Corporate Presentation

Corporate
Presentation
February 2016
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 resources is 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 may cause actual results
to differ from those anticipated. These risks include, but are not limited to: the risks inherent in the oil and gas industry, 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 and resource estimates; the
uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; and 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.
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. There is no certainty that it
will be commercially viable to produce any portion of the resources.
Total Petroleum Initially-In-Place ("TPIIP“) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum
that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. There is no
certainty that undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
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.
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 Alvopetro’s ability to have or generate sufficient cash to fund future growth opportunities. 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.
Net Present Value. The net present value of future net revenue attributable to Alvopetro’s reserves and resources is stated without provision for interest costs and general and
administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only
those wells assigned reserves or resources by Sproule or D&M respectively. It should not be assumed that the undiscounted or discounted net present value of future net revenue
attributable to the Alvopetro’s reserves and resources estimated by Sproule and D&M represent the fair market value of those reserves. Other assumptions and qualifications relating to
costs, prices for future production and other matters are summarized herein. The recovery, reserve and resource estimates of the Company's reserves and resources provided herein
are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual reserves or resources may be greater than or less than the estimates
provided herein.
2
Alvopetro’s Vision
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.
The Alvopetro Opportunity:
• Known Proven Assets
• Conventional Exploration
• Discovered Tight Gas Resource
3
Seismic Processing is Critical
• Key to success is reprocessing of
existing data
• Seismic reprocessed across majority of
Alvopetro’s blocks
Before Reprocessing
After Reprocessing
BL-001
~300 MB EUR
BL-001
~300 MB EUR
– 1,200 km2 of reprocessed 3D seismic
– Reprocessed 2D lines show similar
improvement
– All supported by reprocessed seismic
Pojuca
• Critical to all core focus areas in
Alvopetro
– Significantly derisks 22 conventional
prospects
– Provides better understanding of tight
gas resource concept
– Identifies development drilling potential
on our lower risk Bom Lugar field
Marfim
Producing
Zone
Processed Version from BDEP
Reprocessed 3D
Processed Version from BDEP
Reprocessed 2D
PreRift
4
Alvopetro
• Highly under-explored prospective land base
(154,257 acres, 144,243 net acres) and a balanced
suite of opportunities
• Experienced team with a strong track record
• Base Net Asset Value of C$2.22/share(1)
Known Proven Assets:
• 197(2) Gas field – D&M estimates 47 BCF contingent
resource (3C - ALV share)
• 182(B1) oil discovery
• Existing reserves and production on mature fields
• Strong cash position - US$32.2 million
• Materials inventory on hand - US$4.3 million
Conventional Exploration:
• 22 conventional prospects
• Supported by newly reprocessed/high quality seismic
• Partnered with ENGIE 4 blocks at 13th Bid Round
(ALV 65%)
Discovered Tight Gas Resource:
• 2-well pilot project drilled
• Defined deep basin natural gas resource over a large
mapped area in a non-structural setting
1) Base net asset value of US$141.6 million as at September 30, 2015 includes financial resources of US$32.2 million,
2C contingent resources on 197(2) of US$91.3 million (NPV10 before tax as at June 30, 2015), 2P reserves on two
mature fields of US$13.8 million (NPV10 before tax as at December 31, 2014), and equipment inventory for use on
future operations of US$4.3 million.
5
Known Assets – 197(2) Gas Discovery
ALV 197(2) well
•
Top Caruacu
•
TVD
GR
Sw
Tested gas in 3 intervals of Caruacu Formation (tested 15 m
of a total 78 m of potential encountered pay)
– D&M 47 BCF contingent resource, NPV10 $137.1 million (3C share)
– Combined unstimulated flow test rates of 8.7MMcf/d
– ALV 197(2) Average Forecasted Daily Deliverability
• First 30 days – 19.8 mmcf/d
• First 90 days – 15.9 mmcf/d
• First 365 days – 10.2 mmcf/d
Strong gas demand and robust pricing in
Brazil support favourable economics
6
Known Assets – 182(B1)
• Drilled to 2,095m encountering 6 m of net hydrocarbon pay in Agua Grande Formation
• January average production rate of 46 bopd with a 0.9% water cut
• 182(B1) shut-in to undertake enhancements to maximize productivity of the well
ALV-182(B1)
182
Agua Grande oil
Structural closure
Agua Grande time structure
10 ms Contour Interval
7
Known Assets – Bom Lugar Development Potential
• 3 mature fields (Bom Lugar, Jiribatuba and Fazenda Gameleira)
̶
NPV10(BT) 2P reserves of US$13.8 million (as at December 31,
2014)
o Includes only one probable undeveloped location at Bom Lugar
̶
Sproule estimated 465,000 bbl recoverable per well based on BL-1
̶
Existing single well production suggests larger pool
• First well planned 400 m horizontal leg at 2,414 m TVD
• 4+ follow-up locations
Caruacu Time structure
2 ms Contour Interval
• Surface location built
ALV-BL-B1
Loc. ALV-BL-C1
ALV-BLA1
Horizontal
BL1
Block 107
Follow-up locations
8
Conventional Exploration Inventory
• Highly under-explored prospective land base (154,257
acres, 144,243 net acres)
• 22 conventional exploration prospects identified, all
supported by reprocessed seismic
• Two conventional discoveries in 2015 attest to
repeatability of conventional exploration
• Reprocessed seismic derisks all conventional prospects
• Average shallow conventional well cost expected to be
<$5MM (drilled, cased, completed, tested) - significant
cost reductions can be achieved with a continuous
program
• Portfolio of conventional prospects in an area of
developed oil and gas infrastructure, close to national
and state grids, industry, and coastline
9
Conventional Prospects – 170(B1) Prospect
Shale
Diapir
• Targets Marfim and Caruacu Formations updip of
well that tested the oil water contact
• Well depth 2,000 m
• Site construction started in Q4 2015
• Target spud date – February 2016
10
Conventional Prospects – 256(A1) Gas Prospect
• Three way fault closure
• Well Depth 2,200 m
(Caruacu)
• Prospect located on south
side of Mata Catu fault
Erosional unconformity
Block 256
• Environmental permit has
been submitted to INEMA
• Alvopetro owns surface land
for construction of location
(Fazenda Girolandia)
11
Discovered Gomo Tight Gas Resource
• 197-1 Well
– Encountered 43 m potential net hydrocarbon
pay
– Recovered 78 m of core
– Lower zone flowed natural gas at an average
rate of 40 mcf/d (unstimulated)
• 183-1 Well
– Encountered 189 m potential net hydrocarbon
pay (3 zones)
– Recovered over 40 m of core
– Upper Gomo – 96 m of net pay including:
o Thick 46 m interval with average porosity of
10%
o 3 m zone with 14% porosity
– Deep Gomo – 93 m of net pay, average porosity
of 7%
12
Block 197/183 Geobodies
A’
A
Jan2
183-1
197-1
Deep Gas Geobody 5,460 Acres
Tested Gas
A’
3275m
3550m
183-1
•
Defined deep basin natural gas resource over a large mapped
area in a non-structural setting
A
197-1
Gas Geobody Isopach 20 m C.I.
13
Brazil Gas Marketing Environment
20
•
High demand for natural gas in Brazil,
93.3 million m3/day in 2015.
•
In 2015, on average, Brazil imported
32.1 million m3/day of natural gas from Bolivia
•
National gas infrastructure close to
Alvopetro’s natural gas discovery (see below)
•
Petrobras eliminated discounts
18
16
14
12
10
8
6
4
2
0
Petrobras Undiscounted US$/Mmbtu
Petrobras Discounted US$/Mmbtu
Average Price paid by industrial users US$/Mmbtu
Henry Hub US$/Mmbtu
Sources: Brazilian Association of Large Industrial Energy Consumers and Free Consumer, and Brazil Ministry of Mines and Energy (http://www.mme.gov.br/)
14
Gas Sales Options
•
Compressed natural gas
•
Thermal power plants – 125 MW ~ 30 mmcf/d
•
Bahia Gas – local State distribution company
•
Petrobras – tie into national grid
•
Large industrial users, largest consumes ~35 mmcf/d
Power Substation
15
The Alvopetro Opportunity
• Experienced Team
• Well capitalized - US$32.2 million(1) of financial
resources
• Highly under-explored prospective land base
• Balanced suite of opportunities
• Attractive valuation
• Base Net Asset Value of C$2.22/share(2) before
exploration prospects and Gomo tight gas
resource potential
1)
2)
As at September 30, 2015, includes cash, restricted cash and other working capital resources.
Base net asset value of US$141.6 million as at September 30, 2015 includes financial resources of US$32.2 million, 2C contingent
resources on 197(2) of US$91.3 million (NPV10 before tax as at June 30, 2015), 2P reserves on Bom Lugar and Jiribatuba fields of
US$13.8 million (NPV10 before tax as at December 31, 2014), and equipment inventory for use on future operations of US$4.3
million.
16
Appendix
17
Recôncavo Basin, Brazil
•
Total Area: 10,000 square km
•
First oil drilled (1939)
•
6,000 wells drilled
•
86 producing fields
•
Developed infrastructure
•
TPIIP – 6.3 billion bbls
(conventional)
•
OGIP – 3.2 TCF (conventional)
•
Cumulative production –
1.5 billion bbls
•
34 degree API light oil
•
Oil production 41,000 bbl/d
•
Natural gas production 120
mmcf/d
Alberta outline
compared to
Parnaiba Basin
18
Recôncavo Basin Geological Model
ANP 4th Bid round - Modified from Braga et al., 1987
19
Favourable Fiscal Regime
• Royalties
Operating netback targets
Benchmark price
Discount
Sales price
Transportation expenses
Realized sales price
Royalties
Operating expenses
Operating netback
Oil
($per bbl)
Gas
($per mcf)
50.00
(5.00)
45.00
(3.00)
42.00
(4.95)
(6.00)
31.05
6.50
6.50
(0.30)
6.20
(0.72)
(0.93)
4.55
– Payable on monthly production and computed based on the ANP reference
price
– Basic government royalty = 10% on concession contracts and 5% on mature
fields
– Landowner royalty = 1% on concession contracts and 0.5% on mature fields
– Additional royalties = 2.25% on Blocks 182, 196, 197 and 5.0% on Block 170
– Special Participation Tax – Applicable in high production/profit scenarios
• Corporate taxes
–
–
Note: Operating expenses are estimated based on commercial production levels.
General corporate tax rate = 34% of net taxable income
SUDENE benefit available for eligible projects in Bahia state, reducing
corporate tax rate to 15.25%
• Indirect taxes - Most common:
–
–
–
–
–
–
PIS & COFINS – Remitted monthly on revenues and included in the cost of
goods. Combined rate of 9.25%. Offset by PIS&COFINS credits on eligible
expenditures
ICMS – State tax levied on goods – Rates differ by state and self-assessment
must be made if goods are imported from out of state/country
Alvopetro’s ICMS rate is 17%
ISS & INSS – Taxes on services (typically 5% - 12%)
IOF – Financial transaction tax (0.38%)
Various importation taxes (II, IPI, PIS&COFIN, ICMS, CIDE)
20
Oil Marketing
• Petrobras price is based on average monthly
Brent pricing less a discount for Petrobras
operational and transportation costs
̶
Current discount ~$10/bbl net of tax adjustments
• Alvopetro’s current oil production is trucked to
Petrobras Carmo Station or the Dax Refinery
• Dax discount is 5% off Brent
• New projects being implemented and proposed
21
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