a deep dive into south american e&p argentina: change...
TRANSCRIPT
A Deep Dive into South American E&P
Argentina: Change is in the wind
Anish Kapadia
Matt Portillo
Shola Labinjo
Hubert van der Heijden
May 2011
**IMPORTANT DISCLOSURES BEGIN ON PAGE 35 OF THIS REPORT**
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Contents Argentina: The Investment Case ............................................................................................................. 3
Who should you buy? ............................................................................................................................. 4
Map of Key Basins ................................................................................................................................... 4
The Neuquén is heating up ..................................................................................................................... 5
Enhanced recovery ............................................................................................................................. 6
Don’t write off conventional exploration ........................................................................................... 6
Neuquén Basin Geology ...................................................................................................................... 8
Shale Oil Economics .......................................................................................................................... 11
Shale Gas Economics ......................................................................................................................... 12
Tight Gas Potential ............................................................................................................................ 13
Key Unconventional Wells to Watch ................................................................................................ 13
Price Controls ........................................................................................................................................ 14
Pipeline infrastructure .......................................................................................................................... 15
Argentina: Key Pipelines ....................................................................................................................... 16
Oilfield Services ..................................................................................................................................... 17
Refining ................................................................................................................................................. 18
Our view: Prices are going higher!!!! .................................................................................................... 19
Recent M&A Activity ............................................................................................................................. 21
Other Basins & Potential Shale Plays .................................................................................................... 22
Golfo San Jorge Stratigraphy ............................................................................................................. 22
Austral Magallanes Stratigraphy ....................................................................................................... 24
Parana Chaco Stratigraphy ................................................................................................................ 26
Company Exposure ............................................................................................................................... 27
YPF S.A. (YPF: US – $17B market cap – B): ........................................................................................ 27
Apache Corporation (APA: US – $50B market cap – A): ................................................................... 27
Gran Tierra (GTE: US – $2B market cap – B): .................................................................................... 27
Madalena Ventures Inc. (MVN: CN – $183MM market cap – NR): .................................................. 28
Total S.A. (FP: FP – $150B market cap – NR): ................................................................................... 28
Exxon Mobil (XOM: US – $419B market cap – NR): .......................................................................... 28
Americas Petrogas (BOE: CN – $321MM market cap – NR): ............................................................ 28
Petrobras Argentina S.A. (PZE: US – $2B market cap – NR): ............................................................. 29
Antrim Energy (AEN: CN & AEY: LN – $173MM market cap – NR): .................................................. 29
APCO Oil and Gas (APAGF: US – $2.5B market cap – NR) ................................................................. 29
Crown Point Ventures Ltd (CWV: CN – $113MM market cap – NR):................................................ 29
Arpetrol (RPT: CN – $73MM market cap – NR): ............................................................................... 30
Azabache Energy Inc. (AZA: CN – $31MM market cap – NR) ........................................................... 30
Other private operators .................................................................................................................... 30
Appendix: Booming Buenos Aires & more macro ................................................................................ 31
Important Disclosures: .......................................................................................................................... 34
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Argentina: The Investment Case Why Argentina and why now?
We believe the Argentine oil and gas industry is in the midst of a multiyear transformation that is
fundamentally altering pricing for both oil and natural gas in country. Price caps have created an
unsustainable situation that makes the country a significant oil and gas importer over the next
decade. Slowly rising prices of refined products have allowed refiners to bid up prices for crude and
industrial buyers are in some cases permitted to pay above market prices for gas. This leads to our
thesis that the future should bring more favourable pricing to E&Ps.
The government’s persistent intervention in the local oil and gas market has made Argentina’s
energy sector uncompetitive and as a result, hydrocarbon production has not kept up with demand
growth. Decade long price controls and restrictions on hydrocarbon exports have discouraged
energy companies from investing in exploration and in some cases development (gas), causing
reserves and production to fall. When the country began its price cap policy in 2001, the situation
was manageable, as Argentina was a significant net exporter of crude (>400mbopd) and natural gas
(0.5 bcfd). Furthermore, prices for both products on the international market were lower than they
are today (rising costs have magnified subsidies for imports). For a while the country was able to
meet export commitments for gas (primarily to Chile) and was self-sufficient for refined products.
With strong economic growth forecast, the country’s thirst for hydrocarbons is unlikely to weaken,
even in a steadily rising commodity environment. Based on our forecast, oil consumption will
outstrip domestic production by ~33mbopd in 2014 and by ~360mbopd in 2020. Equally important is
that Argentina is already short of key refined products. Although the country currently produces
~676mbopd and has a refining capacity of 635mbopd (operating at >80% utilisation), only 85% of the
crude produced locally is consumed by the domestic refineries, suggesting that the refineries are not
sufficiently complex to process lower quality crude slates produced locally. As a consequence,
Argentina must export lower quality crudes and import certain refined products, such as diesel;
notably, in 2010 Argentina became a net gasoline importer. In 2003, Argentina’s net exports of
diesel amounted to 23mbblpd, by 2010, the country imported 25mbblpd of diesel to augment
domestic supply. In our view, Argentina reached the tipping point in 2009 as the country became a
net importer of natural gas and saw a rising need for diesel imports. As imports have continued to
increase, pricing for both commodities has already begun to rise. Over the last two years, oil prices
have risen from a “capped” price of $42/bbl to a current market price of $58/bbl but assets still look
cheap and the story is still underfollowed creating an ideal opportunity for investment.
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Argentina: Oil Imbalance
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Argentina: Gas Imbalance
Gas Consumption (bcfd) Forecast Consumption (bcfd)
Gas Production (bcfd) Forecast Production (bcfd)
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Who should you buy? Our preferred investment in country is YPF (YPF US), on which we have a $57 price target. Currently
the stock is trading at a discount to our 1P NAV ($46/sh), has significant leverage to rising domestic
crude prices ($1/bbl increase NAV by $1/sh), a high dividend yield (2011 TPHe 8%), solid upside
potential, driven by improved oil recovery on mature fields, and conventional exploration. However,
the biggest near term catalyst will come from the company’s 3mm (net) acres in the Neuquén basin
– an area which is highly prospective for unconventional oil and gas exploration.
Map of Key Basins
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The Neuquén is heating up Located in the central-western
part of Argentina, the
Neuquén Basin spans an area
of 30mm acres and is the
main hydrocarbon producing
region in Argentina with
activity dating back ~100
years. Total oil and gas
production from the basin was
717mboepd in 2009 versus
1,431mboepd for Argentina as
a whole. From a reserves
perspective, the basin has
suffered a pretty serious
relative decline over the past
decade, and as of 2009, the Neuquén basin held only 25% of the oil resources or 33% of the
combined oil and gas resources in the country (implying steeper potential decline in production
unless reserve replacement ratios increase). Reserves stood at 1.6Bboe in Neuquén and 4.8Bboe in
Argentina, at the end of 2009.
Operators in the basin
Based on data from Argentina’s BDIH1, it appears that
acreage holdings in the Neuquén basin are skewed
toward a few companies that operate the majority of
the basin. Out of a 25mm acre area available for
concessions, a 10mm acre area appears to be un-leased
or does not have data on the operator available. Public
operators on the remaining acreage include YPF
(4.2mm gross acres), Petrobras Argentina (2.0mm
acres), Apache (1.7mm acres), Americas Petrogas,
through Midas S.A., (1.3mm acres), TOTAL (0.87mm
acres), Chevron (0.46mm acres) and Azabache Energia,
through Argenta Energia, (0.21mm acres). These seven
firms operate approximately 60% of the Neuquén
acreage currently under contract. Other public
companies that have a stake2 in concessions in
Neuquén are: Crown Point Ventures (0.56mm gross
acres), Antrim Energy (0.31mm acres) and Madalena
Ventures (0.28mm acres).
1 Banco de Datos Integral de Hidrocarburos de la Republica Argentina
2 Based on company data
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Argentina Oil & Gas Production (mboepd)
Austral Cuyana G. San Jorge Neuquén Noroeste
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Enhanced recovery Century long exploitation of oil and gas resources in Argentina’s hydrocarbon provinces has left the
country with a diminishing production base. Further, oilfield surveillance including reservoir
simulation, waterflood surveillance and maintenance, and enhanced oil recovery is 15-20 years
behind the US. While not sexy work, the returns can be some of the best in the business.
Opportunities to workover existing wells abound including installing and optimizing artificial lift and
optimizing ongoing waterfloods. Simple blocking and tackling production and reservoir engineering
should enable companies to increase recoveries. For example, YPF likely owns assets with 24BBoe
original oil in place and we model our recovery factor at 22%. Waterflood maintenance, looking for
bypassed oil, squeezing off thief zones and polymer injection can increase recoveries by 6-8%. If the
industry can arrest declines by only a few percentage points, Argentina can add tens of thousands of
barrels per day of production and could potentially see a 1x-2x uplift in reserves. The next phase of
surveillance is enhanced oil recovery projects including Alkali Surfactant Polymer and CO2 floods
which are currently being piloted in several fields. In aggregate, the successful adoption of enhanced
oil recovery techniques suggests that there is an opportunity for companies to stem declines and
generate value by exploiting some of the, hitherto overlooked or abandoned, conventional
resources. Unsurprisingly, YPF, the country’s largest producer, has been a leader in this regard. YPF
has a long history of rejuvenating declining fields; in the 1950’s the company successfully executed
water flooding programmes in the Golfo San Jorge basin. This was followed by the adoption of
polymer flooding techniques in the 1970’s and 1980’s. More recently, the company has been drilling
infill wells on the El Medanito field, in Neuquén basin, with a view to initiating a second generation
water flooding programme. YPF estimates that water floods can improve recovery factors by 6%-8%.
In the Golfo San Jorge basin, YPF has developed plans to carry out polymer and surfactant injection
pilots at the Grimbeek II and the Sur Manantiales Behr areas. The area, with 22oAPI and 100cP oil,
provides an ideal geological setting for polymerisation supported recovery. YPF believes that
polymer and surfactant injection techniques could improve recovery rates by 12%-16%, double
recovery rate achievable with water flooding. The upside potential created by the adoption of
enhanced recovery techniques in Argentina is validated by YPF’s 100% reserve replacement in 2010,
achieved entirely through enhanced recovery projects.
Don’t write off conventional exploration We believe there is material conventional exploration upside for both oil and gas in country given
the lack of capital investment over the last 10 years. By constraining realized prices and allowing
service and wage costs to rise, the government effectively squeezed margins on operators and
reduced incentives to spend capital outside of maintenance capex; hence production and reserves
are falling. As prices have started to rise over the last two years, margins are expanding and prices
are high enough (on the oil side) to incentivize capital reinvestment into exploration. The industry
has started to bring in modern drilling and seismic equipment. The recent use of 3D seismic has
improved success rates and horizontal drilling is allowing companies to access bypassed/thinner pay
zones on both exploration and mature assets. However, much of the 3D shot in Argentina has been
over existing fields to better understand the reservoirs. Apache and other operators are shooting 3D
in known hydrocarbon basins; this should result in new field discoveries. Perhaps the greatest
potential to unlock resource is being driven by the use of fracture stimulation. Because many of the
wells have been drilled to deeper producing reservoirs there is good well control for shallower
exploration on bypassed horizons.
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Neuquén Stratigraphy
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Neuquén Basin Geology
The basin comprises a Late Triassic-Early Cenozoic formation, as well as marine and continental
siliciclatics, carbonates and evaporates with the majority of the 4000m infill occurring during the
Early Jurrasic-Cretaceous time frame. It is part of an active tectonic system and the final phase of
the Andean tectonic movements produced a series of fold and thrust belts against the western
portion of the basin. Historically, conventional oil and gas exploration has been focused on the
eastern and southern portion of the Neuquén.3
The source rock for most of the conventional oil and gas opportunities in the Neuquén is the Vaca
Muerta and Los Molles shale. These Jurassic age rocks are thick deepwater marine sequences and
are prospective throughout most of the basin however the primary target for shale exploration
currently is the Vaca Muerta. This organic rich, black and dark grey marine shale was deposited in a
reduced oxygen environment and contains Type II Kerogen.4
The figure below is a cross section, from west to east, of the basin showing depth and thickness
changes for various horizons. The deeper targets can reach 16,000ft in the western portion of the
play (gas) and moves to a shallower depth of 8,000ft in the eastern portion (oil). Focusing on the
unconventional potential, the Vaca Muerta thickness varies significantly along the same cross
section from ~1,500ft to ~150ft. The gas window makes up the thickest portion of the play and
transitions to gas condensate and oil toward the basin high.
There are multiple horizons which are productive for oil and gas. The Sierras Blancas (oil and gas),
Troncoso, Avilé and Agrio (oil) are the main producing conventional horizons, the Mulichinco and
Lajas are tight gas prone and the Vaca Muerta is the primary shale target. Even though this is one of
3 The Neuquen basin: an overview; John A. Howell, 2005
4 World Shale Gas Resources: An Initial Assessment
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Sou
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Argentina’s most prolific and mature hydrocarbon basins, it still holds significant exploration upside
as the introduction of modern technology (3D seismic, horizontal wells and fracture stimulation) is
unlocking new play types.
According to data from YPF’s drilling activities in the Neuquén, the Vaca Muerta has reasonably high
permeability due to presence of interbedded sands with porosity ranges between 6% and 10%
(slightly better than the Bakken and similar to the Eagle Ford). With total organic content between
2% and 9%, OOIP is currently estimated at 8-25mmbbls per section, and all important parameters
appear to be very close to known US shales. While we are cognisant that the play is in its infancy,
our confidence is boosted by the hundreds of wells that have penetrated the formation, recent
vertical wells that yielded 200-400bopd IP rates and a few historical analogues that have been
completed in the Vaca Muerta. Again this is very preliminary analysis, as several more wells need be
drilled to delineate the play.
Looking at Vitrinite Reflectance (Ro %)
profile of the basin (diagram on the right),
we hope to gain an idea of where oil, wet or
dry gas prospects are likely to be situated.
The dark red and lighter red areas each
have a Ro of 1.3 and above, indicating a
likelihood of dry gas. Further to the south
and east, the transitioning area (in yellow) is
expected to yield wet gas and NGL (natural
gas liquids); the shallowest part of the basin
(in green) is highly prospective for oil. When
stepping out further to the west, we believe
the thrust below the Andes Mountains has
reached a depth which has caused over
maturation and to the extreme east, the
shallower depth has not reached thermal
maturity (plus the shale thins out). Like
most shale plays, the Neuquén basin will
likely have sweet spots but it is far too early
to make any assumptions on the potential
location.
Sou
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EIA
Vaca Muerta Bakken Barnett Eagle Ford Gas Window Eagle Ford Oil Window Haynesville Marcellus
Hydrocarbon Oil/Gas Oil Gas Gas Oil Gas Gas
Age Jurassic/Cretaceous Upper Devonian Mississippian Cretaceous Cretaceous Jurassic Devonian
Depth (TVD ft) 8,000-11,000 8,000-11,000 6,000-9,000 11,000-12,000 5,000-11,000 10,000-14,000 5,000-8,500
Thickness (ft) 150-1,000+ <140 200-500 200-300 80-175 150-350 50-300
Porosity (%) 6-10 5-7.5 6 9-11 9-11 9-12 6
EUR (mboe) 300-750 200-700 350 1,000 200+ 1,000 700
TOC (%) 2-9 8-10 3-8 3-6 3-6 2-3 4-6
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While there are very few
wells tested to date,
there have been
hundreds of wells drilled
into and through the
Vaca Muerta as
companies have targeted
deeper formations in the
Sierras Blancas. A few of
these wells have even
produced from the Vaca
Muerta under openhole
completion. The well
depicted on the right
initially flowed almost 500bopd and has produced 720mbls
to date. We believe natural fracturing in the region provided
enough permeability for the well to flow naturally and then
the application of fracture stimulation at a later date helped
boost well performance. Given significant basin-wide
faulting we believe it is possible that there will be improved
permeability in field “sweet spots” of the Vaca Muerta due
to natural fracturing.
There is also a substantial amount of tight gas potential in
the Mulichinco, which is shallower than the Vaca Muerta
and the much deeper Lajas formation. YPF announced the
potential 4.5tcf tight gas Lajas discovery and the Mulichinco
has produced some of Argentina’s largest gas fields at Sierra
Chata (1tcf) and Aguada Pichanca (2tcf). Gross thickness on
these formations can reach a couple hundred meters with 4-
6% porosity. Historically wells drilled into the formations
have not been productive but the introduction of vertical
fracture stimulation has opened up a new horizon type in
Argentina.
*This is an example of a log in the Vaca Muerta taken
while drilling a deeper formation in the Sierras
Blancas by Madalena Ventures in the Neuquén basin
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$'000/acre valuation sensitivity to number of wells drilled &IP rate $'000/acre valuation sensitivity to lateral spacing & prospectivity
$1.4 50 100 150 200 $0.0 80 160 240 300
500 ($0.9) ($1.2) ($1.4) ($1.5) 20% $2.0 $1.4 $1.0 $0.9
750 $0.2 $0.3 $0.3 $0.3 40% $1.9 $2.0 $1.6 $1.4
1,000 $1.4 $1.8 $2.1 $2.2 80% $0.9 $1.9 $2.2 $2.0
1,259 $2.6 $3.5 $3.9 $4.1 100% $0.8 $1.5 $2.2 $2.2
$'000/acre valuation sensitivity to long term oil & gas prices $'000/acre valuation sensitivity to well & production costs
$1.4 $50.00 $65.00 $80.00 $95.00 $0.0 $6.00 $8.00 $10.00 $12.00
$3.00 $0.1 $1.8 $3.6 $5.3 $7.00 $3.2 $2.1 $1.0 ($0.1)
$5.00 $0.2 $1.9 $3.6 $5.4 $8.00 $3.0 $1.9 $0.8 ($0.3)
$7.00 $0.2 $2.0 $3.7 $5.5 $9.00 $2.9 $1.8 $0.7 ($0.4)
$9.00 $0.3 $2.1 $3.8 $5.6 $10.00 $2.7 $1.6 $0.5 ($0.6)
Spacing
Well cost
Pro
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Ga
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Wells per annum at peak
IP r
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Oil price
Shale Oil Economics
We have created shale oil models to evaluate the feasibility of the resource play in Argentina, based
on a low GOR analogue from our US coverage of the Eagle Ford. Our analysis suggests shale oil
projects are currently more viable than unconventional gas projects, as spot market pricing can
justify development while gas needs higher contracted prices (~$5/mcf) to work. We model an initial
flow rate of 900bbl/d for horizontal wells (3x the uplift from midpoint on vertical results) with
160/acre lateral spacing and 20% prospectivity. Estimates are based on a long term oil price of
$60/boe, individual well costs of $5-9mm (depends on depth and number of fracs) and operating
costs of $8/bbl. Our base case valuation is $1,400/acre. The tables below contain sensitivity analysis
on value per acre basis (highly dependent on drilling schedule).
So
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Shale Gas Economics
While the gas market deficit
continues to rise, spot market
pricing does not justify
development of unconventional
resources. Rather we believe
operators need access to Gas Plus
contracts to push forward
development. Over time, we feel
comfortable that operators will
be able to continue to push gas
prices higher for industrial users
(current contracts being
negotiated at ~$5.5/mcf). With
that in mind we have created a model for shale gas development. Using a 10mmcfd IP rate, 6bcfe
EUR per well, 160 acre space with 20% prospectivity and a gas plus price of $6/mcf we obtain a
risked NAV per mcf of $0.22, or ~$1,399/acre, for the full development.
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Argentina: Relative Shale Opportunity by Country (Tcf)
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EIA
Page | 13
Tight Gas Potential We believe there is a significant
amount of running room for tight gas
development in the Neuquén. There
are two targeted horizons in the
region which are highly prospective
for exploration; the Mulichinco and
Lajas. The Lajas recently grabbed
industry headlines in 2010, as YPF
successfully drilled 4 vertical
exploration wells into the tight gas
formation, southwest of the Lomo La
Lata field. YPF estimates the
discovery contains ~4.5tcf. The wells flowed 3.5mmcfd on vertical completion, with 6 stage
fracturing; we expect to see a greater uplift in production potential through horizontal completion.
YPF has entered into a joint venture agreement with Vale to initially co-produce up to 55mmcfd as
part of the Gas Plus scheme from the tight gas formation to supply Vale’s potash projects. We
estimate a total development capex of $1B for the initial stage of the project, as production ramps
up to 55mmcfd by 2017 at a growth rate of around 10% per year. Using YPF’s development plan, we
obtain an NAV per mcf of $0.54 for the initial phase of the project, based on a gas plus price of
$7/mcf (price agreed upon for development). Perhaps the best analogue in the US could be
Jonah/Pinedale fields in the US.
Key Unconventional Wells to Watch
Basin Block Well Participant(s) Horizon Well Type Status
Neuquén - - Apache (100%) Los Molles – Shale Gas Horizontal In Progress
Neuquén Lomo La
Lata LLLK.x-2 YPF (100%) Vaca Muerta – Shale Gas Horizontal In Progress
Neuquén Lomo La
Lata Los Gusanos x-2 YPF (100%) Quintuco – Tight Oil Vertical Testing
Neuquén Loma
Campana SOil.X-1 YPF (100%) Vaca Muerta – Shale Oil Horizontal In Progress
Neuquén Cortadera A.E.A Nq. CorS
x-1
Madalena (40%), Apache (60%), Gas y Petroleo de Neuquén
(10%)
Mulichinco – Tight Gas Vaca Muerta – Shale Gas
Vertical Rig en route to
location
Neuquén Huacalera Huax-1
Americas Petrogas (19.5%), Apache (51%), Energicon
(19.5%), Gas y Petroleo de Neuquén
(10%)
Vaca Muerta – Shale Gas Mulichinco – Tight Gas
Vertical In Progress
*HIDENSA, will be carried during the exploration phase
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0
Domestic Customers
Compressed Natural Gas
Distributors
Power Plants
Apache & Pampa Energia MOU
YPF & VALE MOU
Argentina: Natural Gas Prices by Segment ($/mmbtu)
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Price Controls Gas prices in Argentina are explicitly
regulated by the authorities. The
government divides the market into
three segments – the Households &
Small Retailers, Compressed Natural
Gas, Industrial/Power Plants and
Export. Each segment, with the
exception of the export segment, has
regulated a price and producers can
only export gas after internal demand
has been satisfied. Historically, the
domestic gas price ceiling has been set
at ~$2.5/mcf. Furthermore, producers
are mandated to sell a pre-determined
proportion of their total production to
households and small retailers – a segment of the market which pays between ~$0.3/mcf and
$0.5/mcf for gas. Larger and industrial offtakers pay between $0.5/mcf and $2.5/mcf for gas.
Unlike it is with gas prices, the government does not formally control oil prices in Argentina. Rather,
authorities utilise informal mechanisms to maintain control over oil prices, often engaging in a game
of brinkmanship with oil producers and refiners. The shortage of gasoline and diesel in Argentina has
led to an increase in the demand for crude, causing refiners to drive up crude prices. Periodically, the
refiners pass on the crude price increases to consumers by raising pump prices. Depending on the
political situation, the government may allow the refiners to maintain the price increase or may
head to the courts to get an injunction compelling the refiners to freeze the prices. In February 2011,
Shell was forced by the Courts to roll back the 2.6% fuel price increase it had instituted a month
earlier. It is notable that in an election year, the government opted to challenge the price hike,
although similar price increases had been tolerated in the past.
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Argentina: Reported Oil & Gas Price Realisations
Oil Price ($/bbl) Blended Gas Price ($/bbl)
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Gas Pipeline Systems Operator Start Point End Point Location Length (Km) Capacity (mmcfd)
Transportadora de Gas del Sur S.A. Pipeline (TGS) Transportadora de Gas del Sur S.A San Sebastian Bahía Blanca Onshore 7,089 2,600
TGN North Pipeline System Transportadora de Gas del Norte S.A San Jeronima Buenos Aires Onshore 3,917 797
TGN Centro Oeste Pipeline Transportadora de Gas del Norte S.A Beazley San Jeronimo Onshore 2,176 1,125
GasAtacama Holding Pipeline System GasAtacama S.A Coronel Cornejo Taltal, Chile Onshore 1,167 191
Carina- Aries Pipeline System Total S.A. Aries Caoadon Alfa Both 130 450
Tierra del Fuego Pipeline Bridas Corporation San Sebastian Bandurrias, Chile Both 83 71
Methanex SIP Pipeline Sociedad Internacional Petrolera S.A. Cabo Virgenes Dungeness, Chile Both 33 99
Gas Andes pipeline Gas Andes S.A La Mora Santiago, Chile Onshore 465 310
Parana- Uruguayana Pipeline Transportadora de Gas de Mercosur S.A Parana Paso De Los Libres Onshore 440 106
Gasoducto Cruz del Sur Main Pipeline System Gasoducto Cruz del Sur S.A. Punta Lara Montevideo, Uruguay Both 210 180
Oil Pipeline Systems Operator Start Point End Point Location Length (Km) Capacity (mbopd)
Oldelval Oil Pipeline System Oleoductos del Valle S.A. Allen Medanito Onshore 1,379 471
Repsol Oil Pipeline System "Argentina" Repsol YPF, S.A. Lujan de Cuyo Medanito Onshore 1,230 396
Oleoducto Trasandino Pipeline A&C Pipeline Holding Company Puesto Hernandez Concepcion, Chile Onshore 423 115
Brandsen- Campana Pipeline Repsol YPF, S.A. Brandsen Campana Onshore 167 121
Prodcut Pipeline Systems Operator Start Point End Point Location Length (Km) Capacity (mbopd)
Dock Sud- La Matanza Pipeline Repsol YPF, S.A. Dock Sud La Matanza Onshore 34 n.a
La Plata- Dock Sud Pipeline Repsol YPF, S.A. La Plata Dock Sud Onshore 51 80
Lujan de Cuyo- Montecristo Pipeline Repsol YPF, S.A. Lujan de Cuyo Monte Cristo Onshore 655 76
Villa Mercedes- La Matanza Pipeline Repsol YPF, S.A. Villa Mercedes La Matanza Pipeline Onshore 660 31
Campo Duran- San Lorenzo Pipeline Refinor S.A. Campo Duran San Lorenzo Onshore 1,112 41
Pipeline infrastructure Another side effect of a decade
of underinvestment is a
considerable drop in pipeline
utilization. For instance,
country-wide oil production is
down 24% from a peak of
890mbopd in 1998. Similarly,
Argentina’s gas production is
down 16% from a peak of
4.5bcfd in 2006. While, the
degree of infrastructure
underutilisation would vary
across the country’s producing
basins, the decline in output
suggests that there is sufficient capacity in the system to accommodate near term incremental
production and new project developments. In the Neuquén basin, an area that has witnessed
increased exploration activity in the past year and is likely to deliver production growth going
forward, oil production is down 35% from its 1999 pre-crisis level of 410mbopd; similarly, gas
production is down ~19% from its 2004 peak of 3bcfd (511mboepd). Today, Argentina has an
aggregate pipeline length of 23,082km and contributes 19.3% to South and Central America’s total
transmission pipeline network length5. The country’s pipeline network comprises 3,198km of crude
oil pipelines, 2,512km of petroleum product pipelines and 17,372km of natural gas pipelines. The
largest pipeline operators in the country are Transportadora de Gas del Sur S.A (TGS),
Transportadora de Gas del Norte S.A (TGN) and YPF S.A. The table below contains a summary of
Argentina’s pipeline network.
5 Global Data, Argentina Oil Markets, May 2010
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Argentina: Key Pipelines
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Oilfield Services Whereas pipeline infrastructure is
immobile once installed, service
equipment and qualified personnel
have had a chance to go elsewhere,
leading to a service industry that has
dulled over the past decade.
Argentina has kept up a moderate
rate of activity and still is one of the
largest consumers of oil field services
in Latin America but has been
surpassed in importance by countries
like Colombia (which has gone from
23 rigs in 2005 to 110 rigs as of
March 2011). The country currently
has ~80 rigs running or ~17% of the
continent’s activity. Through conversations with local operators, it is our understanding that there is
plentiful supply of skilled labour, older drilling equipment and logging/drilling services for
conventional oil and gas exploration. The pinch point on supply arises as unconventional and
horizontal drilling pick up. Rigs with top drives are in high demand and there is scarcely any frac
equipment in country. In the Neuquén basin, pressure pumping capacity is in extremely short supply.
We believe there is ~75k horsepower currently in place with additional HP being brought in by
Halliburton and new entrants potentially looking to expand in country. However, if we look to the
Eagle Ford as an analogue, the potential growth for service demand could be enormous and would
take years to build out. TPH estimates the Eagle Ford currently has ~40 frac spreads and 160 rigs
running across the play. At 30K HP per frac spread that would be ~1.2mm HP pressure pumping
capacity. As the Eagle Ford reaches full development we could see this number double to 2mm HP.
To be clear, we do not envision the amount of demand reaching these levels in Argentina, but if the
Neuquén proves to be successful, it would not be inconceivable to see demand for newer spec rigs
and pressure pumping equipment increase multiple times over. The other big hurdle for smaller
operators is the learning curve that many US corporations have had to overcome during the last five
years of drilling unconventional resource plays in the states. The entrance of APA, EOG and a
number majors should help accelerate the development process if the play proves successful – “find
it and they will come”. We believe it is important for smaller operators who lack unconventional
drilling experience to partner with one of these larger producers (as many have done).
0
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Argentina: Historical Rig Count
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Refining YPF is the leading refiner in Argentina with
~333mbopd of processing capacity
compared to a market total of 635mbopd.
In 2010, YPF’s refinery utilisation was 93%;
we estimate a country-wide utilisation of
82% in 2010, with diesel and gasoline
accounting for 40% and 20% of refining
yield respectively. Other notable refiners
are Shell (110mbopd) and Bridas
(85mbopd). The three companies account for a combined market share of 83%. The four largest
refineries in country are La Plata (190mbopd), Capsa (110mbopd), Lujan de Cuyo (105mbopd) and
Bridas Campana (85mbopd) which make up 77% of capacity. Crude oil refining activities are
regulated by the Argentine Secretariat of Energy. In 2008, the government instructed companies to
optimize their production in order to obtain maximum volumes from refining assets according to
their capacity. The government further attempted to incentivise companies to invest in the
downstream business through the “Refining Plus” act which entitles companies to receive export
duty credits for investments made in new refineries, expansion of existing capacity or conversion of
capacity. Currently companies are increasing their refining complexity to handle a greater range of
crude slates but there has been minimal investment to date in expansion of existing or new capacity.
The YPF La Plata refinery is the largest refinery in Argentina with a capacity of ~190mbopd and 8.2
on the Solomon index (moving towards 8.8). The refinery, located at the port in the city of La Plata,
is ~60km from the Buenos Aires. In 2010, the refinery processed around 175mbopd; an implied
utilisation of 93%. The feedstock for the refinery comes primarily from the Neuquén and Golfo San
Jorge basins. The refinery is currently undergoing civil works to improve heavy processing capability
by increasing coking capacity by 30% as well as adding a hydrotreater to reduce product sulphur
content to less than 500ppm. The Shell Capsa refinery is the second largest refinery in Argentina
with a capacity of ~110mbopd. The refinery, located in the Matanza basin, is only ~4km from the
centre of Buenos Aires. The crude oil for this refinery is transported by sea from various fields across
the country. While details are limited, it appears Shell has restricted investment (outside of
environmental standards being met) in the asset over the past few years, a contentious issue with
the government in the past. The YPF Lujan de Cuyo is the third largest refinery in Argentina with a
nominal capacity of ~105mbopd and a complexity of 10.7 on the Solomon index (going to 11). Due to
its location in the western province of Mendoza and proximity to infrastructure, it has become the
primary supplier of refined products to the central provinces of Argentina. The refinery currently
processes around ~101mbopd, an implied utilisation of 96%, and receives crude supplies from the
Neuquén and Cuyo basins. The refinery is undergoing minor upgrades to increase capacity by
~2.5mbopd and also to reduce product sulphur content to less than 500ppm.Given that Argentina is
now a net importer of both diesel and gasoline, we would expect the country to continue to run a
high utilisation rate (>90%) going forward. As with other similar initiatives going on in Latin America,
the government of Argentina is focused on reducing emissions from gasoline and diesel. The current
legislation regulates the reduction of sulphur content to less than 500ppm in diesel through July
2012.
YPF Refinery: Representative Product Yield
Diesel fuel
Gasoline
Jet fuel
Base oils
LPG
Fuel oil
Asphalt
Coke
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Our view: Prices are going higher!!!!
Oil creeps to convergence
The combination of increasing
refined products demand and recent
government initiatives, including the
Petroleum Plus, Gas Plus, and
Refining Plus programs, has made it
possible for operators in Argentina
to obtain higher prices for
hydrocarbons. For instance,
upstream oil price realisations have
increased by ~$9/bbl since 2Q10,
and were as high as ~$58/bbl in
March 2011 (versus the “capped”
price of $42/bbl). Further, limited
domestic refining capacity, robust
economic growth and the Energy
Substitution Programme have led to
an increase in demand for distillates
(distillate demand +4% in 2010). As
such, pump prices (ex-taxes) have
risen from $54/bbl for diesel and
$49/bbl for gasoline in 2007 to over $73/bbl for both products in 2010. This has allowed domestic
refiners to pay higher prices for crude oil, whilst maintaining their margins. As a consequence, crude
realisation prices in Argentina have been rising. With international crude prices now well north of
$100/bbl, it is reasonable to believe that pricing in Argentina could eventually reach $70/bbl. This
would significantly increase the value of producing assets in country.
Gas gets a lift
Argentina is already a net importer of natural gas and based on forecasted growth demand will
outstrip in-country production by ~5.2bcfd in 2020. To address the current supply shortfall in the
local gas market, Argentina’s government has resorted to importing gas from a variety of sources.
Today, the measures include purchasing pipeline gas from Bolivia at >$7/mcf and LNG at ~$11/mcf.
The gas is subsequently sold into the local market at ~$2/mcf. Argentina has also initiated the
construction of a new pipeline to deliver gas to the country from Bolivia. The pipeline is expected to
come on-stream in 2014. By 2017, Argentina expects to be importing 970mmcfd of natural gas from
Bolivia, up from of ~163mmcfd (2009 est.) The gas subsidies, as well as other subsidies on diesel and
NGL imports, and the pipeline project is costing the government money; in 2010, the IMF estimated
that authorities in Argentina would spend ~1% of GDP on fuel subsidies by the year’s end. This
equates to ~$3B, or 40% of the country’s projected fiscal deficit for the year (based on 2010 GDP
estimates). The government’s energy bill is expected to continue growing and it is estimated
authorities will spend $4.3B on fuel imports in 20116.
6 Export Development Canada, Argentina Country Overview, 2011
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Argentina: YPF Oil Price Realisation vs. Brent Price
Brent price ($/bbl) Average oil price - YPF Upstream ($/bbl)
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Argentina: Surplus to Deficit
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Government Initiatives: In March 2008, the government of Argentina began introducing reforms to
spur investment in the country’s hydrocarbon industry. These include:
Gas Plus: The “Gas Plus” initiative is designed to encourage natural gas production from new
reserves, new fields and tight gas formations. Natural gas produced under the “Gas Plus”
scheme is exempt from price controls, provided the producer has an agreement with an
industrial offtaker. Under the scheme, producers can sell conventional natural gas at
~$5/mmbtu; natural gas produced from tight formations can be sold at up to ~$7/mmbtu.
Although the mechanics of the program are bureaucracy at its best, the essence is quite
straight forward. If newly discovered reserves, known unconventional resources or already
depleted fields (enhanced recovery) are produced, a firm has the right to have that
production admitted into the program. This is where bureaucrats take over. The E&P has to
first apply to become part of Gas Plus as a company, then apply to have a specific field
admitted and finally the government needs to determine the technical qualification for that
field. Once done, individual wells need specific volumetric meters and monitoring systems
and only that production can be used for Gas Plus. Now the E&P may have potential
offtakers bid up the price for the gas; however the offtakers themselves need to go through
a similar process to be allowed to participate in the scheme. Finally, there is still a price cap
as under no circumstances may the price be higher than that of the prevailing rate on the
Bolivian import pipeline. Bottom line, deals are getting done and the process is moving
forward but slowly.
Petroleum Plus: The Petroleum Plus initiative is a fiscal incentive created to encourage
investments in E&P, with a view to increasing the domestic oil production and reserves. The
program entitles companies which achieve pre-specified oil production and reserve
increases to export duty credits. This allows production companies to export crude, provided
internal demand has been satisfied, and receive a tax credit increasing realized netbacks.
Companies which meet the criteria are allowed to recover 55% – 70% of the retentions as
VAT or tax deductions. The benefits of the programme can be substantial; in 2010,
Petroleum plus contributed ~$200mm to YPF’s earnings.
Refining Plus: Similarly, the refining plus programme rewards refiners for investing in new
capacity and/or for upgrading existing capacity. Such refiners are able to export refined
products at internationally competitive prices, provided the local demand has been satisfied.
Currently a number of refiners are increasing capacity to handle heavier crudes in order to
improve throughput capacity.
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Recent M&A Activity
There have been a number of high profile transactions in Argentina over the past few years, with
valuations ranging from $8/ proved boe to $22/ proved boe. Our reserve valuation is in the middle
of this range – $13/boe. This is based on a long term oil price of $60/boe for an equally weighted
portfolio of proved oil and gas reserves.
In 2010, the largest transaction in Argentina was the CNOOC and Bridas ~$7B acquisition of BP’s 60%
interest in Pan American Energy. The price per barrel was ~$8/boe, based on proved reserves of
858mmboe. In the same year, China Petrochemical Corporation, Sinopec, paid ~$12/boe for
Occidental’s assets in the Golfo San Jorge, Cuyo and Neuquén basins. The $2.5B transaction allowed
Sinopec to acquire 202mmboe of proved reserves in Argentina. Regional players have also shown an
interest in Argentina. In 2009, privately controlled Pluspetrol acquired PetroAndina Resources for
$441mm or $22/boe. The deal gave Pluspetrol the ownership of PetroAndina’s producing assets in
Trinidad and Tobago and importantly, ownership of El Corcobo Norte (ECN) heavy oil field in
Argentina’s Neuquén basin. In 2011, Gran Tierra acquired Petrolifera Petroleum for $193mm, an
implied value of $21/boe, based on the target’s proved reserve base of 9mmboe.
Another indicator of the renewed interest in Argentina is the increase in the farm-in transactions
and license acquisitions by larger E&Ps and integrateds. Notable examples include Apache, Total
and Exxon. Over the years, Apache has built up a 5.2mm gross acre exposure to Argentina’s
hydrocarbon provinces, including a 1.7mm gross acre exposure to the Neuquén basin. In January
2011, Exxon was awarded to two blocks in the Neuquén basin to explore for tight and shale gas.
Shortly after, Total announced it acquired an interest in four Neuquén basin permits with the
objective of exploring for shale gas resources. In addition to the asset sales and corporate
acquisitions, investors have also shown an interest in equity transactions. In March 2011, Repsol sold
3.8% of its interest in YPF directly to Lazard and other investors for $42.40/share and followed this
up with a sale of 7.6% of its interest in YPF (at $41/share) as a secondary offering on to the NYSE
market. Repsol plans to sell down a further 3% of its interest in YPF to retail investors in Argentina
over the course of 2011. Going forward, we expect interest in Argentina to remain strong. We also
expect to see smaller and independent E&P’s, already present in Argentina, to continue selling
stakes to larger E&P and integrateds as the country shale plays are derisked.
Period Buyer Seller Deal TypeReserve/
Resource Type
Transaction
Value ($mm)
Proved Reserves
(mmboe)Implied $/boe
2011 Gran Tierra Energy Inc Petrolifera Petroleum Limited Corporate Conventional 193 9 21
2010
Bridas Corporation; Bridas Energy
Holdings Ltd; CNOOC LimitedBP plc
Asset Conventional 7,060 858 8
2010CNOOC Limited
Bridas Corporation; Bridas Energy
Holdings Ltd Asset Conventional 3,100 318 10
2010 Sinopec Occidental Petroleum Corporation Asset Conventional 2,450 202 12
2009
EPI (Holdings) Ltd
City Smart International
Investment Ltd; TCL Peak Winner
Investment Ltd Asset Conventional 431 n.a n.a
2009 Pluspetrol Petro Andina Resources Inc Corporate Heavy Oil 441 20 22 Sou
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Other Basins & Potential Shale Plays Besides all the activity in the Neuquén basin as previously discussed, a good part of Argentina’s oil
and gas reserves are located in several other basins. Each has slightly different nuances in terms of
geology and other ‘micro’ factors, but our macro view on the pricing regime, potential for enhanced
recovery, conventional exploration using modern technology and shale potential still applies to
these basins. To get an idea of how production and reserves are situated throughout the country,
see the charts based on 2009 data from Argentina’s Institute of Petroleum and Gas below.
Golfo San Jorge Stratigraphy
Golfo San Jorge Overview
Located in Central Patagonia, the basin covers an area of ~42mm acres, comprising onshore and
offshore sections. The onshore section of the basin covers an area of ~30mm acres, and accounts for
30% of Argentina oil and gas production. The basin is characterised by conventional faulted and high
permeability sandstones (at depths of 1,800-9,000ft), which deliver high multiphase fluid flow rates
per well. Typical trap mechanisms in the basin include stratigraphic pinchouts, tilted horst blocks,
faulted anticlines and structural traps. The basin’s first commercial well was drilled in Comodoro
Rivadavia in 1907. Currently, the Golfo San Jorge basin has ~12,630 wells and produces 267mbopd.
Due to its long production history, the majority of Golfo San Jorge’s wells are declining and
producing increasingly larger volumes of water. Today, the basin produces ~3mmbopd of water.
Furthermore, ~41% if the basin’s oil production is achieved through artificial lift mechanisms, with
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Sucker Rod Pumps, (over 9,000 installed) being widely adopted7. Other lift mechanisms include
Progressive Cavity Pumps (over 1,600 installed) and Electric Submersible Pumps (over 1,300
installed). Crown Point Ventures, a company operating the basin, estimates it would cost ~$6.25mm
to drill, equip and tie in five wells in basin. This puts Golfo San Jorge’s average well cost at $1.25mm.
Other significant operators in the basin include APCO Oil and Gas, Pan American Energy, YPF and
Tecpetrol.
Golfo San Jorge Shale Potential
Golfo San Jorge’s shale zone includes the Late Jurassic – Early Cretaceous Aguada Bandera formation
and the Early Cretaceous Pozo D-129 formation. At depths of up to 15,000ft, these formations have
limited penetrations. The Aguada Bandera and Pozo D-129 formations are estimated to contain 50tcf
and 45tcf of risked recoverable resources, respectively.
San Jorge Shale Potential
Formation Aguada Bandera Pozo D-129
Age Late Jurassic/ Early Cretaceous Early Cretaceous
Area (km2) 22,000 13,000
Depth (ft.) 6,500 – 16,000 6,600 – 15,800
Interval Thickness (ft.)
Interval 0 -15,000 800 – 4,500
Organically Rich 1,600 1,200
net 400 420
TOC 2.2% 1.5%
Risked Gas In Place (tcf) 250 180
Risked Recoverable Resources (tcf) 50 180
7 Clemente M. Hirschfeldt, Rodrigo Ruiz, Selection Criteria for Artificial Lift System Based on Mechanical Limits:
Case Study of Golfo San Jorge Basin, Society of Petroleum Engineers, 2009
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Austral Magallanes Stratigraphy
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Austral Magallanes Overview
The 44mm acre basin extends from the southern part of Argentina to Chile’s Tierra del Fuego area.
Conventional gas is produced from the basin’s 6,000ft deep Early Cretaceous Spring Hill formation.
The basin is the youngest of Argentina’s productive province; commercial production from the basin
began in 1942. The Austral basin is gas prone, with Total being the largest gas producer in the basin.
The basin is also primarily responsible for all of Chile’s oil and natural gas production.
Austral Magallanes Shale Potential
We believe the basin’s untested shale zones are the Lower Inoceramus and the Magnas Verdes
Lower Cretaceous formations. The EIA estimates that the Lower Inoceramus and Magnas Verdes
formations each contain 88tcf of risked recoverable resources. Importantly, the Austral Basin is
primed for export, as there are pipelines connecting the basin’s fields to gas deficient Chile. Potential
consumers in Chile include Methanex – a methanol producer. Due to the unavailability of natural
gas, the company’s plant in Chile’s Tierra del Fuego area is operating at 26% of installed capacity.
Methanex requires ~370mmcfd of natural gas to operate at optimum capacity; the company
currently receives ~53mmcfd from its suppliers. A liberalisation of Argentina’s gas market or a
relaxation of gas export controls will provide an opportunity for operators in the basin to generate
low cost revenue by exporting gas, through already installed pipelines, to neighbouring offtakers,
such as Methanex.
Austral Shale Potential
Formation Lower Inoceramus Magnas Verdes
Age Early Cretaceous Early Cretaceous
Area (km2) 50,700 50,700
Depth (ft.) 6,000 – 10,000 6,000 – 10,000
Interval Thickness (ft.)
Interval 400 – 2,000 100 – 300
Organically Rich 600 300
net 300 240
TOC 1.6% 2.0%
Risked Gas In Place (tcf) 351 351
Risked Recoverable Resources (tcf) 88 88
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Parana Chaco Stratigraphy
Parana Chaco Shale Overview
Covering an area of 321mm acres Parana Chaco is a large basin that extends into Paraguay, Brazil,
Uruguay and Northern Argentina. To date, there has been very limited hydrocarbon production
from the basin. On the Brazil side, the surface is blanketed by basalt flows which make seismic data
difficult to gather and interpret, and fewer than 150 wells have been drilled in the basin. Parana
Chaco’s shale zone is believed to lie within the Devonian aged San Alfredo formation. The San
Alfredo formation is estimated to contain 521tcf of risked recoverable resources.
San Jorge Shale Potential
Formation San Alfredo
Age Devonian
Area (km2) 130,000
Depth (ft.) 5,000 – 11,000
Interval Thickness (ft.)
Interval 100 – 12,000
Organically Rich 2,000
net 1,000
TOC 2.5%
Risked Gas In Place (tcf) 2,083
Risked Recoverable Resources (tcf) 521
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Company Exposure
YPF S.A. (YPF: US – $17B market cap – B): Majority owned by Repsol, the former NOC, remains a dominant player in Argentina’s hydrocarbon
sector. In 2010, the company produced ~532mboepd and had proved developed oil and gas reserves
of 982mmboe by the year’s end. YPF’s production and reserves come, almost exclusively, from its
117 exploration and production concessions in Argentina. YPF accounts for ~39% of oil and ~39% of
gas (including NGL) production in Argentina. In 2010, YPF drilled 4 tight gas wells south of its Loma La
Lata field in the Neuquén basin, encountering 4.5tcf of unconventional gas resources in the Lajas
formation. In October 2010, YPF started drilling Argentina’s first shale oil well, SOil.x – 1, at the Loma
Campana block, in the Neuquén basin; the company expects the well to prove the productivity of the
Vaca-Muerta formation as an unconventional liquid hydrocarbon horizon. The well is the first of a 3
well programme, comprising 2 vertical and 1 horizontal wells; it is expected to be completed in 2011.
We anticipate that Repsol will provide an update on the well, on the 12th of May, 2011, during its
1Q11 results presentation. YPF also drilled 4 vertical wells into the Neuquén basin’s oil window; the
wells flowed between 200 and 400bpdand had low GORs. Three of the wells had 4 – 6 stages of
fracturing; YPF expects EURs to be in line with those expected in the Eagleford. YPF continues to
evaluate the results of two tight oil wells, La Caverna x-1 and Dolina x-1, drilled in 2009. The
company is also evaluating tight gas opportunities through a pilot in the Cupen Mahuida area. The
wells in Cupen Mahuida currently produce 3.5mmcfd of tight gas from the Lajas formation. YPF has a
strong land position of 3mm net acres in the 30mm acre Neuquén basin.
Apache Corporation (APA: US – $50B market cap – A): Apache is the largest U.S. independent E&P operating in Argentina. The company produces
~43mboepd, ~7% of its total production, from Argentina. APA has a total of 5mm gross acres (4.2mm
net), across the Austral, Cuyo, Neuquén, and Noroeste basins. Apache is currently developing the
Estación Fernández Oro (EFO) tight gas field in the Neuquén basin. 2011 will see Apache drill 2 new
wells and recomplete 2 existing wells on the field. The EFO field’s reservoirs are located in the Lower
Lajas formation, at a depth of ~13,000ft. New wells on the EFO field typically have an initial flow rate
of 3.7mmcfd of gas and 184bpd of oil. Apache also expects to drill its first well in Argentina’s Cuyo
basin in 2Q11. In the Neuquén basin, Apache is currently drilling a 10 frac stage horizontal well. This
will be drilled to a true vertical depth of 13,800ft and a lateral length of 3,280ft, targeting shale
reservoirs in the Los Molles formation. The company expects to complete the well in May 2011.
Apache estimates it has 20 – 40 Tcf of tight gas in place in the Neuquén basin. Expect an update on
APA’s analyst day – 17th May, 2011.
Gran Tierra (GTE: US – $2B market cap – B): The company is currently producing ~2,300bpd of oil and 4mmcfd of natural gas in Argentina (~16%
of corporate production). GTE is the largest exploration landholder in the Noroeste basin which is
prospective for both conventional oil and gas and recently through a farm out transaction with
Apache plans to explore the Santa Victoria block for gas. The company also has a sizeable position
(0.2mm net acres) in the Neuquén basin where it is currently producing conventional oil from Sierras
Blancas formation. While the company has yet to talk about unconventional potential, proximity to
other producers in the region lead us to believe GTE has prospective acreage for the Vaca Muerta
shale. Overall, GTE has a total of 1.5mm net acres in Argentina.
Page | 28
Madalena Ventures Inc. (MVN: CN – $183MM market cap – NR): The company has three blocks in the Neuquén basin and a combined gross acreage position of
0.28mm acres. All of Madalena’s blocks – Coiron Amargo, Curamhuele and Cortadera, have
conventional, tight and shale resource potential. Madalena (40%) and Apache (60%) will begin
drilling the A.E.A Nq. CorS x-1 well on the Cortadera block in 1H11; the rig is currently en route to
the well location. The well will be drilled to 13,780ft, targeting tight gas prospects in the ~590ft thick
Mulichinco formation and shale gas prospects in the 1,300ft thick Vaca Muerta formation. On the
Coiron Amargo block, Madalena (47.5%), APCO (22.5%) and Roch (20%) plan to drill a horizontal well
into an 80ft –130ft thick section of the Vaca Muerta formation in 2011. The partners will be
targeting an oil prospect and may also elect to drill another well on the block. The partners will fund
100% of the exploration costs. HIDENSA, the provincial oil company, will be responsible for 10% of
the costs incurred during the production and development phase. APCO will fund carry Madalena
during drilling programme, earning the right to increase its interest in the block to 45%. A.E.A Nq.
CorS x-1 follows the CAS X-1 well; which is being completed, the well encountered oil and gas shows
and was cased as a potential hydrocarbon discovery. CAS X-1 was drilled to 11,400ft, penetrating the
Vaca Muerta shale and the conventional Sierras Blancas formation. (Tearsheet available on request)
Total S.A. (FP: FP – $150B market cap – NR): In January 2011, Total acquired an interest in four Neuquén basin permits with the objective of
exploring for shale gas resources. The new permits include a 42.5% interest in the Aguada de Castro
license, a 42.5% interest in the Pampa las Yeguas II license, a 40% interest in the Cerro Las Minas
license and a 45% interest in the Cerro Partido license. In addition, Total owns a 27.3% interest in the
Aguada Pichana and a 24.7% interest in the San Roque licenses. As a result of the transactions, Total
now holds a combined 0.38mm acres in Argentina’s shale gas zone and has a gross acreage position
of 0.89mm acres across its entire portfolio in Neuquén basin. The company is planning to drill a
number of exploration wells in 2011 to test the shale gas play. Total currently produces 28% of
Argentina’s daily gas production (~1bcfd).
Exxon Mobil (XOM: US – $419B market cap – NR): At the end of 2010, Exxon Mobil’s net acreage in Argentina totalled 0.3mm acres. In January 2010,
Exxon was awarded to two blocks in the Neuquén basin to explore for tight and shale gas. Exxon’s
partner in the blocks, Loma del Molle and Pampa de las Yeguas I, is YPF.
Americas Petrogas (BOE: CN – $321MM market cap – NR): Americas Petrogas owns a total of 2mm acres (1.1mm acres on a net basis) across 16 blocks in the
Neuquén basin. In April 2011, the company spud the Huax-1 well on the Huacalera block, in the
Neuquén basin. The well will be drilled to a depth of ~14,000ft and test the Late Jurassic Vaca
Muerta shale formation; the company expects the well to be completed by the middle of June 2011.
The well will also test shallow lower Cretaceous formations, including the Mulichinco and Quintuco
horizons, which have seen previous gas discoveries by other operators. Participants in the Huacalera
block are Americas Petrogas (19.5%), Apache (51%), Energicon (19.5%) and Gas y Petroleo de
Neuquén (10%). Americas Petrogas plans to spend $45mm drilling conventional and unconventional
wells on its acreage in 2011.
Page | 29
Petrobras Argentina S.A. (PZE: US – $2B market cap – NR): The publicly listed Latin American subsidiary of the Brazilian integrated produces ~104mboepd of
from its operations in Argentina, Venezuela, Bolivia, Ecuador and Colombia. Specifically, the
company produces ~86mboepd (~83% of its total production) from its assets in Argentina, where it
has 204mmboe of proved oil and gas reserves. 2011 will see Petrobras Argentina spend $540mm on
its operations in Latin America. A significant proportion of the sum will be spent in Argentina, where
the company plans to continue drilling development wells in the Neuquén basin and to expand its
secondary recovery projects in the country. The company also plans to spend $16mm developing
unconventional gas reserves at its El Mangrullo field in Argentina’s Neuquén basin. Petrobras
Argentina expects to produce 14mmcfd of gas from El Mangrullo within the context of the “Gas
Plus” program. Offshore, Petrobras Argentina (33%) plans to drill the Malvinas x-1 well in 2011.
Other partners in the Malvinas well are Enarsa (33.5%) and YPF (33.5%).
Antrim Energy (AEN: CN & AEY: LN – $173MM market cap – NR): All of the company’s production – ~1.8mboepd (75% gas) on a net basis, comes from its Tierra del
Fuego concession in southern Argentina. Antrim has a 25.78% interest in Tierra del Fuego; other
participants are APCO (25.78%), Roch SA (24.99%), San Enrique (12.62%) and DPG (11.54%). In 4Q10,
Antrim acquired a 50.1% interest in the 0.31mm acre Cerro de Los Leones concession, in the
Neuquén basin. The company has identified a number of Tertiary and Cretaceous stratigraphic leads
at depths between 5,000ft and 8,200ft and intends to shoot 3D seismic over the area in 1H11, with a
view to drilling an exploratory well later in the year. The other participant in Cerro de Los Leones is
Crown Point Ventures, with a 49.9% interest. Antrim has applied for “Gas Plus” pricing incentives for
new gas that will be produced from the wells it drilled in 2010; the company is currently awaiting
approval of its application from the authorities in Argentina.
APCO Oil and Gas (APAGF: US – $2.5B market cap – NR) APCO is a subsidiary of Williams Companies Inc. The company has been operating in Argentina for
over forty years and currently owns assets in the Austral, Neuquén, and Northwest, San Jorge basins.
The company has a net production of ~13mboepd from its assets in Argentina. APCO has proved
reserves of 46mmboe in Argentina, of which 59% is oil and the remainder is gas. In the Neuquén
basin, APCO has 0.25mm net acres, including a 22.5% interest in the Madalena operated Coiron
Amargo block. In the near term, APCO, alongside its partners – Madalena and Roch, plans to spend
up to $6mm drilling 2 wells to test an oil prospect in the Vaca Muerta formation in 2011. By funding
the drilling programme, APCO will increase its interest in the block to 45%.
Crown Point Ventures Ltd (CWV: CN – $113MM market cap – NR): Crown Point is focused on the Golfo San Jorge and Neuquén basins, with a total net acreage position
of ~0.29mm acres. The company plans to drill 12-24 low risk wells on its El Valle Concession, in the
Golfo San Jorge basin, between 2011 and 2012. In April 2011, Crown Point commenced the
programme, drilling the first of 5 development wells on the El Valle Concession. The wells will be
targeting conventional oil resources in the Cañadon Seco, Caleta Olivia and Mina el Carmen zones.
The company expects to drill, test and equip the 5 wells in ~70 days; subject to the complexity of the
completion programme for each of the wells. Crown Point is also evaluating low risk and low cost
exploration plays on its Cañadon Ramírez concession in the Golfo San Jorge basin. In addition to its
conventional resource opportunities, Crown Point continues to assess the potential for shale gas and
Page | 30
oil production from its existing concessions, Cerro Los Leones and Laguna de Piedra, in the Neuquén
basin.
Arpetrol (RPT: CN – $73MM market cap – NR): The company has been operating in Argentina since 2007. Arpetrol currently produces 350boepd
from its assets in Argentina and has 2P reserves of 8mmboe. In addition, Arpetrol owns and operates
an 85mmcfd gas plant in Argentina. The company generates its production from its 100% owned
0.03mm acre Faro Vírgenes concession in the Austral basin. Arpetrol continues to evaluate
development opportunities on its Faro Vírgenes concession, with a view to drilling 3 wells between
4Q11 and 4Q12. The company also plans to drill 2 to 3 shallow wells on the Blanco De Los Olivos
Oriental block, in the Neuquén basin, in 2011. Arpetrol has a 20% interest in the block, with a 50%
back in right at casing point. The Neuquén basin drilling programme is expected to extend the pool
discovered by an earlier exploratory well which flow tested 4.8mmcfd. The company is aiming to
produce 10mbopd from its operations in Argentina by 2014.
Azabache Energy Inc. (AZA: CN – $31MM market cap – NR) Azabache has between 80% and 100% working interest in the Loma El Divisadero, Covunco and El
Corte blocks in Argentina’s Neuquén basin. The company plans to drill at least 3 shale gas
exploration wells on its Covunco and El Corte blocks in 2011. Azabache estimates it has ~200bcf of
unrisked resources on its Covunco and El Corte blocks. Azabache currently has a 100% interest in the
oil prone Loma El Divisadero block, where it is pursuing opportunities to farm out a portion of its
interest.
Other private operators Pan American Energy – CNOOC and Bridas Energy Holdings (BEH), already 40% owners of Pan
American Energy (PAE), acquired the outstanding 60% of the company for $7.06B from BP in 4Q10.
Now equally and jointly owned by CNOOC and BEH, PAE is responsible of ~18% (118mbopd of oil and
123mboepd of gas) of Argentina’s oil and gas production. With the exception of its 50% interest in
the Coiron block in Chile and a 25% interest in the Caipipendi block in Bolivia, PAE is exclusively
focused in Argentina, with in-country reserves of 1.42Bbboe (2009 est.).
Sinopec – The Chinese NOC acquired Occidental’s assets in Argentina for ~$2.5B. The transaction
provides Sinopec with 23 concessions located in the San Jorge, Cuyo and Neuquén basins. In
addition, Sinopec also gained ownership of Occidental’s producing asset in Argentina; estimated to
yield ~44mboepd on a net basis.
Tecpetrol – Privately controlled Tecpetrol is a Latin American focused E&P company. Tecpetrol has
assets in the Neuquén, Noroeste and Golfo San Jorge basins.
Pluspetrol – Pluspetrol is a privately controlled Latin America and Africa focused E&P company. The
company acquired PetroAndina for ~$440mm, in 2009, consolidating its position in Argentina’s oil
and gas space. The transaction provided Pluspetrol with a further 20mmbbl of proved oil and
83mmcf of proved gas reserves in Argentina, as well as further oil and NGL production of 14mbblpd
and further gas production of 64mcfd. The company currently has over 430 producing wells in
Argentina, with a daily production of ~43mmbbl/d of oil and ~340mmcfd of gas.
Page | 31
Appendix: Booming Buenos Aires & more macro Argentina’s economy has
experienced a renaissance over
the past decade after an economic
crisis, which began in 1999
culminating in a sovereign default
in 2002. Driven largely by a weak
Peso, which rendered the
industrial and manufacturing
sectors internationally
competitive, the country’s GDP
has grown ~7.5% per annum since
2002 to ~$300B in 20098.
However, growth has come at a price, as the country continues to battle high inflation driven by
wage demands, rising money supply and subsidised costs (spurring higher demand for goods). Going
forward, it is likely the rising inflation will cause oil and gas companies to experience significant cost
pressure. To be sure, refinery and natural gas plant workers in Argentina recently (May 2011)
announced that their representatives will meet with YPF and Shell to demand a 36% salary increase;
the companies are said to be offering 24% – a substantial increase from a cost perspective. In 2009,
the official consumer price inflation (CPI) rate was 6.3%9. However, it is widely accepted that the
official estimates understate the reality. In 2010, the unofficial CPI rate was estimated to be ~22%.
Overall, Argentina’s hydrocarbon production has been steadily declining over the past decade. The
downward trend is due to the government’s intervention in the hydrocarbon sector which has
spurred declining oil and gas reserves. Recent unconventional resource discoveries and the
government’s introduction of initiatives to spur investment in the country’s hydrocarbon sector
suggest that the trend could be reversed.
Resource Potential: Presently,
Argentina has proved oil
reserves of 2.5Bbbl (4th largest in
Latin America), and proved gas
reserves 13Tcf (4th largest in
Latin America)10. Although, the
country’s reserves have been
declining over the years, the
successful use of enhanced
recovery techniques by
operators in the country suggests that there is significant upside potential if the proper pricing
incentives are in place. In addition to the conventional resource, which has been relatively
underexplored over the past decade, recent exploration activity reveals that substantial
8 The World Bank
9 Economist Intelligence Unit
10 BP statistical Review of World Energy, June 2010
0
100
200
300
400
500
600
700
800
19
98
20
00
20
02
2004
20
06
20
08
20
10
Argentina: Historical Hydrocarbon Consumption
Gas Consumption (mboepd) Oil Consumption (mbopd)
Sou
rce:
BP
So
urc
e: B
P
Latin America Oil & Gas Reserves by Country (Ex-Venezuela)
Argentina - 5Bboe
Brazil - 17Bboe
Colombia - 3Bboe
Ecuador - 7Bboe
Peru - 3Bboe
Trinidad & Tobago - 3Bboe
Page | 32
unconventional hydrocarbon deposits lay in the country’s basin. In 2011, the U.S Energy Information
Administration estimated that ~774tcf of technically recoverable shale gas resources lay in place
within Argentina11. Argentina has the platform for growth, now it needs reform change to liberalize
pricing in order to incentivise investment. It is our belief that these changes will happen sooner
rather than later. Changes made in 2008 are moving things in the right direction and recent “free
market” pricing for oil (from $42/bbl in 2009 to $58/bbl in Mar 10) demonstrates the price disparity
to the international market is unlikely to last.
Government Take: Argentina had operated a stable and competitive oil and gas fiscal regime (prior
to price caps), with a 12% royalty and 35% corporate tax rate. Contracts are governed by
“Concession Agreements” with the Federal and Provincial governments exercising authority over
taxation. In Argentina, the ownership of onshore hydrocarbon reserves resides with the provincial
authorities. Provincial authorities impose a sales tax of ~2% on gross revenues for upstream
companies, a stamp tax on commercial contracts - typically between 1% and 4% of transaction value,
and a production royalty equivalent to 12% of the wellhead value of the produced hydrocarbons; an
additional 3% royalty is payable on some lease extensions. All provincial taxes are treated as
production costs and are tax deductible. Separately, the federal government generates revenue
from both onshore and offshore oil and gas activities through a general corporate tax, at a rate of
35%. We estimate that for many expiring concessions, companies will be able to renegotiate a new
lease for slightly higher royalty rates, paying between 2-3% above an existing contract, plus a signing
bonus upfront. These terms are relatively favourable as the government would like to keep
production uninterrupted and margins are still relatively thin for capital reinvestment on most
projects.
Argentina’s recent economic growth has
been accompanied by an increasing demand
for hydrocarbons; however the country’s oil
and gas production declined over the same
period. The declines are attributable a
perverse energy policy, which creates
artificially low hydrocarbon prices and deters
exploration and production companies from
investing in the country’s hydrocarbon
sector. Today, the country spends ~ $3B a
year purchasing and subsiding LNG imports
as well as natural gas from Bolivia. In
addition to the gas imports, Argentina’s is set
to continue importing increasingly large amounts of diesel in order to satisfy local demand.
According Cammesa, a public-private electricity wholesaler in Argentina, the country “will import 2.3
million cubic metres of diesel to supply electricity power plants at a cost of some US$112 million a
month”. The situation is evidently unsustainable. Argentina elects a new president in October 2011
and it is likely that regardless of the administration, prices will be liberalised, at least partially, in
order to control public spending on energy.
11
EIA, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, April 2011
So
urc
e: W
orl
d B
an
k, E
DC
, EIU
, TP
H
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
19
89
19
99
20
08
20
09
20
10
201
1E
Argentina: Fiscal Deficit & Energy Bill
Fiscal deficit (% of GDP) Fuel & Energy Bill (% of GDP)
Page | 33
Hydrocarbon Regulation: With the exception of offshore exploration and production activity, which
is exclusively overseen by the federal government, all exploration and production activity in
Argentina is overseen by provincial authorities. The provincial authorities are responsible for
conducting acreage licensing rounds and awarding concessions as well as collecting royalties from
operating companies.
State Participation: In 1999, the government of Argentina completed the decade long privatisation
of the former NOC, Yacimientos Petrolíferos Fiscales (YPF), selling a controlling stake to Repsol.
However in 2004, the government created, Energia Argentina (ENARSA) with a mandate to
participate in all segments of the hydrocarbon value chain, particularly the underexplored
continental shelf. ENARSA is the sole concessionaire of all offshore acreage that had been not
awarded prior to its creation. Going forward, the company expects to develop its offshore acreage in
partnership with international oil companies.
Capital Markets: Argentina’s main exchange, the Bolsa de Comercio de Buenos Aires (BCBA) was
founded in 1854. Today, there are 105 listed issues on the exchange, with a total equity
capitalisation of ~$505B and an average daily trading volume of 1.8B shares at a value of $600mm
per day12.
Financial Markets: The Banco Central de la República Argentina (BCRA), established in 1935, is the primary regulator of financial and economic activities in Argentina. The bank is also responsible for maintaining exchange rates, issuing currency, setting interest rates and managing inflation. Currency Controls: Capital flows in and out of Argentina must be registered with the Central Bank.
Generally, inbound capital may not be transferred out of the country for 365 days after entry and
proceeds from transactions involving foreign capital must be paid into a local account. Furthermore,
there is a reserve requirement on transactions involving foreign capital; 30% of the transaction
amount must be deposited in a local non interest paying dollar denominated account for 365 days.
Importantly, foreign capital aimed at energy infrastructure is exempt from the deposit requirements.
To control the supply of dollars in the local market, exporters are obliged to deposit U.S dollar
proceeds in local banks within 10 days of receipt of payment. Also, institutional investors are
restricted to total currency transactions of $2mm per month.
12
RBC Dexia
Page | 34
Important Disclosures: The following Tudor, Pickering, Holt & Co. affiliates have contributed to this research report: (1) Tudor, Pickering, Holt & Co. Securities, Inc., and (2) Tudor, Pickering, Holt & Co. International, LLP. Foreign Research Analyst Disclosure: Anish Kapadia and Shola Labinjo contributed to this research report. Mr. Kapadia and Mr. Labinjo are employed by Tudor, Pickering, Holt & Co. International, LLP in the United Kingdom and are not registered/qualified as a research analyst with FINRA. Mr. Kapadia and Mr. Labinjo are not associated persons of Tudor, Pickering, Holt & Co. Securities, Inc. and as such are not subject to NASD Rule 2711 restrictions on communications with subject companies, public appearances and trading securities held by a research analyst account. Analyst Certification (U.S.A.): We, Anish Kapadia, Matt Portillo, Hubert van der Heijden and Shola Labinjo, do hereby certify that, to the best of our knowledge, the views and opinions in this research report accurately reflect our personal views about the company and its securities. We have not nor will we receive direct or indirect compensation in return for expressing specific recommendations or viewpoints in this report.
Important Disclosure: The analysts above (or members of their household) do not own any securities mentioned in this report.
Analysts’ compensation is not based on investment banking revenue and the analysts are not compensated by the subject companies. In the past 12 months, Tudor, Pickering, Holt & Co. Securities, Inc. has not received investment banking or other revenue from the companies mentioned in this report. We intend to seek compensation for investment banking services from the companies we follow in the next 3 months.
For detailed rating information, distribution of ratings, price charts and disclosures regarding compensation policy and investment banking revenue, please visit our website at http://www.tudorpickering.compdisclosure/ or request a written copy of the disclosures by calling 713-333-2960 (United States).
Tudor, Pickering, Holt & Co. uses a Buy, Accumulate, Hold, Trim and Sell rating system.
Opinion Key:
Buy - The stock should be purchased aggressively at current prices. The stock has among the best combination of risk/reward and positive company specific catalysts within the sector. Stock is expected to trade higher on an absolute basis and be a top performer relative to peer stocks over the next 12 months.
Accumulate - The stock should be purchased consistently at current prices. The stock has above average risk/reward and is expected to outperform peer stocks over the next 12 months.
Hold - Do nothing with the stock at current prices. The stock has average risk/reward and is expected to perform in line with peer stocks over the next 12 months.
Trim - The stock should be sold consistently at current prices. The stock has below average risk/reward and is expected to under perform peer stocks over the next 12 months.
Sell - The stock should be sold aggressively at current prices. The stock's risk/reward is skewed to the downside with possible negative company specific catalysts or excessive valuation. The stock is expected to trade lower on an absolute basis and be among the worst performers relative to peer stocks over the next 12 months.
Price Target Methodology:
Price targets are developed using the stock's forward price-to-earnings ratio as a primary valuation metric. Target prices are typically 20-25X forward price-to-earnings for oil service companies, with validation of this range is driven by examination of EBITDA multiples and price-to book value metrics. For offshore drilling companies, price targets are developed using 10-15X multiples of upside earnings. These are calculated using our assumptions of normalized day rates and utilization. Validation of our target is done by examining net
Page | 35
asset values, and private market transactions. There is a risk that the stock will never reach the price target. These risks include market conditions and unforeseen events that may affect the company's business.
For E&P businesses, we value proved reserves by assessing the net present value of current production. For probable and possible reserves, we attempt basin-by basins analysis of the reserves, with the key variable being the timing of drilling.
Investment Rating Distribution: (as of March 31, 2011) Coverage Universe -
Stock Rating Category Count % of Total
Overweight / Buy 65 71%
Equal-weight / Hold 23 25%
Underweight / Sell 4 4%
Investment Rating Distribution of Investment Banking Clients: (as of March 31, 2011) Coverage Universe -
Stock Rating Category Count Percent
Overweight / Buy 9 64%
Equal-weight / Hold 4 29%
Underweight / Sell 1 7%
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