Corporate Presentation

Corporate
Presentation
September 2014
Cautionary Statements
Forward Looking Statements. Statements in this presentation may contain forward-looking statements including management’s assessment of future plans, operations,
expectations of future production and capital expenditures. Information concerning reserves may also be deemed to be forward-looking statements as such estimates
involve the implied assessment that the resources described can be economically produced. These statements are based on current expectations that involve numerous
risks and uncertainties, which will cause actual results to differ from those anticipated. These risks include, but are not limited to: the risks of the oil and gas industry (e.g.
operational risks relating to exploration, development and production; potential delays or changes in plans with respect to exploration or development projects or capital
expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and
environmental risks), fluctuation in foreign currency exchange rates and commodity price fluctuation. As a consequence, actual results may differ materially from those
anticipated in the forward-looking statements. Undiscovered Petroleum Initially-In-Place (“UPIIP”), equivalent to undiscovered resources, are those quantities of
petroleum that are estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIIP is referred to as prospective
resources, the remainder as unrecoverable. Undiscovered resources carry discovery risk. There is no certainty that any portion of these resources will be discovered. If
discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of UPIIP
at this time. Discovered Petroleum Initially-In-Place (“DPIIP”), equivalent to "discovered resources", is that quantity of oil that is estimated, as of a given date, to be
contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is
unrecoverable. A recovery project cannot be defined for these volumes of DPIIP at this time. There is no certainty that it will be commercially viable to produce any
portion of the resources.
Non IFRS Measures. This presentation contains financial terms that are not considered measures under International Financial Reporting Standards (“IFRS”), such as
funds flow from operations, funds flow per share, operating netback and working capital. These measures are commonly utilized in the oil and gas industry and are
considered informative for management and shareholders. We evaluate our performance based on funds flow from operations. Funds flow from operations is a non-IFRS
term that represents cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds
flow per share important as they help evaluate performance and demonstrate the Company’s ability to generate sufficient cash to fund future growth opportunities and
repay debt. Working capital surplus includes current assets less current liabilities and is used to evaluate the Company's short-term financial leverage. Operating netback
is determined by dividing oil sales less royalties, transportation and operating expenses by sales volume of produced oil. Management considers operating netback
important as it is a measure of profitability per barrel sold and reflects the quality of production. Funds flow from operations, funds flow per share, working capital and
operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income
or other measures of financial performance calculated in accordance with IFRS.
Test results. There is no representation by Alvopetro that the data relating to any well test results contained in this presentation is necessarily indicative of long-term
performance or ultimate recovery. The reader is cautioned not to unduly rely on such data as such data may not be indicative of future performance of the well or of
expected production or operational results for Alvopetro in the future.
2
Alvopetro’s Vision and Strategy
Our vision is to be the premier
independent exploration and production
company
in
Brazil,
maximizing
shareholder value by being the lowest
cost operator and applying innovation to
underexploited opportunities.
Three-pronged strategy:
• Mature fields
• Shallow conventional exploration
• Large tight oil resource
3
History and Formation of Alvopetro Energy Ltd.
December 2012: Petrominerales Ltd. acquired a 75% interest in seven exploration blocks in the
Recôncavo Basin (Blocks 131, 132, 144, 157, 182, 196, 197) and three mature producing fields (Bom
Lugar, Jiribatuba and Aracaju).
May 2013: Acquired Blocks 170 and Block 183, and awarded Blocks 106 and 107 in the Recôncavo
Basin, and Block 177 in the Tucano Basin in the Brazil 11th Bid Round.
November 19, 2013: Petrominerales acquired the remaining 25% interest in Alvopetro for $9 million.
November 28, 2013: Alvopetro was formed as a result of a plan of arrangement involving
Petrominerales Ltd. and Pacific Rubiales Energy Corp., with Alvopetro capitalized with C$100 million
cash and holding all of Petrominerales' former Brazil assets, including a talented team of technical
professionals in Brazil and certain of the former Leadership Team and Board members of
Petrominerales. Through the completed Arrangement, Pacific Rubiales acquired all of Petrominerales’
outstanding shares, with former shareholders of Petrominerales receiving, for each Petrominerales
share held, cash consideration of C$11.00 per share and one share of Alvopetro.
Alvopetro Energy Ltd., with its current Leadership Team and Board, commenced operations as a new
resource company. Alvopetro was awarded Blocks REC-T 169, REC-T 198, REC-T 255 and REC-T
256 in the Recôncavo Basin in the Brazil 12th Bid Round.
4
Our Opportunity
•
Experienced Leadership Team and Board of Directors
•
Well capitalized - $79.7 million(1) of cash and working capital resources
•
85.1 million shares outstanding
•
148,500 gross acres (147,808 net acres)
•
Highly under-explored area
•
Large “unconventional” resource
•
Shallow exploration potential
•
3 mature fields with NPV10 (AT) 2P reserves of US$21.8 million
•
Compelling fiscal regime
Note: (1) As at June 30, 2014, includes cash, restricted cash (current and non-current) and other working capital resources.
5
Recôncavo Basin, Brazil
•
Total Area: 10,000 sq km
•
First oil drilled (1939)
•
6,000 wells drilled
•
86 producing fields
•
Developed infrastructure
•
PIIP – 6.3 billion bbls
(conventional)
•
OGIP – 3.2 TCF (conventional)
•
Cumulative production –
1.5 billion bbls
•
34 degree API light oil
•
Oil production 41,000 bbl/d
•
Natural gas production 120
mmcf/d
Alberta outline
compared to
Parnaiba Basin
6
Focused Land Base
•
148,500 gross acres (147,808 net
acres)
•
16 exploration blocks
•
1,055 km2 of 3D seismic
•
Initial focus is to demonstrate the
commercial deliverability of Gomo
sands
•
Captured majority of deep Gomo play
fairway in Miranga Low
•
14 wells with Gomo pay
•
Gomo - 1.2 billion bbls of UPIIP(1)(2)
•
Shallow conventional exploration
potential – 9 prospects
•
3 mature fields
6 km
Notes:
(1) Does not include Blocks REC-T 169, REC-T 198, REC-T 255 and REC-T 256 awarded to Alvopetro in the Brazil 12th Bid
Round.
(2) Internal Management estimate.
7
Seismic Processing is Critical
BL-001
~300 MB EUR
BL-001
~300 MB EUR
SW
NE
NE
SW
Pojuca
Marfim
Producing Zone
Pre-Rift
Processed Version from BDEP
Reprocessed 3D
8
Recôncavo Basin Geological Model
Gomo Play Fairway
ANP 4th Bid round - Modified from Braga et al., 1987
9
Comparison of Reservoir Parameters
US Bakken
Canadian Bakken
Cardium
EagleFord
Niobrara
Argentina
Brazil
Elm Coulee
ViewField
West Pembina
South Texas
Colorado
Mata Mora
Reconcavo
Age
Devonian
/Mississpian
Devonian
/Mississpian
Cretaceous
Cretaceous
Cretaceous
Cretaceous
Cretaceous
Target Zone
Middle Bakken
Middle Bakken
Cardium
Eagleford
Niobrara B
Vaca Muerta
Gomo
Lithology
Siltsone
/Carbonate
Sand/Siltstone
Sandstone
Carbonate
Carbonate/Chalk
Silicoclastic
Shale
Sand
Thickness
2.4 - 4.3m
5m
5 - 8m
30 - 50m
20 - 50m
34 - 100m
10 - 200m
Depth
3000m
1,500 - 2,000m
2,000m
1,800 - 3,200m
1,800 - 2,700m
3000 - 3500m
2500 - 3500m
Porosity
3 - 9%
10%
6 - 12%
6 - 9%
5.5 - 10%
4 - 14%
6 - 15%
Permeabilities
0.04 md
0.2 - 0.6md
2 - 10 md
0.07 - 3.0 md
0.01 - 1.0md
0.1 - 5.0md
0.1 - 4.0md
Pressures
0.53psi/ft
0.48psi/ft
0.53psi/ft
0.48 - 0.70 psi/ft
0.48 psi/ft
0.67 - 0.97 psi/ft
0.48 psi/ft
30 Day Average Rates
600 bbl/d
100 - 200 bbl/d
125 - 300 bbl/d
200 - 1,000boe/d
200 - 1,000bbl/d
160 - 600 bbl
To be determined
Oil Saturations
85%
50%
85%
75 - 87%
50 - 70%
75 - 85%
62 - 78%
Resource in Place Per Section
20 - 35mmbbl
4.5 - 5mmbbl
5.0 - 8.0mmbbl
40 - 70mmboe
20 - 30mmbbl
10 - 65mmbbl
20 - 100mmbbl
Recovery Factor
10%
10 - 15%
15%
6 - 10%
5 - 10%
10 - 15%
10 - 15%
Well Costs
$6.0 - 7.0mm
$1.5 - 2.0mm
$3.5mm
$5.5mm
$4.0mm
$8.0 - 12.0mm
$5.0 - 9.0mm
EUR Per Well
50,000 500,000 bbl
100,000 175,000 bbl
175,000 250,000 bbl
500,000 700,000 boe
200,000 400,000 bbl
160,000 700,000 bbl
300,000 650,000 bbl
Note: The Gomo Member of the Candeias Formation has favorable reservoir parameters when compared to other commercial
tight-oil plays.
10
Block 197 and 183: First Phase Drilling
•
197-1 well was drilled, cased and
cemented in Q1 2014.
•
197-1 well discovered 43 meters of
potential net hydrocarbon pay in
several intervals with an average
porosity of 9.5%, using an 8%
porosity cut-off, recovered over 78 meters
of core.
•
197-1 well completion operations
commenced July 28, 2014.
•
We spud our 183-1 well on Block 183 on
July 27, 2014.
183-1 well
197-1 well
Existing oil pools
Existing gas pools
Proposed surface locations
11
Block 197: Preliminary Test Results
•
Perforated and completed the deepest
sandstone interval (3,175 - 3,184 metres),
analogous to several uphole zones.
•
Over a 67 hour test, unstimulated, well flowed
natural gas, at an average rate of 40 mcf/day,
with no water, on an 8/64" choke, using 2 7/8"
tubing, from the Gomo Member of the Candeias
Formation.
•
Test results from this first zone of three to be
tested prove hydrocarbon deliverability on an
unstimulated basis, at depth, in the core of our
play fairway.
•
A major step in proving the commercial viability
of the Gomo resource opportunity.
•
Lower zone not penetrated in offset well, adds
deep basin potential in addition to our originally
defined resource.
12
Brazil: Gas Marketing Environment
Bahia, Brazil - Comparison between Natural Gas Prices for the
Industrial Market (20,000 m³/day) and Fuel Oil
•
•
•
High demand for natural gas in Brazil,
approx. 1.3 Tcf demand/year, 35% imported
gas.
Gas infrastructure nearby Alvopetro’s
operations.
Opportunity exists to sell natural gas
directly to nearby large industrial end
users.
March 2014 Brazil Natural Gas Prices:
Brazil*:
US$12.35/MMBtu
Brazil**:
US$8.19/MMBtu (discounted)
Reference:
Price paid for gas imported from Bolivia: US$10.29/MMBtu
Fuel Oil:
US$13.37/MMBtu
Liquefied petroleum gas: US$11.19/MMBtu
Henry Hub: US$ 4.40/MMBtu
Sources: Brazilian Association of Large Industrial Energy Consumers and Free Consumer, and Brazil Ministry of Energy
*Without discount
** In accordance with regulations, Petrobras may market its natural gas to large gas distribution companies at a price discounted by no more than a
set amount.
13
Bom Lugar-1 Well - Production History
•
•
•
•
Unstimulated vertical well, on-production starting in 1968
Producing interval at 2,412 metres vertical depth
22 metres of net pay with 8.5% average porosity
IP 534 bopd, cumulative production to July 31- 285,771 bbls
Bom Lugar-1 Well: Rate vs. Cumulative Production
1,000
IP Rate: 534 bopd
barrels of oil per day
Well re-activation
(May 2008)
100
10
300,000
250,000
200,000
150,000
100,000
50,000
0
1
Cumulative Production (barrels)
Note: Production day basis used for the Bom Lugar-1 Rate versus Cumulative Productive graph above.
14
Capital Plan and Strategy
Strategy:
•
Develop mature fields
•
Pursue shallow conventional exploration
•
Prove the commercial potential of the Gomo tight oil play
$40 million 2014 capital plan, including up to:
•
2 vertical Gomo wells (197(1) and 183(1))
•
2 workovers
•
2 conventional exploration wells
•
1 well on our Bom Lugar field
15
Accomplishments
Accomplishments:
•
Completed the Alvopetro reorganization from the sale of Petrominerales Ltd.
•
Assembled high-quality team
•
Acquired 25% working interest partner
•
Secured seven new blocks at 2013 Brazil bid rounds
•
Reprocessed available 3D seismic
•
Recovered and analyzed over 78 meters of core
•
Successfully drilled first Gomo well to 3,275 metres – exceeded expectations
•
Spud our second well (183(1))
•
Built an initial 9-well inventory of conventional exploration prospects
Next Steps:
•
Complete testing of 197(1) well
•
Complete drilling of 183(1) well
16
Alvopetro - Early Stage Investment Opportunity
•
Attractive land position and fiscal regime
•
Captured majority of deep Gomo play fairway
•
Large resource opportunity
•
Shallow exploration potential
•
Mature fields
•
Well capitalized
•
Experienced Leadership Team and Board, holding >10% of Alvopetro’s (fully diluted)
shares
•
Strong operating platform in Brazil
•
Operational excellence and innovation
17
Contact us:
Calgary, Canada:
Alvopetro Energy Ltd.
Suite 1175, 332 6th Ave. SW
Calgary, Alberta, Canada
T2P 0B2
Tel: (587) 794-4224
Email: [email protected]
Salvador, Brazil:
Alvopetro S/A Extração de Petróleo e Gás Natural
Rua Ewerton Visco, 290, Boulevard Side Empresarial,
Sala 2004, Caminho das Árvores, Salvador-BA
CEP 41.820-022
TEL: + 55 (71) 3432-0917
Email: [email protected]
www.alvopetro.com
TSX-V: ALV