100
50
0
2013
2014
2015
2016
2017
2018
^^ 2013 is Q4/13 annualized production
2019
2020
The company exited 2013 with production of ~16,000 boe/d. We
believe production will grow significantly in 2014 and beyond, driven
by its high-quality asset base. For 2014, Seven Generations expects
to spend ~$900 million in 2014, have 7 rigs running and bring 35–40
new wells on stream. This is expected to result in production
between 30,000–40,000 boe/d or YoY growth of over 300%. For
2015, Seven Generations expects to spend between $700–$950
million and produce between 50,000–70,000 boe/d or YoY growth of
71%.
Corporate cash flow and capex projections
Cash Flow
Capex
Cummulative Free Cash Flow
($mm)
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
00
(500)
(1,000)
2013
2014
2015
2016
2017
2018
^^ 2013 is Q4/13 annualized production
Production expected to ramp up in next two years
We foresee a corporate sale or IPO by 2015
2019
2020
We believe that Seven Generations is in the sweet spot of the
liquids-rich Montney and has unparalleled asset quality. With strong
economics, years of production growth and potential for additional
upside, we believe that Seven Generations will be a company to
watch. In addition, the company has identified a soft target of mid2015 for additional equity sponsors either through public listing or a
potential corporate sale, which could provide investors with
additional liquidity and a premium valuation.
Aaron Swanson
[email protected]
403-543-3563
[email protected]
403-695-1401
February 18, 2014
Spur Resources Ltd.
SHARE DATA
Net Debt ($mm)
Dilutive Proceeds ($mm)
PRODUCTION DATA
Oil and NGLs (b/d)
Total (boe/d) 6:1
Equivalent growth
53.4/56.9
$6.00
$341
$28.3
$12.4
$357
2013E
1,950
18.6
5,054
36%
2014E
4,179
20.9
7,663
52%
2015E
6,290
22.3
10,015
31%
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Hedging ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
2013E
$41.65
($6.18)
($10.37)
$25.10
($0.40)
$24.71
$23.72
$43.8
$0.91
($57.2)
$21.9
0.5x
2014E
$51.61
($9.29)
($9.55)
$32.77
($0.47)
$32.30
$30.56
$85.5
$1.52
($90.0)
$28.3
0.3x
2015E
$53.47
($9.62)
($9.55)
$34.30
$0.17
$34.47
$32.73
$119.6
$2.10
($122.0)
$30.6
0.3x
VALUATION
P/CF
EV/DACF
EV/boe/d
2013E
6.3x
6.7x
$59,542
2014E
3.9x
4.3x
$48,225
2015E
2.9x
3.1x
$37,135
Clayton Woitas
Chairman
Ian Currie
President & CEO
Scott Birchall
VP, Corporate Development
Gary Fischer
VP, Operatioms
Andrew Leuchter
VP, Exploration
Rob Motherwell
VP, Land
Greg Warner
VP, Finance & CFO
Theodore Hanlon
Margaret McKenzie
David O'Brien
Ron Wigham
Grant Zawalsky
Earning their spurs
Profico team behind the helm at Spur
Founded in 2006, Spur was spun out of the Profico Energy Management and Focus
Energy Trust merger. Profico was a notable success story as the company raised a total
of $60 million over a six-year period and sold for $1.2 billion in 2006. The majority of
senior management at Spur worked together at Profico, with Ian Currie leading the way
in the CEO position. Supporting the management team is a very capable Board of
Directors, led by Clayton Woitas, who currently holds the Chairman position.
Transformation into an oil weighted producer
In 2011, Spur was a shallow gas company with a 9% liquids weighting, but through a
combination of acquisitions and oil-focused drilling, the company has materially
improved its liquids weighting, driving a fourfold increase in cash flow and a doubling of
netbacks. As a result of a continued oil-focused drilling program, largely led by their
Viking play in Saskatchewan, Spur is expected to be 55% weighted to oil and liquids
through 2014. Given over 80% of Spur’s $90 million 2014 capital program is to be
directed towards oil drilling, we suspect oil weighting will continue to rise through 2015.
Provost acquisition adds another leg to the stool
Recently, Spur announced an agreement to acquire Provost Viking oil assets, which
include 1,200 boe/d (60% weighted to oil) and 140 net sections of land for a net cost of
$52 million. Attractive metrics aside (acquired this at $43,300/boe and 3.5x forward cash
flow), we like this transaction as it deepens Spur’s Viking light oil drilling upside, giving
them the opportunity to leverage upon expertise gained from the Colleville asset base.
Of the 140 net sections acquired, Spur believes 25 of the sections are prospective for Viking
light oil, offering 150 low-risk locations to inventory. Initial development plans are calling
for a 10-well drilling program through 2014, with an expanded program expected in 2015.
Clean balance sheet, great cost structure
Director
Director
Director
Director
Director
36%
DATE
OFFERING
SHARES
PRICE
December-11
CS
10.6mm
$4.25
August-12
Acquisiton
1.8mm
$4.25
February-14
CS^^
8.35mm
$6.00
TOTAL EQUITY RAISED
20.75mm
Last: $6.00**
TOTAL
$43.1mm
$7.65mm
$50.1mm
$100.85mm
^^Expected to close Feb 25, 2014
**Last equity issue price – $6.00 in Feb 2014
Spur has a history of maintaining a very clean balance sheet and, in conjunction with the
above-mentioned acquisition, the company is currently in the process of raising $50
million in non-brokered equity, of which insiders are subscribing to half. Pro forma
(including the acquisition and financing), we see Spur exiting the year with a trailing
D/CF of 0.3x times, positioning the company extremely well for additional acquisitions or
an increase in capital expenditures. Complementing the clean balance sheet is a top tier
cost structure, with a mandate to be one of the lowest cost producers in the basin. With
forecast all-in cash costs of roughly $12.50/boe for 2014, we would say the company is well
on its way.
Where does the company go from here? Anywhere it wants
A clean balance sheet, top tier cost structure, and a focus on plays with lower capital
intensity and fast payouts has given Spur the ultimate flexibility. We would not rule anything
out for the company at this point, including further complementary acquisitions, corporate
sale or yield conversion. Our best guess is the company stays the course in the near term,
focusing on growing light oil production and de-risking its current asset base.
February 18, 2014
LOW-COST OPERATOR WITH A BALANCED PORTFOLIO
Coleville Smiley and Hoosier land base
Coleville Viking offering significantly more Viking upside
than originally thought
Spur land
Farm-in land
2013 Spur well
Producing Viking oil wells
Kerrobert
Kerrobert
Coleville/Hoosier
Coleville
Smiley
Hoosier
Hoosier
Dodsland
Dodsland
Lucky Hills
Lucky Hills
Farm-in adds 150 Viking locations to inventory
Spur recently signed a 19-section farm-in agreement north of its
Hoosier gas unit, which the company believes adds 150 net Viking oil
locations to its ever expanding Viking inventory. Identified as the
Western extension of the Prairiedale pool, the farm-in lands carry a 20well commitment and the land will begin to be de-risked through Spur’s
upcoming winter drilling program with the anticipation for a more active
drilling program this summer. Currently, the lands have 2 successful
horizontal Viking producers which produced roughly 10,000 bbls in
their first year of production. Spur sees this land base being analogous
to Plato, an area in the southeast portion of the main Dodsland play
that continues to see 16 well per section development.
Top tier cost structure – 2013 cash costs
$45
Interest
Total cash costs ($/boe)
$40
Transport
Op costs
G&A
$35
$30
$25
$20
$15
$10
Medium oil assets should not be overlooked
$5
CTA
KEL
CQE
Spur
RMP
MEI
RTK
DTX
RRX
TVE
STE
TOG
GXE
HYX
RE
RPL
PRY
MQL
PXL
SOG
OIL
$0
Consistent growth with increasing liquids share
9,000
Oil and liquids (bbl/d)
8,000
Natural gas (boe/d)
7,000
6,000
boe/d
Spur acquired the Coleville asset at the end of 2011 for $30.4 million
and has subsequently increased production and cash flow from the
asset by greater than 5 times and 25 times, respectively. What we find
more impressive is how the light oil drilling inventory continues to
expand as the company de-risks the asset base. When the asset was
acquired, the company identified 20 Viking horizontal oil locations. To
date, the company has drilled 45 horizontal wells and has another 60
net wells identified in an area that has seen some of the most prolific
Viking oil wells drilled in the greater Dodsland Viking trend. Spur’s
2014 capital program is calling for 18 net wells to be drilled in the play.
2010 to 2014E
CAGR of 44%
5,000
4,000
Through 2014, Spur will direct over $28 million (32% of total 2014
capital) and drill 32 wells on its medium oil assets in east central
Alberta. Spur views its medium oil upside as complimentary to its
growth-oriented Viking assets, as the medium oil wells offer
impressive returns and quick paybacks. The company has identified
12 prospects, of which 5 have been de-risked, and offer a drilling
inventory in excess of 100 locations. With an additional 3 prospects
to be tested through 2014, we see the company’s drilling inventory
continuing to expand. The company ultimately feels each prospect
has the potential for 500 bbls/d of sustained production.
Growth profile continues to ramp up
3,000
2,000
1,000
14Q4E
14Q3E
14Q2E
14Q1E
13Q4E
13Q3A
13Q2A
13Q1A
12Q4A
12Q3A
12Q2A
12Q1A
11Q4A
11Q3A
11Q2A
11Q1A
10Q4A
10Q3A
10Q2A
10Q1A
0
We see Spur currently in the resource capture and aggressive
growth stage of the company life cycle. 2014 production is forecast
to fall in the 7,300–7,700 boe/d range (over 50% oil and liquids),
representing more than 50% growth from 2013. Looking further back
in the company history shows this growth profile is not a new
phenomenon. Over the past 5 years, Spur’s production has yielded
a CAGR greater than 40%; factor in the increased oil weighting and
reduction in operating expenses and the cash flow per debt adjusted
share CAGR is 45%.
Aaron Swanson
[email protected]
403-543-3563
[email protected]
403-695-1401
February 18, 2014
Teine Energy Ltd.
SHARE DATA
Shares o/s (mm, f.d)
Net Debt ($mm)
Dilutive Proceeds
163.4
N/A
N/A
$319
$79.0
N/A
PRODUCTION DATA
% oil
% oil
2013E
7,800
84%
10,000
84%
.
2013E
$81.05
($8.10)
($14.57)
$58.38
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Funds flow ($mm)
FFPS ($/f.d. share)
All in Capex ($mm)
Net debt ($mm)
% drawn
$166
$1.02
$308
$319
$159
2%
Reserves
Proved (mmboe)
P+P % oil
% Proved
YE 2013
58.1
86.5
85%
67%
Dennis Chorney
Chairman
David Tuer
CEO & Vice Chairman
Raymond Cej
President
Jason Denney
COO
Kim Verrier
Interim CFO
Willey Wong
VP Finance
Dwayne Romansky
VP Engineering
Jim Thomson
VP Land
Doug Dent
VP Operations
Melanie Pedersen
VP Exploration
Jim Howe
Mark Jenkins
Adam Vigna
Jeff Donahue
Nicholas Zelenczuk
Director
Director
Director
Director
Director
INSIDER OWNERSHIP (%)^
22%
FINANCING HISTORY (2011-CURRENT)
DATE
OFFERING
VALUE
Q4 2011
Equity
$202mm
Q4 2012
Equity
$155mm
Q2 2013
Second Lien US$300mm
TOTAL CAPITAL RAISED
~$687mm ^^
^ Does not include CPP ownership of 78%
^^ convereted the Second Lien to $C at $0.90 $US/$C
2014E
11,750
88%
15,000
88%
2014E
$86.50
($9.89)
($13.35)
$62.00
$266
$1.63
$255
Last: N/A**
Amassing a fortune in Dodsland
Experienced management team with access to capital
Teine Energy came into existence through a leveraged buyout of Marble Point Energy
in 2010. The company’s current asset base is entirely contained in the Greater
Dodsland area, initially constructed through asset purchases from True Energy and
Baytex Energy. Much like its asset base, Teine’s ownership is highly concentrated as
well, with the Canada Pension Plan (CPP) holding approximately 78% of the
company’s fully diluted shares. Teine is led by CEO David Tuer, who previously held
CEO positions with PanCanadian and Hawker Resources; he is also the current
Chairman of Altalink. In Tenie’s Chairman position is Dennis Chorney, who served as
CEO of Norquay Capital and was also a founder of Argo Energy.
Dominant Dodsland presence
Since taking a toehold in the area in 2010, Teine has consistently expanded its land
position at Dodsland through acquisitions in 2011, 2012, and 2013. As a result, Teine
has become the kingpin in the Greater Dodsland area, holding the largest land
position, at approximately 500 net sections, and is the area’s largest producer at
10,500 boe/d. The company has drilled over 400 horizontal wells to date, pegs
inventory at 2,700 net locations and reports a 2P reserve life index of 23 years.
Committed to being a low-cost operator
Teine takes pride in its operational performance and has continually improved well
economics by perfecting drilling execution, enhancing completion techniques and
grinding down all-in costs. Recent per well all-in costs are approaching $0.80 million,
with significant savings coming from the utilization of pad drilling and downspacing to 16
wells per section. Recent improvements to completion techniques include the utilization
of a wax inhibitor, which adds minimal cost but has had a significant improvement on well
deliverability. Additionally, the company’s contiguous land position is supportive of its lowcost edict, allowing the company to own and control its infrastructure, maximizing
netbacks and reducing downtime. Teine’s oil batteries have combined capacity of 18,000
bbl/d, complemented by 15 mmcf/d of capacity at its gas plants.
Another big year for growth
Through 2014 Teine is planning on drilling 280 net Viking oil horizontals, spending up
to $260 million and furthering its infrastructure with a pipeline into Plato. The company
is looking to add nearly 4,000 boe/d of light oil production through the year, representing
over 40% growth from its 2013 exit production levels.
A few options from here
A strong asset base offering material development upside, strong management
leadership and support from CPP has enabled Teine to quickly move into the
intermediate ranks; the question is where does the company go from here? While we
would not rule anything out, indications suggest the company is ready to move out of
its backyard and leverage expertise in a new core area. Along with this, we think it’s
likely we’ll see the company move into the public ranks.
**no recent trade or equity price
February 18, 2014
LOW-COST, LOW-RISK, HIGH-RETURNING ASSET BASE
Concentrated asset base at Dodsland
Dodsland’s largest landholder and producer
Through a combination of acquisitions and land sale purchases,
Teine has amassed approximately 500 net sections of land, giving
the company the largest footprint in the Greater Dodsland area. The
company estimates 170 sections of its land are prospective for oil,
and carry 2,700 drilling locations. To date, the company has drilled
400 horizontal wells and with current production of 10,500 boe/d,
Teine is also the largest oil producer in the area. The company is
keeping its foot firmly on the accelerator in 2014, with average
production set at 11,500 - 12,000 boe/d and exit guidance pegged at
15,000 boe/d, both representing growth in excess of 40%.
Teine land
Kerrobert
2013 Teine well
Dodsland
Lucky Hills / Avon
Low risk, low cost, high return
Plato
Teine’s concentrated asset base at Dodsland is well suited for its
mantra of low-risk assets and low-cost operations. While Dodsland
may not deliver eye-popping IP rates, the economics are excellent.
Teine is drilling wells at an all-in cost of $0.815 million, with payout
periods firmly under the one-year mark. The company is able to achieve
this thanks to sub $15 operating costs (including transportation),
resulting in industry-leading netbacks in the $58/bbl range.
Forgan
Type curves across regions
90
80
Kerrobert
70
bbl/d
Plato – the proof is in the pudding
Dodsland East
60
Lucky Hills/Avon
50
Teine closed its Plato acquisition in late 2012 and subsequently
drilled 60 wells through 2013. The company operates over 100
horizontal wells in the area, with a type curve that puts Plato at the
top of the class, compared to other areas in Greater Dodsland.
Furthermore, Teine’s 2013 wells at Plato, which were all drilled and
operated by the company, are proving to be significantly better than
the wells it inherited, a testament to the company’s execution.
Economics at Plato are poised to get even better as the company is
planning to build a pipeline to the region. The pipe is expected to be
in place by the end of 2014, with corresponding cost savings
providing a further bump to netbacks.
Plato all
40
Plato 2013
30
20
10
0
1
3
5
7
9
11
13
15
Producing month
17
19
21
23
Top tier netbacks
$70
120%
Operating netback 2013
% liquids
The development potential on this asset base is massive
$50
80%
$40
60%
$30
40%
$20
CQE
PXL
STE
TBE
CTA
SOG
RE
MQL
MEI
GXE
RMP
TVE
HYX
RPL
0%
PRY
$0
TOG
20%
RRX
$10
Liquids weighting (%)
100%
Teine
Operating netback ($/bbl)
$60
In the summer of 2013, Teine drilled 16 horizontal wells on one of its
Plato sections. In five months of public production data, this section
produced over 130,000 bbls of oil and saw peak monthly average
production in excess of 1,700 bbl/d. What we find truly encouraging is
the fact that, on the whole, this section is producing above the Tier 9
type curve for the play, two tiers higher than what the wells are
currently booked at. Taking into consideration that Teine has roughly
170 net sections of Viking oil prone lands, one quickly realizes the
productive capability of this asset base is absolutely stunning.
[email protected]
403-543-3039
Associate: Graham Smith, CFA
[email protected]
403-543-3032
February 18, 2014
Venturion Oil Ltd.
Last: $1.30**
Not their first rodeo
SHARE DATA
Net Debt ($mm) - Q4 2013E
Dilutive Proceeds
77.3 / 92.7
$1.30
$120.5
$1.0
$24.3
$97
2013E
2014E
% oil
600
95%
2,100
95%
% oil
1,800
95%
2,400
95%
Cash flow ($mm)
CFPS ($/f.d. share)
$6.3
$0.07
$27.0
$0.29
Capex ($mm)
$84.6
$41.0
Net debt ($mm)
% drawn
$1.0
$55.0
2%
$15.0
$55.0
27%
Reserves (GLJ - at Oct. 31, 2013)
Proved (mmboe)
% oil
% oil
1P FD&A ($/boe)
2P FD&A
5.56
95%
8.10
95%
$16.46
$11.44
Venturion aims to selectively acquire and efficiently exploit overlooked conventional
high OOIP pools through low-risk development drilling, waterflood and optimization
activities. Particular attention is paid to legacy oil pools with gas caps given the
teams’ technical skill set. This strategy represents a low-cost, low-risk way to grow
production from high-netback oil assets and capitalizes on the sector’s focus on
resource plays at the expense of conventional assets. Through seven transactions,
Venturion now holds an asset base of 98 mmbbls OOIP across 3 core areas, and
without drilling a well, increased production from 1,150 to 1,800 boe/d (88% oil) last
year. The company’s asset base is designed, over time, to deliver low decline
production while spinning off material free cash flow.
At Killam, the company’s largest asset, Venturion holds a 100% WI on 19.75
sections, with 68 mmbbls OOIP (5.7% recovered to date) currently producing 1,180
boe/d of mainly 24 degree API Lloydminster oil.
The Killam asset is well known to Venturion as it was developed by VNRL, sold to
Barrick Energy and later reacquired at attractive metrics. Production has increased
~ 30% from acquisition due to waterflooding and $13 million will be spent in 2014 to
enhance waterflood operations.
At Boundary Lake North, Venturion has a 100% WI in 7.75 sections producing 500
boe/d of 41 degree API light oil from the Halfway formation. $13 million will be
deployed to drill 5 horizontals (4 producers, 1 injector) this year as well as adding a
water source well and upgrading facilities.
21%
DATE
Aug 2012
Founders
2.1
Jan 2013
CS
62.9
July 2013
Rights Offering
12.3
PRICE
$0.22
$1.00
$1.30
TOTAL ($mm)
$0.5
$62.9
$16.0
TOTAL EQUITY RAISED
$1.03
$79.4
77.3
Focusing on the forgotten
The operations
Vincent Chahley
Chairman
Kevin Wesa
Patrick Shore
CFO
Brian Goodfellow
VP Production and Operations
Jim McCormick
VP Land
Gord Moffat
VP Exploration
Chris Colborne
Controller
Justin Ferrara
Corporate Secretary
M. Bruce Chernoff
Director
Jody Forsyth
Director
D. Keith MacDonald
Director
Gary Simpson
Director
Peter Williams
Director
Venturion was founded in late 2012 and is headed by Kevin Wesa, who as
President and CEO, grew Venturion Natural Resources Limited (VNRL) from 130
boe/d to 2,800 boe/d in ~4.5 years, tripling outsider investment. The members of
the management team each has on average over 30 years’ experience in oil and
gas and a history as founders and officers of successful start-ups (VNRL, Teague,
Cabrerra). The Board of Directors consists of Vincent Chahley (Chairman), M.
Bruce Chernoff, Jody Forsyth, D. Keith MacDonald, Gary Simpson, Kevin Wesa,
and Peter Williams.
**Last equity issue price – $1.30 in July 2013
Waterflooded Montney 31 degree API oil is targeted at Worsley, where Venturion
holds 100% WI on 4 sections with 8 mmbbls OOIP and only a 4% recovery factor.
January production is forecast at 250 boe/d with upside via waterflood expansion.
The numbers
A $41 million capital plan for 2014 can be comfortably funded using the company’s
undrawn $55 million credit facility. With a GMP estimated cash flow of $27 million,
Venturion would exit 2014 with ~$15 million in net debt. We believe this capital
could grow production per share by 33% in 2014 exit to exit.
February 18, 2014
EXPLOITING MATURE OIL ASSETS – A DYING ART
Land position
Assets: big oil in place upside
Focused across three core areas, Venturion’s asset base boasts
98 million barrels of OOIP, all conventionally producing highquality reservoirs with a low 6% recovery factor. Employing
conventional reservoir expertise with an emphasis on improving
ultimate recoveries, the company has proven it can grow
production from these underdeveloped pools without the risks,
costs or high decline rates associated with chasing unconventional
reservoirs. Venturion’s strategic advantage comes from its
technical knowledge of conventional pools which require
additional exploitation primarily through engineering.
Killam, AB
Current base production of 1,800 boe/d has continually grown
from the time of acquisition and has inclined 53% while
generating the company a healthy $40/boe netback. The 2014
capital budget of $41 million will be directed towards development
drilling of up to 10 horizontal oil production wells, waterflood
projects and production optimization across the three properties.
The company remains a patient but active acquirer, constantly
looking for assets which meet its mandate of good quality,
conventional, high OOIP oil reservoirs that possess a
combination of waterflooding, well optimization and drilling
upside that can be acquired at discounted prices.
Killam is a core area producing over half of corporate volumes.
This is a legacy Lloydminster pool with a depleted gas cap.
Venturion believes with additional waterflood work the current
5.7% recovery factor could reach 25%, adding ~14 mmboe of
reserves.
Boundary Lake has material resource upside from the Halfway
zone and with additional drilling and waterflood activity a double
to the current 10% recovery factor is possible, adding over 2
mmboe of reserves.
Conservative reserve booking
November 1, 2013 reserves equated to 5.5 mmboe Proved and
8.1 mmboe Proved + Probable, and of those proved bookings,
95% are oil, 96% are producing. Associated P+P FDC of ~$11.2
million represents less than half of Venturion’s projected cash
flow this year. The company generated outstanding F&D costs of
$11.44/2P boe and $16.46/1P boe.
End game
With a low decline, free cash flow generating asset base, we
believe Venturion will be attractive to multiple buyers in the
sector over time.
David Beddis, CFA
[email protected]
403-543-3588
Associate: Andrew Gannon
[email protected]
403-543-3565
February 18, 2014
Verano Energy Ltd.
SHARE DATA
Share Price ($/share)^
Dilutive Proceeds
PRODUCTION DATA
Oil and NGLs (b/d)
Total (boe/d) 6:1
Equivalent growth
FINANCIAL DATA
Revenue ($/boe)
Operating ($/boe)
Cash Flow ($mm)
CFPS (f.d.)
Capex ($mm)
Net Debt ($mm)
D/CF
VALUATION
P/CF
EV/DACF
EV/boe/d
183.0 / 194.8
$0.25
$48.7
($51.8)
$0.0
($3)
2012A
1,353
0.0
1,353
N/A
2013E
2,500
0.0
2,500
85%
2014E
3,200
0.0
3,200
28%
2012A
$90.57
($7.87)
($37.66)
$45.04
$14.77
$7.3
$0.04
($57.3)
($12.8)
NM
2013E
$85.92
($7.56)
($28.71)
$49.64
$22.58
$20.6
$0.11
($26.6)
($51.8)
NM
2014E
$73.00
($6.51)
($25.19)
$41.30
$28.08
$32.9
$0.17
($43.3)
($41.3)
NM
2012A
6.7x
N/A
N/A
2013E
2.4x
N/A
N/A
2014E
1.5x
N/A
N/A
Abdel Badwi
Chairman
David Stangor
Kristen Bibby
VP Finance & CFO
Cesar Ortega
COO
Dave Kimery
VP Engineering
Peggy Hodgkins
VP Exploration
Doug Urch
Director
Stuart McDowall
Director
Su Lian Tay
Director
Leon Teicher
Director
DATE
January-10
CS
30.2
March-10
CS
26.0
December-10
CS
18.5
July-11
CS
35.7
TOTAL EQUITY RAISED
110.4
After several years of transformation, Verano Energy has emerged as a light oil
producer in Llanos Basin, Colombia, with a strong balance sheet and exciting
exploration program slated for 2014. The company was originally formed as P1
Energy following a merger with APO Energy in late 2010. Since that time, the
company has transformed its asset base to focus on the four blocks that it has
today. The company is led by David Stangor, President and CEO, who has
extensive experience in South America, most recently with Occidental Petroleum.
With the company recently renamed Verano, it looks to build through the drill bit
with a $44 mm program (success dependent) planned for this year.
Asset dispositions strengthen balance sheet
2013 was a year that saw Verano dispose of several of its non-core Colombian
blocks. Proceeds from the sales totalled ~$50 million, generating funds to retire its
outstanding convertible debentures and leaving the company with a similar balance
in cash on the balance sheet to fund its upcoming program for 2014, which
includes several exciting exploration prospects to be drilled early this year. Of
note, the dispositions were done at 2P reserve metrics of $35/b (La Punta) and
$42/b (Guachirias), which are excellent metrics for these non-core areas.
High-graded asset base with significant upside potential on
exploration success
The exploration program for 2014 will see Verano drill three of the highest impact
wells since its inception. The Urraca, Mirlo and Carmentea prospects are all
expected to be drilled in 2014, with the first expected to spud in March. All three
prospects are on the LLA-32 block (40% WI) with a mean risked recoverable
estimate in the range of 25 MMB. Initial results from the first well, Urraca, are
expected during Q2/14.
2%
PRICE
$0.50
$1.50
$2.75
$3.00
$1.92
Last: $0.25**
Colombian Private primarily focused in the
Llanos Basin
TOTAL ($mm)
$15.1
$39.0
$50.9
$107.1
$212.1
**GMP bid price – $0.25 in February, 2014
Recent discoveries provide cash flow and expected reserve bump
despite the disposition of producing assets
In the two aforementioned dispositions, Verano sold ~1,200 b/d and 1.4 mmb of
reserves. Despite this, discoveries on LLA-34 (10% WI, non-operated) at Tua,
Tarotaro, Tigana and Tigana Sur have provided production and reserves to replace
those sold, with the company forecasting an increase in reserves in 2013 after
production and dispositions.
Renewed company set for exciting 2014
When all put together, Verano enters 2014 as a much cleaner entity with cash on
the balance sheet, oil production and a high-impact exploration program that will
look to build value for shareholders.
February 18, 2014
HIGH-IMPACT OIL DISCOVERIES AND POTENTIAL
LLA-34 discoveries and prospects
LLA-34 – a roadmap to success
The company’s recent success has been primarily in the LLA-34
Block (10% WI). The block has had several high-impact oil
discoveries, and as of December 2013, total production from the
LLA-34 Block was ~1,300 b/d net. The company and its partners
have also increased new prospect inventory through 3D seismic
acquisition on the Western side of the block. Oil discoveries on
the block in 2013 include:
2014 exploration targets
In June 2013, the Tarotaro-1 discovery well IP’d at 2,239 b/d
of 15.5° gravity oil with <1% water cut. This well was
followed up with several appraisal wells, which successfully
delineated the pool.
In July 2013, the Tua-1 discovery well tested at a rate of
1,723 b/d of 18.2° API oil with less than a 1% water cut from
the Mirador formation with an electric submersible pump.
More recently, Verano announced the successful drilling of
the Tigana-1 exploration well. The well tested at 1,600 b/d
of 15.1° API oil with less than a 1% water cut in December,
2013. The test was conducted with an electrical
submersible pump in the Guadalupe formation.
The company and its partners also recently drilled and
tested the Tigana Sur-1 as a follow-up to the Tigana-1. The
Tigana Sur-1 tested at a rate of 1,597 b/d of 15.3° API oil
with a 0.2% water cut.
2014 exploration program
Corporate asset map
As mentioned, the 2014 exploration program is expected to
expose investors to more than 25 MMB (gross) of recoverable
resource in drilling of three prospects, Urraca, Mirlo and
Carmentea. Each prospect has a relatively high chance of
success (over 50%) and as they are all on the LLA-32 block
where the company has a 40% working interest, providing
significant upside potential for shareholders.
Other assets
The company’s remaining assets are the LLA-17 block (23% WI)
and the La Rompida block (84% WI), where the company plans
minimal capital expense this year.
February 18, 2014
a GMP
Securities L.P. and/or any of its group affiliated companies has, within the previous 12 months, provided paid investment
banking services or acted as underwriter to the company.
b The analyst who prepared this report has viewed the material operations of this company.
c The analyst who prepared this report has visited material operations of the company. The company and/or GMP clients paid all or a
portion of the travel expenses associated with the analyst’s site visit to its material operations.
d The analyst who prepared this report owns this company’s securities.
e Abbreviations used in the equity financing history: CS = Common shares, SR = Subscription Receipts, CDE = Canadian Development
Expense, CEE = Canadian exploration expense, OA = Over allotment, FT = Flow through, and WRTS = Warrants.
This material is based upon information that we consider to be reliable, but neither GMP Securities L.P. (“GMP”) nor its affiliates
warrant its completeness or accuracy. Companies mentioned included in this report may not be reporting issuers, and /or the
companies’ securities or other financial instruments mentioned herein may not be listed on any recognized stock exchange and
therefore may have limited liquidity, reduced regulatory oversight, and face other investment risks beyond those normally associated
with publicly traded companies and their securities. We believe all assumptions, opinions and estimates are accurate as of the date of
this document but are subject to change without notice. The last price shown on this report may be based upon: information provided
by the company, the issue price of the company’s most recently completed financing, the most recent trade price where GMP and/or its
affiliates were a party to, or the bid price on the company’s securities as indicated on GMP’s trading desk. The basis of information on
the “Last Price” can be found on the first page of the company report. Trade prices or bids shown may be resultant from non-arms’
length transactions and/or a reflection of GMP or its affiliates’ principal activity. Therefore, while GMP considers the information
regarding market prices to be reliable, it makes no representations nor warrants that the information contained is complete, timely or an
accurate reflection of current fair value. Past performance is not indicative of future results. GMP does not maintain target prices or
ratings on private companies. This material is not intended as an offer or solicitation for a purchase or sale and any security or other
financial instrument or strategies mentioned herein may not be suitable for all investors. GMP and/or affiliated companies or persons
may as principal or agent, buy and sell securities mentioned herein, including derivative instruments thereon. Griffiths McBurney Corp.,
an affiliate of GMP, accepts responsibility for the contents of this report subject to the foregoing. U.S. clients wishing to effect
transactions in any security referred to herein should do so through Griffiths McBurney Corp. GMP will provide upon request a
statement of its financial condition and a list of the names of its directors and senior officers.
Each research analyst and associate research analyst who authored this document and whose name appears herein certifies that (1)
the recommendations and opinions expressed in the report accurately reflect their personal views about any and all of the securities or
issuers discussed herein that are within their coverage universe and (2) no part of their compensation was, is or will be, directly or
indirectly, related to the provision of specific recommendations or views expressed herein.
GMP Analysts are compensated competitively based on several criteria, including performance assessment criteria based on quality of
research. The Analyst compensation pool is comprised of several revenue sources, including, sales and trading and investment
banking.
GMP prohibits any director, officer, employee or Canadian agent of GMP from holding any office in publicly traded companies or any
office in private companies in the financial services industry. If any director, officer, employee or Canadian agent of GMP does hold
such office in a private company highlighted herein, it will be disclosed.
All relevant disclosures required by IIROC Rule 3400, GMP’s recommendation statistics and research dissemination policies can be
obtained at www.gmpsecurities.com or by calling GMP’s Compliance Department.
© GMP. All rights reserved. Reproduction in whole or in part without permission is prohibited. 145 King Street West, Suite 300 Toronto,
Ontario M5H 1J8 Tel: (416) 367-8600; Fax: (416) 943-6134.

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