LatAm Energy
T W I C E M O N T H LY
NEWS, PRICES AND ANALYSIS FROM LATIN AMERICA AND THE CARIBBEAN
VOLUME XVIII, 6, 24 MARCH 2015
A refined perspective
Failure to complete refinery projects in Latin America will
leave the region increasingly dependent on US imports
Latin America’s grand ambitions to
expand and build refineries have fizzled,
guaranteeing a future of rising imports,
mainly from the US Gulf coast.
Not long ago, Latin America was
abuzz with refinery plans. Brazil alone
had well over 1mn b/d of new capacity on the drawing board. But a lack of
financing and commercial logic swept
most of the plans into the dustbin. The
fall in oil prices since mid-2014 will probably keep them there.
State-controlled Petrobras aimed to
build four greenfield refineries to absorb
its growing sub-salt crude flows and
close a costly domestic supply gap.
Brasilia wanted partners. The only one
that signed up with a 40pc stake in
the 230,000 b/d Abreu e Lima refinery,
Venezuela’s state-owned PdV, could not
foot its share of the $20bn bill.
Petrobras nearly completed the first
115,000 b/d phase of the refinery on its
own late last year. But delays to the installation of an emissions unit are capping
runs, and the second phase has been
shelved. Construction of the 165,000
b/d Comperj refinery, more than 80pc
complete, is idled. Like Abreu e Lima,
Comperj was one of the Petrobras projects subject to inflated contracts in a gargantuan corruption scheme (see p3). Any
hope of Petrobras building the Premium
refineries, with a combined capacity of
900,000 b/d, has been dashed.
In Ecuador, financing is the main
obstacle to building the 200,000 b/d
Pacific refinery shared by state-owned
PetroEcuador with 51pc and PdV with
49pc. A plan to bring in China’s stateowned CNPC with a 30pc stake, out
of PdV’s share, has not materialised.
In Colombia, budget cuts have stalled
the upgrade of Ecopetrol’s 245,000 b/d
Barrancabermeja refinery.
Other state-led refinery projects with
PdV, including ones in Jamaica, the
Dominican Republic and Nicaragua, have
evaporated. But there is some progress.
Upgrades at PetroEcuador’s 110,000
b/d Esmeraldas, Ecopetrol’s 78,000 b/d
Cartagena and state-owned PetroPeru’s
65,000 b/d Talara refineries are advancing despite delays. Even Costa Rica’s
state-run Recope is reviving a 65,000 b/d
project with CNPC to replace its fire-hit
25,000 b/d Limon refinery.
Vasconia
$/bl
Vasconia
$/bl
110
100
90
80
70
60
50
40
Jan 14
Apr
Jul
Oct
Jan 15
Mexico natural gas production mn ft3/d
Mexico: Gas production
mn ft³/d
1,900
1,800
1,700
1,600
1,500
Jan 14
Apr
Jul
Oct
Ecuador crude output
’000 b/d
Ecuador: Crude output
’000 b/d
570
560
550
540
530
Lower costs
The decline in oil prices has cut the cost
of fuel imports in Latin America. This has
alleviated the trade balance pressure
that helped bring about many of the
refinery projects. And where the market
is allowed to function, the oil price drop
has cut pump prices.
Yet while gasoline or diesel imports
now cost a lot less, Latin America still
needs far more of them than it used to —
and not just because of rising demand.
The region’s trickle of new processing
capacity in recent years pales beside the
loss of operational capacity, especially
in Venezuela. And the region’s ageing
refineries have failed to keep pace with
tightening fuel specifications. Products
imports, mainly from US refiners, will keep
rising regardless of the oil price.
520
Jul 13 Jan 14
Apr
Jul
Oct
Jan 15
Crude
$/bl
23 Mar
±9 Mar
Vasconia fob
49.73
-2.40
Castilla fob
44.98
-2.40
Maya USGC
45.00
-2.04
Olmeca
53.07
-2.09
Isthmus
51.48
-1.58
WTI Cushing
46.85
-3.15
ANS
53.50
-1.99
Gasoil ¢/USG
23 Mar
±9 Mar
USGC
166.27
-12.21
172.39
-0.21
44.90
-1.95
517.94
-38.68
Products
Gasoline ¢/USG
USGC
Fuel oil $/bl
USGC
Biodiesel $/t
Argentina
‘Decisions about the location of critical infrastructure are not taken by private actors’ —
Dominican Republic energy minister Pelegrin Castillo (see p11)
© Argus Media Ltd
www.argusmedia.com
Argus Latam Energy
24 March 2015
Contents
Editorial: A refined perspective
1
Petrobras sub-salt plans at risk
3
Petrobras corruption probe widens
3
Latin American highlights
l Mexican shale reserves attract interest
Potential investors continue to show an interest in
Colombian oil association calls for reforms
4
Future of Colombia’s Rubiales field uncertain
4
Pipeline boosts Peru’s growth potential
5
Mexican shale reserves attract interest
6
Pemex to bid in upstream licensing round
6
PetroCaribe exports drop
7
Buenos Aires reduces tax exemption on fuel imports
7
Venezuela’s Perla awaits platform delivery
8
members last year, down from 220,000 b/d a year earlier,
China lends Caracas another $5bn
8
Venezuela’s energy ministry says (see p7).
Mexican gas network to expand
9
Mexico’s massive shale reserves, even though the
sharp decline in oil prices has raised questions over
their viability. The drop in oil prices since mid-2014 has
forced Mexico to delay parts of its first-ever licensing
round (see p6).
l PetroCaribe exports drop
Venezuela’s state-owned PdV reduced its crude and
products exports to PetroCaribe members by nearly a
fifth last year. PdV exported 178,000 b/d to PetroCaribe
Ambitious Ecuador oil agenda in need of funds
10
Changes to Argus Latam Energy
DomRep minister rejects southern LNG terminal
11
This is the final issue of Argus LatAm Energy. Argus will
incorporate ALE into a new service called Argus Latin
America Energy from next month. ALAE will continue Argus’
coverage of Latin American oil and natural gas markets, as
well as reporting on and analysing regional power markets.
In brief
12-13
Prices14
Output data — Ecuador
15-16
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Page 2
Argus Latam Energy — Brazil
24 March 2015
Petrobras sub-salt plans at risk
Brazil’s state-controlled Petrobras is struggling to sustain its
sub-salt development plans as the fallout from a corruption
scandal engulfing the firm escalates.
Four 150,000 b/d floating production, storage and offloading (FPSO) units earmarked for the prolific Lula field will
each be delayed by at least a year, says Portugal’s Galp,
Petrobras’ partner along with UK firm BG in the Santos
basin’s BM-S-11 block. The affected units are P-66 and P-67,
due on stream in 2016, and P-68 and P-69, due on stream in
2017. Galp says its estimate is conservative, based on the
financial problems affecting Petrobras’ scandal-hit suppliers.
The delays stem from the collapse of Brazilian engineering firm Iesa, which had been responsible for the construction of gas compression modules that are due to be integrated at the four platforms.
Petrobras has relaunched the tender for the modules,
and is assessing the impact that the cancellation of the
contract will have on its schedule. BG maintains that the
FPSO units at Lula planned for 2016 are on track, but will not
comment on those for 2017. Petrobras owns a 65pc stake in
BM-S-11. BG has 25pc and Galp 10pc.
Capex in hand
Under Petrobras’ current plans, its production from sub-salt
fields is expected to reach 1mn b/d by 2017 (ALE, 11 March
2014, p3). The firm’s share of sub-salt production hit a record
555,000 b/d on 26 February. But Petrobras has cut around
$13bn from this year’s capital expenditure (capex) budget of
$44bn and will shed assets in response to sharply lower oil
prices (ALE, 10 March, p5). It has yet to announce changes
to its 2020 domestic crude output goal of 4.2mn b/d, but will
release its new 2015-19 business plan later this year.
Iesa is one of a number of mostly Brazilian construction
and engineering firms alleged to have participated in a cartel
that inflated contracts in the knowledge that a certain percentage would be diverted to top-ranking politicians from Brazil’s
ruling PT party and its coalition allies. Petrobras has temporarily banned the firms, including Iesa, from bidding for future
contracts (ALE, 24 February, p4).
Shipbuilding
Brazilian shipbuilder Sete Brasil is not one of the companies
that Petrobras has banned from bidding for future projects,
but the firm is facing a rapidly worsening financial predicament. The company has a contract for the construction of 29
drilling ships earmarked for sub-salt fields at a cost of $25bn.
UK bank Standard Chartered notified Sete on 20 March that
it is seeking early repayment of around $250mn in loans.
And Brazilian shipyard Estaleiro Atlantico Sul last month cancelled a $6bn contract with Sete, after the firm failed to keep
up with its payments.
Sete says it is waiting on a 10bn real ($3.1bn) bridging
loan from Brazil’s state-backed development bank Bndes.
Petrobras owns a 5pc stake in Sete. Pension funds and
Brazilian banks hold the remaining 95pc.
Petrobras’ sub-salt production was dealt a blow on 18
March when the 180,000 b/d P-58 FPSO unit went off line.
Petrobras says P-58, which was responsible for around
88,700 b/d at the Campos basin’s Parque das Baleias complex in January, went off line for scheduled maintenance
aimed at improving efficiency. But union leaders say production halted because of safety concerns. It is not clear when
the unit will restart.
Scheduled maintenance at the P-58 facility in February
contributed to a drop in Petrobras’ monthly domestic production to 2.15mn b/d that month, 2pc lower than January output
and more than 3pc down on a 2.21mn b/d production record
set in December.
Corruption probe widens
Federal prosecutors have widened their
investigation into a corruption scandal
centred on Brazil’s state-controlled oil
company Petrobras.
The treasurer of Brazil’s ruling PT
party, Joao Vaccari Neto, was arrested
on 16 March and charged with corruption
and money laundering offences. Vaccari
Neto is alleged to have been responsible
for ensuring that funds siphoned off from
Petrobras appeared as legal donations
to PT and specifically to President Dilma
Rousseff’s 2010 election campaign.
Federal prosecutors are investigating
around 50 senior Brazilian politicians.
And in Switzerland, the attorney-general has identified 300 accounts suspected of being linked to the Petrobras
scandal. The Swiss authorities have frozen $400mn in assets as part of an investigation into unnamed individuals, and
intend to return $120mn to Brazil.
The corruption scandal is increasingly
weighing on Rousseff, who on 18 March
announced a series of new anti-corruption measures, such as adopting new
rules on illegal campaign donations and
expediting the confiscation of graft-linked
assets. Rousseff was Petrobras chairwoman in 2003-10, and energy minister
in 2003-05, but denies any knowledge of
the kickback scheme.
But according to a Datafolha poll
this month, 84pc of respondents believe
that Rousseff knew corruption was taking
place at Petrobras while she was at the
firm. Some 1mn people marched in cities
across Brazil on 15 March in support of
efforts to impeach her.
© 2015 Argus Media Ltd www.argusmedia.com
Page 3
Argus Latam Energy — Colombia
24 March 2015
Oil association calls for upstream reforms
Colombian oil producers association ACP is lobbying the government to take “drastic” measures to avert a looming upstream
crisis. Colombia will not be able to sustain production of above
1mn b/d because of a significant decline in exploration in the
first two months of this year, the association says.
Oil companies conducted just 160km of seismic surveys
in January and February, a four-year low, and drilled just
six wells, down from 20 a year earlier. Barring a rebound in
exploration, production will sink below 700,000 b/d by around
2021, ACP forecasts.
Even though Colombia produced approximately 1.03mn
b/d of crude in February, the finance ministry said on 17
March that the energy and mining section of the economy
contracted by 0.2pc last year. This was mainly the result of a
1.4pc decline in the country’s oil production compared with
a year earlier.
Colombia’s GDP grew by 4.6pc last year, the finance ministry says, following a 4.9pc expansion in 2013. But the outlook
for this year appears less rosy. Colombia’s central bank projected in January that GDP will grow by 2-4pc this year, with
3.6pc the “most likely” scenario, partly reflecting lower investment in the oil sector.
Even though security for oil and gas companies has
improved this year, with just two rebel attacks in the first two
months compared with 27 a year earlier, community blockades
persist, ACP says. The were 64 blockades in January and
February, compared with 62 a year earlier, it says. Blockades
lasted for three days on average last year.
Environmental licence approvals continue to take about 15
months, ACP says, despite government efforts to accelerate
the process. The government pledged in September last year
to cut the timeframe for obtaining environmental licences to
around five months (ALE, 23 September, p8).
Crisis prevention
In a bid to avert an upstream crisis, ACP has called for the
government to cut pipeline tariffs and taxes, ease upstream
contract conditions, allow contract obligations to be transferred and further stimulate offshore investment. Colombia’s
energy ministry has not commented on ACP’s proposals, but
says it is reviewing various measures to accommodate new
market conditions.
The government could make modifications to upstream
contracts under revisions to Colombia’s national development plan, which is being debated in congress. Part of the
plan addresses the issues that are thwarting exploration,
including lower oil prices, community unrest, rebel attacks
and delays to environmental licence approvals.
Future of Rubiales field uncertain
The future of Colombia’s flagship
160,000 b/d oil equivalent (boe/d)
Rubiales field is in doubt after operator
Canadian independent Pacific Rubiales
and
Colombia’s
state-controlled
Ecopetrol agreed on 13 March not to
extend the Rubiales upstream contract
when it expires next year.
Pacific Rubiales has operated the
field since 2007, but its contract expires
in June 2016. Ecopetrol “will evaluate
different alternatives for the operation
of Rubiales”, the company says. Pacific
Rubiales will study the possibility of
presenting a new proposal to Ecopetrol
for the field’s operation, it says. The
Canadian firm is considering whether
it wants to be the operator after the
current contract expires, “but only if it
makes economic sense”, chief executive
Ronald Pantin says.
Last year, Pacific Rubiales submitted a proposal to Ecopetrol for a new
operating contract for Rubiales, in which
it would apply infill drilling and enhanced
oil recovery (EOR) to maintain production. Under the proposal, it would share
incremental output with Ecopetrol from
the heavy oil field. But the slide in oil
prices led the firm to reconsider its offer.
“Under the new price scenario, [the
proposal] was marginal, so we decided
to invest in more profitable parts of the
company,” Pantin says.
Pacific Rubiales plans to boost its
output from Rubiales to a net 60,000
boe/d by the end of this year from
the 53,000 boe/d it now produces.
Ecopetrol takes the remainder of the
field’s production.
The Canadian firm expects to produce a total of 150,000-160,000 boe/d
this year compared with 147,423 boe/d
in 2014. Colombia accounts for 98pc of
Pacific Rubiales’ output. The additional
flows will come from light and medium
crude acreage in Colombia and Peru.
Pacific Rubiales’ oil output last year was
137,000 b/d, up by 16pc from 2013,
while its net proven oil and gas reserves
were 315mn boe. Colombian heavy oil
accounted for 137mn bl.
The firm is looking to Mexico in a bid
for further growth, alongside its Mexican
partner and 19pc shareholder Alfa. The
two are vying for existing service contracts from state-owned Pemex that will
be converted into production-sharing
agreements and are eyeing shallowwater and onshore exploration blocks.
The company’s 2015 capital expenditure (capex) is $1bn, assuming a crude
price of $45/bl in the first quarter, based
on prices for US light sweet benchmark
WTI, rising to $60/bl in the fourth quarter.
In January, Pacific Rubiales cut its 2015
capex to $1.1bn-1.3bn from $1.5bn in
late 2014. It plans to divest some assets
to raise cash (ALE, 27 January, p5).
© 2015 Argus Media Ltd www.argusmedia.com
Page 4
Argus Latam Energy — Peru
24 March 2015
Pipeline boosts growth potential
Nine months after Brazil’s Odebrecht and Spain’s Enagas won
a contract to build Peru’s Southern Gas Pipeline, the consortium’s chief executive Rodney Carvalho spoke to Argus about
the project’s future. Edited highlights follow:
What point have you reached in the project?
We were awarded the concession on 26 June 2014 and
signed the contract on 23 July. We are now at 12.5pc of the
total investment. In construction, we have invested around
$450mn in pipework and preparing the terrain, and another
$50mn in a fund to pay for rights of way and land use.
How much will you invest?
The contract is for $7.3bn over 30 years. Investment in construction is around $4bn and the remainder is for the 30 years
of operation. The $7.3bn will be financed with capital from
Odebrecht and Enagas and loans from private banks.
When we know the amount of gas and liquids in these blocks,
we can negotiate with them to transport liquids. The contract
gives us two years from the date of signing to decide on the
liquids pipeline without the need for an international tender.
So we have another 18 months to reach an agreement with
companies that would want to transport liquids.
There are two thermal generating plants already lined
up to receive gas from the pipeline. Are you talking with
other companies?
We are talking to all the major electricity users in the south in
the manufacturing and mining sectors. We expect [requests for
gas supply contracts] to accelerate as construction advances.
The potential for growth in the south is very promising.
Can you name the companies?
There are companies that want to invest in petrochemicals,
like [Brazil’s] Braskem, [Canada’s] Methanex, [Japan’s]
Sojitz and [Peru’s] Breca.
How is the financing organised?
‘The country
We have agreements with 14 of the 15
banks that we are working with and
Previous petrochemicals projects failed
has a solid credit
are finishing negotiations with the final
to get off the ground. How confident are
rating and good regulatory
bank. The idea is that in June we will
you about the sector?
framework. This is going
have financing agreed with all of the
The issue is gas supply. Unlike previous
to be one of the largest
banks. Five of the banks have already
projects, we have planned to have infrafinancing deals ever
provided us with a $600mn bridge loan
structure in place to deliver gas. We are very
in Peru’
for the work that we have carried out, so this
confident that supply and demand will increase.
proves that there is confidence in the project.
Banks do not have a problem with loans for projects in Peru,
Regarding supply, could Bolivia take advantage of this
because the country has a solid credit rating and good regulapipeline to transport its gas to the Pacific coast?
tory framework. This is going to be one of the largest financing
The Bolivian government was the first to approach us after we
deals ever in Peru.
signed the contract. It is building a pipeline from Cochabamba
to La Paz. It is only 230km from La Paz to Puno in Peru. This
When will the construction phase begin?
is the natural route for Bolivia in the future. Bolivia exports gas
We have an agreement to start construction in June, but have
to Argentina and Brazil, but Brazil expects to be self-sufficient
asked [energy regulator] Osinergmin to let us begin in April.
in gas from its sub-salt developments, and likewise Argentina
We want to start laying the pipeline in April, as soon as the
from its Vaca Muerta [shale formation]. These markets will
rainy season ends. We aim to finish the segment between the
eventually close for Bolivia, so it is looking for another option,
jungle and Cusco [in the highlands] by December 2016. The
and that means linking with our pipeline.
last segment, from Anta in Cusco to Ilo in Moquegua, will be
finished in December 2017. We expect to begin supplying gas
Is a second LNG plant feasible?
within the first half of 2018, with 500mn ft³/d (5bn m³/yr) from
Not only is it feasible, it is imperative. Our project is initially for
block 88 [in the Camisea gas complex].
500mn ft³/d, which will satisfy electricity production and petrochemicals plants. An LNG plant is a critical component for
Are you still considering a parallel liquids pipeline?
the project to grow. We need to change the attitude that LNG
The first segment, from the gas fields in Malvinas to Anta, will
is only for export. An LNG plant could be used to supply the
include a liquids line. For the rest, we are waiting for results
whole of Peru without the need to build new pipelines. Small
from block 76, where [US firm] Hunt Oil has started exploraregasification plants could be built in the highlands and the
tion, and from block 58, which [Chinese state-owned] CNPC
north, with the LNG moving by ship or tanker truck. It would
acquired from [Brazil’s state-controlled] Petrobras. They are
be cheaper to move LNG to regasification plants than to build
working on seismic testing and could start production in 2017.
thousands of kilometres of gas pipelines.
© 2015 Argus Media Ltd www.argusmedia.com
Page 5
Argus Latam Energy — Mexico
24 March 2015
Shale reserves attract interest
Potential investors continue to show interest in Mexico’s massive shale reserves, even though the sharp decline in oil prices
has raised questions over their viability.
The drop in oil prices since mid-2014 has forced Mexico
to delay parts of its first-ever licensing round. An initial package of 14 shallow-water blocks was unveiled in December,
followed by the release of nine shallow-water development
blocks in February (ALE, 10 March, p3). But the auctioning of
costly shale gas and deepwater blocks, initially scheduled for
April and May, has been pushed back indefinitely.
Mexico’s shale projects still hold interest despite this.
“We have plenty of time,” Norwegian state-controlled Statoil’s
project leader in charge of overseeing new opportunities in
Mexico, Ferid Tore al-Kasim, says. “When the data is available,
we’ll be ready to look at it.” Statoil, like many other companies,
“is following Mexico’s first round [of auctioning] very closely,
including its tender for Chicontepec and unconventional
fields,” al-Kasim says.
Mexico has some 545 trillion ft³ (15.4 trillion m³) and
13.1bn bl of technically recoverable shale gas and shale
oil reserves, respectively, mostly in the north of the country,
according to US government agency the EIA. Mexico’s Burgos
and Sabinas basins are an extension of the prolific Eagle Ford
formation in the US.
But it remains to be seen whether the Texas model can
be reproduced in northern Mexico. Mexico’s state-owned oil
firm Pemex initiated shale exploration in the Burgos basin in
2011. Exploration wells costing $20mn-25mn/well have been
expensive and flow rates have declined steeply from an initial
rate of 3mn ft³/d per well, according to a 2013 EIA report titled
Technically Recoverable Shale Oil and Shale Gas Resources.
In comparison, US independent EOG Resources invested an
average $5.8mn/well in the Eagle Ford in 2013, according to a
report last year by consulting firm Accenture. Mexico imported
1.36bn ft³/d of natural gas last year, mostly from the US, an
increase of more than 250pc since 2010.
Water shortfall
At the same time, security in areas of the country controlled by
criminal gangs and a critical lack of water are significant obstacles. A development manager at a US firm with shale drilling
experience in northern Mexico has cited regulatory uncertainty
as another of the industry’s main concerns.
“There is already strong competition for the use of water,”
Jaime Felipe, a member of the water commission in the shalerich state of Tamaulipas says. Up to 78pc of the water in the
region is dedicated to agricultural use, he says.
The body that regulates water usage and distribution in
Mexico, Conagua, last year identified 79 water basins nationally that are in deficit, meaning that Conagua cannot approve
water supply contracts in those areas. In Texas, private-sector
firms can negotiate with landowners to obtain access to water.
Although this is allowed in Mexico, any agreement must first
be approved by Conagua. Transporting water from a water-rich
state to a drier area is permitted only during emergencies.
But new legislation introduced by the governing PRI party
is being debated in the lower house of congress. The proposed measures could change the way Mexico assigns water
concessions to the private sector and ease restrictions on
water distribution in the country.
Pemex to bid in upstream licensing round
Mexican state-owned oil company
Pemex has confirmed that it will bid in
the initial two phases of the country’s
first licensing round, but has yet to
clarify if it will participate on its own or
with a partner.
The first package covering 14 shallow-water exploration blocks was issued
in December. The second package of
nine shallow-water blocks was issued
in February (ALE, 10 March, p3). The
tender for the first package moved into
the pre-qualification stage on 19 March,
after a total of 39 companies accessed
a data room, Mexico’s oil regulator CNH
says. Potential bidders are scheduled
to be pre-qualified by 15 May, with final
bids due on 15 July.
Pemex was one of the companies
that accessed the data room for the first
package. Such access is the first step
for potential bidders ahead of the prequalification stage.
The staggered licensing round is
scheduled to culminate with coveted
deepwater acreage. This was originally
supposed to be offered in May, but has
been postponed indefinitely because of
lower oil prices.
Pemex is considered an attractive
partner because of its long experience
as Mexico’s upstream monopoly holder.
Ahead of December’s licensing round
launch, Pemex signed co-operation agreements with a number of foreign oil companies, including Chevron, ExxonMobil,
Total, India’s Reliance Industries and
China’s state-owned CNPC.
The upstream rounds, together with
imminent contract migrations and farmouts of its own acreage, could position
Pemex to reverse a decade-long slide
in oil production. In January, Pemex produced 2.25mn b/d of crude, 4.3pc less
than the previous month and more than
10pc down on a year earlier.
The company has lowered its 2015
crude production target by 5pc to
2.28mn b/d from 2.4mn b/d, according to upstream manager Gustavo
Hernandez Garcia. But Pemex’s official
line is that it “hopes to create new alliances with various companies to reach
its initial production target”.
© 2015 Argus Media Ltd www.argusmedia.com
Page 6
Argus Latam Energy — Exports/imports
24 March 2015
PetroCaribe exports drop
Venezuela’s state-owned PdV reduced its crude and products
exports to PetroCaribe members by nearly a fifth last year.
PdV exported 178,000 b/d to PetroCaribe members in
2014, down from 220,000 b/d a year earlier, Venezuela’s
energy ministry says. Of this, Cuba took 77,000 b/d, compared
with 98,000 b/d in 2013.
Among the factors that drove down shipments were stagnant crude production, operating problems at PdV’s refineries and sharply lower oil prices, which made the initiative’s
financing terms less attractive. PetroCaribe’s terms allow
member states to finance up to 50pc of the cost for up to 25
years at 1pc/yr interest. But the portion of the cost eligible for
financing drops to only 30pc when oil prices fall below $50/bl.
PetroCaribe members’ combined storage capacity
increased to 617,000 bl last year, reducing the need for the
export facility, the energy ministry says.
Late review
President Nicolas Maduro vowed earlier this month that
Venezuela would not reduce oil shipments under PetroCaribe.
But he called for a “review” of its financing terms, including
late payment conditions.
Recipients last year were Antigua and Barbuda, Belize,
Dominica, the Dominican Republic, Grenada, Guyana, Haiti,
Jamaica, Nicaragua, St Kitts and Nevis, St Vincent and the
Grenadines, Suriname and Cuba. Cuba is a PetroCaribe member but its supplies are covered by separate bilateral deals.
PetroCaribe members should see a substantial reduction in the amount they have to pay because of the oil price
fall since mid-2014, the IMF’s deputy director for the western
hemisphere Adrienne Cheasty says.
“When oil prices were high, bills were large and so was
PetroCaribe’s financing, which averaged 2.5pc of importing
countries’ GDP in 2014,” Cheasty says. “Current low oil prices
mean that PetroCaribe members should see their bills decline
by an average of 3.75pc of GDP in 2015,” she says.
“But this significant gain will be somewhat offset by lower
access to financing of about 1pc of GDP for the average
recipient country, as the size of PetroCaribe loans declines and
loan terms become less generous as oil prices fall,” she says.
Maduro remains committed to PetroCaribe, but Cheasty
says “a possible discontinuation would now be more manageable than in the past. The lost income from the oil price
drop for Venezuela has caused analysts to question whether
PetroCaribe support will continue. If it were to cease, the impact
would differ across PetroCaribe members.”
A reduction or suspension of PetroCaribe would leave
several governments short of cash, Cheasty says. “If
resources are not recycled from the private to the public sector in the form of financing or reductions in energy subsidies,
some governments could be forced to discontinue social
or investment programmes. Nearly all countries would face
some additional fiscal pressures,” she says.
If PetroCaribe financing were to cease, Guyana, the
Dominican Republic and Jamaica would be among the members least affected, “because these governments are financially prepared for the change”, while the most affected would
be Haiti and Nicaragua, Cheasty says.
Buenos Aires reduces tax exemption on fuel imports
Argentina has eliminated a tax exemption on gasoline and diesel imports to
address a market distortion whereby
government-controlled domestic fuel
prices exceed international levels.
The energy secretariat resolution
published on 16 March effectively
reverses a 2015 budget measure that
sought to stimulate imports to make
up any shortfall in local production to
meet domestic demand, including from
the power sector. The budget allowed
for annual tax-free imports of as much
as 120,000 b/d of diesel and 20,000
b/d of gasoline, which could each be
increased by 20pc if required.
The resolution is retroactive to 1
January and affects Argentina’s state-
controlled YPF, Shell, Brazil’s statecontrolled Petrobras, local firm Oil
Combustibles and Bridas subsidiary Axion. Bridas is jointly owned by
Argentina’s Bridas Energy and China’s
state-owned CNOOC. Despite the reimposition of the tax, international prices
for refined products are still lower than
domestic values, following years in which
Argentina’s pump prices were a fraction
of global levels. Buenos Aires hopes the
change will encourage domestic fuel
sales and boost investment in the exploration and refining sectors.
The government has put into effect
a stimulus plan to subsidise oil production and crude exports as part of an
effort to forestall a further decline in
output amid lower international prices
(ALE, 27 January, p6). The proposal was
published in Argentina’s official bulletin
on 16 March, but has yet to be voted on
by congress.
The government will pay an extra
$3/bl to companies that increase their
production or keep it unchanged. The
payment will be made only when the
price obtained for crude from the Golfo
San Jorge or Cuyana basins is no
greater than $67/bl, or $81/bl for crude
from the Austral, Neuquen or northwestern basins. The government will pay an
additional $2-3/bl for crude exports if a
company keeps its sales abroad steady
or increases them compared with its
shipments from the country last year.
© 2015 Argus Media Ltd www.argusmedia.com
Page 7
Argus Latam Energy — Venezuela
24 March 2015
Perla waiting for platform delivery
Venezuela’s state-owned PdV expects first commercial gas
150mn ft³/d, leaving Repsol and Eni with 32.5pc each.
production at the offshore Perla field to start by July at the
Perla’s output could rise to 450mn ft³/d and over 10,900
earliest, because the project’s main production platform has
b/d of condensate before the end of August if production
still not arrived from Mexico.
starts in early July, and to 800mn ft³/d and up to 30,000 b/d
Perla’s principal gas production platform (PP1), built
of condensate in mid-2017, Gonzalez says. Some Perla conby Mexican group Monclova at facilities near the port of
densate will be exported, while some will be supplied locally
Tampico in Tamaulipas state, started its journey to the Gulf
to PdV’s refineries and to petrochemical plants operated by its
of Venezuela on 21 March and should arrive “in less than
subsidiary Pequiven, Gonzalez says.
four months”, PdV offshore gas manager Francisco
Perla gas will go mainly to state-owned power
Gonzalez says.
company Corpoelec, allowing PdV to reduce
Perla’s
Gonzalez is PdV’s general manager for
some of the costly diesel imports it has to
main production
the Rafael Urdaneta offshore gas exploramake to supply oil-fired power plants.
tion and development programme in the
Corpoelec consumes about 300,000 b/d
platform has started
Gulf of Venezuela, which includes the
of diesel and other liquid fuels, accordits journey to the Gulf of
Cardon 4 block, where the Perla field is
ing to electricity minister Jesse Chacon.
Venezuela and should
located. A source close to the Perla proEnergy and electricity ministry figures
arrive ‘in less than
ject said earlier this year that the block’s
show that PdV imported up to 115,000 b/d
four months’
first 150 ft³/d (1.5bn m³/yr) production train
of diesel last year to supply Corpoelec plants
would begin “soon” (ALE, 24 February, p5).
that are designed to run on gas.
The PP1 platform was originally due to arrive in
Local output
Venezuelan waters by the middle of last year, but construction
PdV produced over 7.42bn ft³/d of gas in 2014, of which 2.12bn
and delivery fell behind schedule because of financial and
ft³/d went to local consumers including the state-owned power
technical problems. Perla’s joint-venture operators — Spain’s
and petrochemicals industries and private-sector residential
Repsol and Italy’s Eni — were partly able to compensate
and industrial clients, the energy ministry says.
for these by hiring specialised local and foreign contractors
Venezuela’s gas deficit in the local non-oil economy is
instead of issuing contracts through heavily indebted PdV.
estimated at close to 3bn ft³/d at present, suggesting that the
The shallow-water Perla field, with more than 16.3 trillion
local market will absorb 100pc of the gas from PdV’s current
ft³ (450bn m³) of gas reserves, is located about 80km off the
plans to produce 1.2bn ft³/d at Perla and a further 1.2bn ft³/d
coast of Falcon state.
at its Mariscal Sucre offshore project in waters northeast of the
Repsol and Eni discovered the field in 2009. PdV will take
Paria peninsula by 2020.
35pc once the project has started producing Cardon 4’s first
China lends Caracas another $5bn
Venezuela’s cash-strapped government
expects to receive a $5bn cash injection
from China in April.
China Development Bank (CDB) is
scheduled to renew one of three funds
created to manage close to $50bn in
Chinese oil-backed loans granted to
the government and state-owned PdV
since 2007. As part of the arrangement, Caracas is seeking to borrow a
further $5bn for crude joint ventures in the
Orinoco oil belt, the energy ministry says.
It is not clear yet if this second loan
would be structured as a conventional
bank credit or as an oil-backed loan that
PdV must repay with crude and oil prod-
ucts deliveries to Chinese companies. But
it is likely to be the latter.
CDB’s renewal of China heavy fund 2
with up to $5bn had been expected. The
fund was created in 2009 with an initial
$4bn loan repayable over three years,
and was renewed in February 2012 for
another three years, when Caracas took
another $4bn. The fresh $5bn of oilbacked financing that Caracas expects
to receive next month would bring total
oil-backed loans through China heavy
fund 2 to $13bn.
China heavy fund 1, created in
November 2007 with a $4bn loan from
CDB repayable with crude and products
over three years, was renewed in 2010
and 2013 for a combined $12bn. It is
up for renewal again in 2016. The China
grand volume fund was created in 2010
with an initial oil-backed $20bn, half in
Chinese currency.
Caracas spent or committed the full
$10bn dollar-denominated portion of
this fund by 2012, and has been lobbying Beijing since 2013 to replenish it
with at least another $10bn, the energy
ministry says.
CDB granted a $4bn oil-backed
loan in June 2013 to Sinovensa, a 60:40
crude blending venture between PdV and
Chinese state-owned firm CNPC.
© 2015 Argus Media Ltd www.argusmedia.com
Page 8
Argus Latam Energy — Mexico
24 March 2015
Huge boost to gas network
Mexico aims to expand its natural gas pipeline network by
three-quarters to nearly 20,000km over the next three years.
The expansion will help state-owned utility CFE offer more
competitive electricity prices ahead of the opening of the gas
and power industries to the private sector, chief executive
Enrique Ochoa Reza says.
Six new gas lines have been completed in the past year,
seven are being built, while construction tenders for five more
were recently awarded. A further four are in the process of
being auctioned. These projects will add a combined 6,000km
to the country’s 11,000km of operational pipelines. A further 11
projects covering 2,300km are at the planning stage.
Expanding the gas network is a part of President Enrique
Pena Nieto’s 2014-18 national infrastructure programme and
is expected to attract $13bn in investment. One of Pena
Nieto’s 2012 election campaign promises was to lower power
prices to Mexican households by the end of his administration in 2018. CFE is aggressively modernising its gas pipeline
network to meet the target, and expanding it to areas in the
country where access to gas is limited.
Gas accounts for over 40pc of Mexico’s primary energy
consumption and demand is increasing. Demand rose by 4pc
in 2013 to 6.95bn ft³/d (70bn m³/yr). The electricity sector is the
country’s biggest user, accounting for almost half of demand,
followed by the upstream oil industry with 32pc and industrial
demand from the metals and chemicals sectors at 17pc.
Mexico has nearly 60 trillion ft³ (1.7 trillion m³) of proven,
probable and possible gas reserves and produced 6.53bn
ft³/d last year — around 7pc less than in 2010. And the country
has 545 trillion ft³ of technically recoverable shale gas, according to US government agency the EIA.
Mexico’s shale resources are concentrated in the north but
have remained largely untapped because of the low profitability of extraction projects in Mexico prior to the approval of the
country’s energy reform (see p6). Mexico imports gas to meet
rising demand, mostly from the US through a growing number
of cross-border pipelines. And the country has three privately
operated LNG import terminals.
Six new gas-fired power plants should come on line by
2017 at an overall cost of $5.7bn. Four of the facilities will be
in the northern border states of Sonora, Chihuahua and Nuevo
Leon. The other two will be in the western state of Sinaloa.
Replacement package
Another key CFE strategy is to encourage the replacement
of fuel oil-fired generating units with gas-fired units that are
less expensive to run. Mexico is investing $200mn to upgrade
seven oil-fired power stations, all of which will convert to gas
within the next two years. “Using more natural gas and less
fuel oil to generate power is helping us lower electricity prices
in the industrial, commercial and domestic sectors,” CFE’s
Ochoa Reza says.
Pemex awards breakthrough ethanol tender
Mexico’s state-owned Pemex has
selected six local companies in a groundbreaking tender to supply ethanol.
The firms will supply Pemex with up
to 123mn litres/yr (2,119 b/d) of domestically produced ethanol for 10 years.
The contracts, to begin in April 2018,
are based on US corn ethanol prices.
Pemex plans to produce its Pemex
Magna brand of gasoline with a 5.8pc
ethanol blend.
Blending will take place at six Pemex
distribution terminals — Veracruz,
Xalapa and Perote in the Gulf coast
state of Veracruz, Ciudad Mante in the
neighbouring state of Tamaulipas, and
San Luis Potosi and Ciudad Valles in the
central state of San Luis Potosi. Under
a pilot programme, Pemex will start
selling 60,000 b/d of gasoline mixed
with ethanol in the states of Tamaulipas,
San Luis Potosi and Veracruz in 2018.
Overall, Pemex will invest $57.6mn in
blending infrastructure.
Contracts to supply another two
terminals were not awarded. Ciudad
Madero in Tamaulipas received no bids,
while none of the bids for Pajaritos in
Veracruz fulfilled the necessary criteria, a
Pemex official says. Pemex plans to hold
a new tender for the two terminals.
The tender, which was open to
Mexican firms only, requires companies
to deliver ethanol from locally produced
sugar cane or sorghum.
Antonio Garcia Carreno, whose
company Bioenergeticos Mexicanos
won three contracts to supply San Luis
Potosi, Ciudad Valles and Ciudad Mante,
says the company will build a new plant
in Valle Hermoso in sorghum-producing
Tamaulipas state. The construction of the
plant and operational costs will require
investment of $90mn-100mn, Carreno
tells Argus.
Another winning firm, Jalisco-based
Alcoholera de Zapopan, already produces cane-based ethanol for beverages and chimneys. “Those who are
investing in a brand new plant are taking big risks,” says Salvador Romero
Valencia, the firm’s founder. “We are
subject to a formula based on US corn
ethanol, so if their ethanol is expensive,
we win. If it’s cheap, we lose.”
The cane industry opposes the US
corn ethanol-based price index that
Pemex uses. But Pemex says it is legally
obliged to use a market-based price
for its ethanol formula, which is set by
a government biofuels commission that
includes Mexico’s energy, finance and
agriculture ministries.
© 2015 Argus Media Ltd www.argusmedia.com
Page 9
Argus Latam Energy — Ecuador
24 March 2015
Ambitious oil agenda in need of funds
Ecuador is seeking $17bn to help finance its ambitious 201517 oil investment plan amid low oil prices and the appreciation
of the US dollar.
The key oil projects include 13 exploration blocks initially
offered to investors in November 2013 as part of Ecuador’s
11th upstream licensing round, which covered 16 blocks in
the southeastern Amazon region. The original round failed to
attract newcomers to the country’s upstream and drew proposals for just four of the 16 blocks on offer, one of which was
later rejected (ALE, 3 December 2013, p6).
Contracts for blocks 28, 79 and 83 under the 2013 licensing round are still being negotiated. A consortium led by
Ecuador’s state-owned PetroAmazonas with 51pc, Chile’s
state-owned Enap holding 42pc and Belarusian state-owned
Belorusneft with 7pc bid for block 28. And Andes Petroleum, a
joint venture between Chinese firms CNPC and Sinopec, bid
for blocks 79 and 83.
Ecuador aims to find investors willing to spend some
$2.9bn to explore and develop the remaining acreage, which
is located in the remote Pastaza and Morona Santiago provinces, close to the border with Peru.
Block 86 has proven reserves of 90mn bl, according to US
consultancy Gaffney, Cline and Associates, and could produce a peak of 72,500 b/d of 10-23°API grades. It will require
a $90mn exploration budget and an additional $1.6bn for
development, the strategic sectors ministry says.
Seismic absence
There is little seismic information for the remaining southeastern blocks. Quito plans to carry out seismic studies in
the first half of this year to provide additional information for
potential bidders, before relaunching the round later in the
year, oil minister Pedro Merizalde said in December (ALE, 16
December, p6).
The government is also looking for funding alternatives
to finance the development of the Ishpingo-TambocochaTiputini (ITT) heavy crude block, which will now require $5.6bn
of investment, according to the strategic sectors ministry’s
investment catalogue. ITT contains recoverable reserves of at
least 850mn bl and a production potential of 100,000-200,000
b/d of 14-15.5°API crude over 22 years (ALE, 10 March, p8).
And Ecuador wants to revive the Pungarayacu oil sands
deposit project in block 20, some 200km southeast of Quito
in Napo province. PetroAmazonas terminated the contract
of Canadian independent Ivanhoe Energy in February after
the latter failed to reach an agreement with China’s stateowned CNPC to develop the acreage (ALE, 10 February, p6).
Pungarayacu is considered Ecuador’s largest-known untapped
oil field, with estimated extra-heavy oil reserves of up to 6.4bn
bl, a 2009 report by Gaffney, Cline and Associates said.
The country’s 2015-17 investment agenda also includes
PetroAmazonas’ block 31, which contains 129mn bl of
12-18°API crude reserves, according to US firm Ryder Scott.
It will require the construction of 10 platforms and drilling 44
wells at the Apaika Sur, Obe, Boica Norte, Kuwatai and Pimare
oil fields, at a cost of $668mn, the strategic sectors ministry
says. PetroAmazonas has so far completed the first phase of
the Apaika field development, with an investment of $103mn.
Despite falling oil revenues, Ecuador has increased its
public investment budget to $8.1bn this year, up from $7.2bn
in 2014 and $7.6bn in 2013. To help finance its investments,
Ecuador returned to the international capital markets in June
last year for the first time since its $3.2bn sovereign debt
default in 2008, selling $2bn of 10-year bonds with a yield of
7.95pc (ALE, 1 July, p1).
A bond sale on 19 March raised $750mn from five-year
notes, below an initial target of $1bn, with a yield of 10.5pc.
President Rafael Correa has attributed the higher bond yield
and shorter maturity to the oil price collapse.
State seeks to raise ethanol output
Ecuador wants private-sector investors to finance a $940mn
plan to produce and distribute an ethanol-gasoline blend
nationwide. State-owned PetroEcuador would blend 5pc
sugar cane-based ethanol into its existing 87 Ron gasoline
to create the new fuel, called Ecopais.
Ecuador has completed a pilot plan covering 145 retail
stations in the coastal province of Guayas, where some
11,110 b/d of the fuel is now sold. Nationwide distribution
could be achieved by 2017. In a second phase that could
start in 2018, the blend rate would be raised to 10pc. “The
next step is to select the price formula for ethanol,” a government official tells Argus. A new decree setting ethanol prices
could be issued in three to four months.
The 5pc mandated blend rate will require Ecuador to
expand domestic ethanol production to 180mn l/yr from the
current 35mn litres/yr. This in turn will require increasing cane
cultivation to 104,000 hectares (1,040km²) from 70,000 ha.
The country’s three privately owned ethanol plants have
combined production capacity of just 40mn l/yr. Expanding
cane cultivation to achieve a 10pc blend rate will require
$580mn in investment, and building new ethanol plants will
cost another $360mn, according to figures from the strategic
sectors ministry.
The plan is aimed at reducing Ecuador’s growing
high-octane gasoline imports, which it blends with locally
produced, low-octane gasoline to make 87 Ron and 93 Ron
gasoline. High-octane gasoline imports were over 55,000
b/d last year, up by a quarter from 2013, according to
PetroEcuador’s figures (ALE, 10 March, p8).
© 2015 Argus Media Ltd www.argusmedia.com
Page 10
Argus Latam Energy — Caribbean
24 March 2015
DomRep minister rejects southern LNG terminal
Dominican Republic energy minister Pelegrin Castillo has
rejected plans by consortium Antillean Gas to build an LNG
regasification facility on the country’s south coast, saying the
country “cannot afford” three natural gas terminals.
“The energy ministry has a very clear position on this
matter,” Castillo says. “Decisions about the location of critical
infrastructure are not taken by private actors. These decisions
must be taken by the state and have to accord with the state’s
vision of the demands for energy security and infrastructure
development,” he says.
Castillo has already thrown his weight behind the construction of a terminal on the north coast by US firm Southern
California Telephone and Energy subsidiary North Energy
Central (NEC). The terminal, located in Manzanillo bay, will be
part of a power complex aimed at bringing greater energy benefits to the country, Castillo says. NEC in 2013 concluded an
agreement in principle with Dominican Republic state-run utility
CDEEE to build, own and operate the terminal and a 400MW
gas-fired power plant. Neither NEC nor CDEEE have provided
details of how much gas will be supplied to the complex, which
NEC has said will cost about $800mn.
Stalled progress
Construction at the Antillean Gas complex formally began
in February last year, but the project stalled following the
appointment of Castillo as the country’s first energy minister in
April. Antillean Gas plans to deliver gas to power plants with a
combined capacity of 980MW, and meet rising demand in the
country for compressed natural gas for road transport. The
$302mn facility would receive just over 1mn t/yr of LNG and
have storage and sendout capacity of 127,000m³ and 2.4bn
m³/yr, respectively.
Antillean Gas comprises Norway’s BW Gas, Colombia’s
Promigas, local independent power firm InterEnergy and the
country’s biggest LPG distributor Coastal Petroleum Dominicana,
which is owned by the country’s fuel distributor Propagas.
“There is no logic to the energy ministry’s arguments,” says
local businessman Juan Bautista Vicini Lluberes, a leading financier of the consortium. “We want to install the terminal to supply
natural gas to all who require it, because the intention is to contribute to the development of the country,” he says.
Floating order
Antillean Gas “has an agreement with a US company that
will supply LNG”, and has completed engineering studies
for the project, Vicini Lluberes says. The floating storage and
regasification unit (FSRU) for the project is under construction
in Asia-Pacific, he says. Vicini Lluberes did not name the LNG
supplier, although the consortium started talks last month with
US firm Cheniere Energy to supply up to 1mn t/yr of LNG to
the regasification terminal.
But US firm AES’ subsidiary AES Dominicana says there
is no need for any new gas facilities in the country. The company says it will be able to meet the Dominican Republic’s
gas needs through the expansion of its Andres LNG terminal,
which is located 30km from Antillean Gas’ planned facility. AES Dominicana is doubling the import capacity of its
Andres terminal to 2mn t/yr, and is lifting storage capacity to
320,000m³ from 160,000m³ and sendout capacity to about
4.7bn m³/yr from 2.3bn m³/yr, it says.
Trinidad to press on with Venezuela energy talks
Trinidad and Tobago will continue to
co-operate with its neighbour Venezuela
on energy issues, despite the South
American country’s deteriorating relations with the US, Trinidad’s foreign minister Winston Dookeran says.
“We would like to see a diplomatic
solution for the escalating crisis between
Venezuela and the US,” Dookeran says.
“But our joint efforts with Venezuela
to explore for resources in the sea
between our countries will continue,”
he says. US president Barack Obama
signed an executive order on 9 March
implementing and expanding sanctions against senior Venezuelan officials
(ALE, 10 March, p12). Trinidad and
Tobago has close bilateral ties with the
US, and has been a significant supplier
of LNG to the US in the past.
A joint government and private-sector delegation from Trinidad will visit
Caracas “in a few weeks” to continue
discussions over natural gas deposits that straddle the countries’ maritime
border, and to fine-tune an agreement
to exchange energy products, Trinidad’s
trade minister Vasant Bharath says.
The countries will discuss how best
to develop the cross-border LoranManatee field, the Cocuina-Manakin
field and the Kapok-Dorado field.
The countries have already agreed to
develop the Cocuina-Manakin field but
have yet to decide how to split its 740bn
ft³ (20bn m³) of reserves, Trinidad’s
energy ministry says.
Following prolonged negotiations
since 2007, the two countries have
agreed that Venezuela will own 73.75pc
of the Loran-Manatee field’s 10.5 trillion
ft³ of reserves, with Trinidad taking the
rest. And the countries have agreed that
70pc of the 5 trillion ft³ Kapok-Dorado
field belongs to Trinidad.
The countries have also signed
a bilateral agreement under which
Venezuela will resume crude and asphalt
shipments to Trinidad in exchange for
much-needed goods such as gasoline,
machine parts and toilet paper.
© 2015 Argus Media Ltd www.argusmedia.com
Page 11
Argus Latam Energy — In brief
Caracas puts PdV output at 2.9mn b/d
Venezuela’s state-owned PdV produced
2.899mn b/d of oil in 2014, including
2.785mn b/d of crude and 114,000 b/d
of NGLs, the energy ministry said in
an annual report to the governmentcontrolled national assembly. Argus estimates PdV’s real crude output at about
2.3mn b/d. Orinoco heavy and extraheavy crude accounted for 1.245mn b/d,
or 45pc, of last year’s official crude
production. PdV’s Orinoco upgraders at
the Jose complex in Anzoategui together
processed 416,000 b/d, or about 70pc
of combined nameplate capacity of
600,000 b/d. PdV’s total exports averaged 2.356mn b/d last year, down by
69,000 b/d from 2013. Crude exports
of 1.895mn b/d were down by 40,000
b/d from 2013, and products exports
of 461,000 b/d were 29,000 b/d lower,
reflecting the combined impact of PdV’s
falling production capacity and refinery
incidents. Asia-Pacific was PdV’s largest export market last year, with 953,000
b/d destined mainly for China and India,
followed by North America with 837,000
b/d, 418,000 b/d to Latin America and the
Caribbean, and 132,000 b/d to Europe.
PdV’s domestic refineries produced
953,000 b/d of products in 2014, including 323,000 b/d of gasoline and 292,000
b/d of diesel (ALE, 27 January, p7).
Batista fined over OGP non-disclosure
Brazilian securities regulator CVM has
levied a 1.4mn reals ($443mn) fine
against Eike Batista, the business
tycoon behind the now-defunct EBX
commodities group, for his failure to
disclose relevant facts concerning oil
company OGX. Operational difficulties
at the Tubarao Azul field owned by OGX,
now known as OGP, ultimately led to the
collapse of other EBX group companies. Batista is alleged to have waited
some weeks before disclosing in July
2013 that production was not viable at
Tubarao Azul, the firm’s main producing
asset. Batista also continues to face
insider trading and market manipulation charges (ALE, 7 October, p6). The
shallow-water 3,000 b/d Tubarao Azul
field is scheduled to stop production
24 March 2015
Peru appoints new PetroPeru chief executive
Peru’s government has named a new
chief executive of state-run oil company PetroPeru, as authorities debate its
return to the upstream.
German Vasquez was appointed
PetroPeru chief executive on 20 March,
replacing Pedro Touzett, after a public disagreement between Touzett
and energy minister Rosa Maria Ortiz.
Touzett, who was only appointed to the
position in July, wanted the ministry to
endorse a number of upstream agreements that PetroPeru had signed that
would allow it to return to crude production after a two-decade absence.
The company is waiting for the ministry to approve an agreement for it to
take a 25pc share in blocks 3 and 4 on
the northern coast that were awarded to
Peru’s Grana y Montero in December
this month, a little more than two years
after output started, and the nearby
Tubarao Martelo field is likely to produce
only around 8,000 b/d unless additional
funding for a second phase is found.
OGP returned the Campos basin’s
Remora field to Brazilian oil regulator
ANP on 12 March after OGP decided
that production there was not economically viable. OGP produced 12,784 b/d
of oil in Brazil in February, down from
14,090 b/d in January.
Petrobras oil output falls in February
Brazil’s state-controlled oil firm
Petrobras produced 2.146mn b/d of
oil in Brazil in February, down by 2.1pc
compared with January, but an 11pc
increase over February 2014. Its total
oil and natural gas production in Brazil
last month reached 2.612mn b/d of oil
equivalent (boe/d), a 1.8pc fall compared with January. The drop marks the
second consecutive month Petrobras’
domestic oil production has slipped
after it set a 2.212mn b/d record in
December. The fall was the result of
scheduled maintenance at production
platforms in the Campos and Santos
basins, Petrobras says. The loss from
(ALE, 16 December, p9). The ministry
has also failed to sign off on an October
2013 agreement between PetroPeru and
Argentina’s Geopark to develop block
64 in the northern jungle.
The failure to approve the agreement
involves legislation that was passed by
congress in December 2013 to clear
the way for the $3.5bn modernisation of
PetroPeru’s flagship Talara refinery. The
unit’s capacity will increase to 95,000
b/d from 65,000 b/d now. It will also
be able to produce cleaner diesel and
process heavier crude (ALE, 3 June, p9).
The legislation bars PetroPeru from
involvement in any other activity that
could take financial resources away
from the modernisation project. Ortiz
had previously said the agreement for
blocks 3 and 4 would violate the law.
maintenance was partially offset by the
start of seven new production wells,
including ones in the Santos basin
sub-salt region. Petrobras’ share of subsalt production reached a record of
555,000 b/d on 26 February, with total
production, including partners’ shares,
at 737,000 b/d. Natural gas production
in Brazil averaged 73.97mn m³/d in
February, down by less than 1pc against
January, but up by around 13pc on the
previous year. The increase was mainly
because of the ramp-up of associated
gas produced at sub-salt fields (ALE,
13 January, p7). Total oil and gas production in Brazil and abroad averaged
2.801mn boe/d, a 1.5pc drop compared
with January, but up by around 10pc
from the previous year.
Shell Argentina’s Aranguren to quit
The chief executive of Shell’s Argentinian
affiliate, Juan Jose Aranguren, will
step down from the company on 30
June, ending a 12-year tenure that has
been marked by sharp conflicts with
the government. Teofilo Lacroze, a Shell
employee since 1996, will succeed
Aranguren from 1 July. Aranguren, who
has worked at Shell for 37 years, became
© 2015 Argus Media Ltd www.argusmedia.com
Page 12
Argus Latam Energy — In brief
one of the country’s most outspoken
business leaders and has often criticised the government, including current
president Cristina Fernandez de Kirchner
and her late husband and predecessor
Nestor Kirchner. In 2005, Kirchner called
on Argentinians to boycott Shell after
the company instituted a price increase
at its retail outlets. In 2007, Argentina’s
government threatened to jail local Shell
executives if the company failed to boost
diesel supplies to the local market (ALE,
11 July 2007, p7).
Trinidad LNG train 2 to shut in late April
24 March 2015
Guyana dismisses Venezuela Essequibo challenge
Guyana has rejected what it terms a
“subtle threat” from Venezuela over
ExxonMobil’s decision to drill for oil in
waters that the two countries dispute.
Guyana “has full and unfettered
authority to unilaterally explore — with
or without partners — and exploit the
living and non-living resources within its
jurisdiction,” the country’s foreign ministry says. “Any act or objection to the
exercise of such jurisdiction is contrary
to international law.”
On 5 March, ExxonMobil spudded the deepwater Liza 1 well on the
southeastern end of the vast offshore
Stabroek block, which lies in the extensive Essequibo area. ExxonMobil operates the block with a 45pc stake. US
independent Hess holds 30pc and
Chinese state-owned CNOOC subsidiary Nexen holds the remaining 25pc.
Shell acquired a 25pc stake in the
block in 2009, but sold it last year.
According to Hess, the 6.5mn acre
block holds net risked resources of
500mn bl of oil.
Trinidad and Tobago’s 3.3mn t/yr train
2 LNG production facility is scheduled
to close for eight days in late April.
Train 2 is owned by BP, the UK’s BG
and Shell. The liquefaction plant shutdown is related to upstream gas maintenance. Trinidad’s Atlantic LNG facility
has production capacity of 14.8mn t/yr.
Trinidad produced a total of 32.15mn
m³ of LNG in 2014, down by 1.6pc from
2013, mainly because of the temporary shutdown of BP subsidiary BPTT’s
Savonette platform for most of the year.
But BG started delivering natural gas
from the offshore Starfish field at the
end of 2014, which has helped boost
LNG output. Trinidad produced 2.87mn
m³ of LNG in January, up by 14pc
from January 2014. Gas production in
January averaged 4.07bn ft³/d (42bn
m³/yr), 1.9pc higher than a year earlier
and 0.2pc higher than the previous
month (ALE, 24 February, p13).
although the banks involved have not
been named. Jamaica imports around
69,000 b/d of crude and oil products.
It receives 23,000 b/d from Venezuela
under the PetroCaribe oil supply facility
and imports refined products, mainly
from Trinidad and Tobago and the US
(ALE, 2 December, p11).
Jamaica introduces fuel tax
Geopark sharpens Colombia focus
Jamaica has levied a tax of 6¢/litre on
the retail price of gasoline and diesel
as a way of raising $55mn to finance a
planned hedge against an increase in
international crude prices, finance minister Peter Phillips says. “There is a risk
that oil prices will again start to move
sharply upwards,” he says. “This could
have a profound negative effect on our
economy.” Negotiations with “overseas
counterparts” are being conducted by
the finance ministry and the country’s
central bank, state-run energy company
PCJ chairman Christopher Cargill says,
Colombia-focused
independent
Geopark boosted oil and natural gas
output by 20pc to 20,557 b/d of oil
equivalent in 2014 compared with 2013.
This year, the company plans to spend
$60mn-70mn, assuming an oil price of
$45-50/bl, with flat-to-5pc production
growth. Most of the spending will be in
Colombia. Geopark aims to cut costs
by 20-30pc as a result of the decline
in oil prices. Much of last year’s output growth came from the 12,000 b/d
Tigana oil field in the Llanos 34 field in
Colombia. Geopark plans to drill four or
The Essequibo region covers the
western two-thirds of Guyana, which
Venezuela has consistently claimed as
its own. The dispute has prevented
both countries from demarcating their
maritime boundary. Venezuela’s foreign
minister Delcy Rodriguez sent a letter in
February to ExxonMobil’s unit in Guyana
demanding a halt to the exploration project (ALE, 10 March, p4).
Guyana’s latest statement follows advertisements that Venezuela
placed in Guyanese newspapers on
14 March, stating that Venezuela “ratifies the full exercise of its just claim
to the Essequibo territory, including its
coastline”. Furthermore, Caracas said it
“reserves the right to execute all actions
in the diplomatic field and in accordance with international law that might
be necessary to defend and safeguard
the sovereignty and independence of
Venezuela”. Caribbean trade group
Caricom came out in support of Guyana
on 20 March, rejecting Caracas’ claim
as “null and void”.
five wells in the Tigana and Tua fields
in the second half of 2015, with a hope
of eventually reaching 30,000 b/d from
the complex. In Chile, the company
noted non-cash expenses of $21.8mn
related to the writedown of seven exploration wells and some seismic studies.
Geopark’s net profit sank by 54pc to
$15.9mn in 2014, and the firm lost
$33.7mn in the fourth quarter. It also has
operations in Brazil and Peru (ALE, 14
February, p7).
Argus Rio Oil Conference
11-13 May 2015
Rio de Janeiro, Brazil
Join Latin American market participants and Argus to network, exchange
ideas and learn about opportunities and
challenges in the Latin American crude
oil markets.
www.argusmedia.com/ROC
© 2015 Argus Media Ltd www.argusmedia.com
Page 13
Argus Latam Energy — Prices
Crude prices
$/bl
23 Mar
Price
Diff. to WTI
±9 Mar
48.63
Jun -0.52
-2.93
Vasconia fob
49.73
Jun +0.58
-2.40
Castilla fob
44.98
Jun -4.17
-2.40
Maya fob
45.00
Apr -1.85
-2.04
Olmeca fob
53.07
Apr +6.22
-2.09
Isthmus fob
51.48
Apr +4.63
-1.58
WTI Cushing
46.85
-
-3.15
LLS St James
55.99
Apr +9.14
+0.49
Mars Clovelly
52.10
Apr +5.25
-0.26
ANS del WC
53.50
CMA +3.84
-1.99
Argentina
Escalante fob
Colombia
Mexico del USGC
US
Product prices
¢/USG
23 Mar
Price
±9 Mar
Fob USGC high-sulphur diesel
147.82
-7.54
Fob USGC ultra-low sulphur diesel
166.27
-12.21
172.39
-0.21
Del USGC 40 N+A (reformer grade)
158.14
+0.04
Del USGC LSR/LV (paraffinic)
122.00
-3.50
44.90
-1.95
Fob Argentina biodiesel SME $/t
517.94
-38.68
Brazil ethanol bob anhydrous $/m³
463.50
+3.50
Cif Brazil ethanol anhydrous $/m³
430.50
-67.00
Gasoil
Gasoline
Fob USGC 87 conventional
Naphtha
Fuel oil
Fob USGC 3% $/bl
Other
LPG prices
¢/USG
23 Mar
Price
±9 Mar
Propane
50.88
-5.50
Butane
57.00
-9.38
24 March 2015
Crude dips as supplies mount
Crude prices fell after regaining some
strength earlier this year, as plentiful supplies met sluggish demand.
US crude stocks hit a record high for
the tenth week running, according to the
latest data from the EIA. Saudi Arabian
crude output climbed to around 10mn
b/d in March, according to Saudi oil minister Ali Naimi, up from an Argus estimate
of 9.68mn b/d in February. The bearish
fundamentals were only partly offset by
a decline in the value of the US dollar
against other major currencies, as the
dollar’s strength began to ease.
US light sweet benchmark WTI fell
by $3.15/bl to less than $47/bl in the two
weeks to 23 March. The decline came
despite a switch from April to May pricing in a contango market, where forward
prices are at a premium to prompt values.
Tight supplies of Iraqi medium sour
Basrah Light amid weather-related loading delays have spurred demand for
medium sour crude in the US Gulf coast.
Colombian producers took advantage of
the widening arbitrage to the US Gulf
coast by issuing tenders for medium sour
Vasconia for end-April loading. These
were awarded at narrower discounts to
Ice Brent crude than previous tenders.
Canadian firm Pacific Rubiales’ subsidiary Meta Petroleum and China’s
Sinochem both awarded 500,000 bl
Vasconia tenders loading in late April
at discounts to Ice April Brent of $6.507.00/bl. But Vasconia is poised to soften
relative to Brent amid a bearish market
in the Mediterranean. Russian medium
sour Urals has fallen against the North
Sea Dated benchmark and Basrah Light
looks better value to Mediterranean refiners than Vasconia when freight costs are
taken into account.
Outright prices for both Vasconia,
which competes with Basrah Light, and
Colombia’s heavier Castilla Blend fell
by $2.40/bl to $49.73/bl and $44.98/bl,
respectively, in the two weeks to 23 March.
Strong exports support gasoline
US products prices mostly fell in the two
weeks to 23 March, but demand from
Latin America and elsewhere supported
gasoline and naphtha. At least 21 clean
products cargoes were scheduled to
leave the US Gulf coast for Latin America
in the second half of March, after a threeday closure of the Houston Ship Channel
slowed exports earlier in the month.
The firm gasoline export demand
offset slow domestic buying. Waterborne
conventional gasoline prices fell by just
0.2¢/USG to $1.72/USG. But gasoil values tumbled, with waterborne heating oil
falling by 7.5¢/USG to $1.48/USG and
ultra-low sulphur diesel down by 12.2¢/
USG to $1.66/USG. The falls followed
a declining April Nymex diesel contract.
Colombian demand for naphtha to
use as a diluent for its heavy crudes supported prices, with the issue of the latest
in a string of tenders for two 170,000180,000 bl shipments of light naphtha
for 7-12 April and 13-23 April delivery
to Barranquilla. Colombia had already
drawn at least three cargoes of light
naphtha from the Gulf coast in March,
and its continued buying interest appears
poised to support light naphtha in April
too. Waterborne prices for light paraffinic
naphtha fell by 3.5¢/USG to $1.22/USG.
Heavy N+A naphtha values rose
by 0.4¢/USG to $1.58/USG, as existing
requirements for Mexico and Venezuela
kept trading firms hungry for barges. At
least four cargoes of heavy naphtha are
thought likely to head from the US to
Venezuela in late March.
Latin American bunker fuel prices
mostly declined, tracing crude values.
Plentiful supplies in Rio de Janeiro made
this the cheapest port in Latin America,
while Buenos Aires had the region’s most
expensive prices, with supplies limited by
high temperatures, which have diverted
residual fuel oil to power generation.
© 2015 Argus Media Ltd www.argusmedia.com
Page 14
Argus Latam Energy — Energy output
24 March 2015
Latin America: Oil output
Venezuela*
’000 b/d
Feb 14
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2014
Jan 15
Feb
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,300
2,304
2,300
2,300
Mexico
2,501
2,469
2,478
2,490
2,436
2,388
2,415
2,390
2,363
2,363
2,353
2,429
2,251
2,326
Brazil
2,090
2,119
2,146
2,189
2,246
2,267
2,326
2,358
2,393
2,358
2,497
2,255
2,469
2,420
Argentina
539
535
515
528
530
525
529
540
539
534
534
532
533
535
Colombia
1,002
977
935
950
1,008
968
999
993
1,002
1,002
1,007
988
1,035
1,027
551
557
560
554
555
558
558
551
557
563
561
556
558
560
81
82
80
81
80
82
82
83
86
79
84
81
84
85
174
179
178
174
169
169
164
171
180
175
174
172
166
159
Ecuador
Trinidad & Tobago
Peru
Bolivia
65
62
63
65
65
65
64
63
63
58
60
63
63
63
Cuba
49
49
49
49
49
49
49
49
49
49
49
49
49
49
Guatemala
10
11
10
10
10
9
10
10
9
11
10
10
10
10
Others
24
24
24
24
24
24
24
24
24
24
24
24
24
24
9,387
9,365
9,339
9,415
9,472
9,405
9,521
9,533
9,565
9,516
9,655
9,464
9,542
9,557
824
835
811
825
821
824
828
826
820
818
821
821
820
816
10,211
10,199
10,150
10,240
10,292
10,229
10,349
10,359
10,385
10,333
10,476
10,285
10,362
10,373
Total crude
NGLs & other^
Total crude & NGLs
* excludes condensate, includes syncrude ^includes Venezuelan condensate, Orimulsion and extra-heavy crude
Ecuador: Total national production ’000 b/d
2009
2010
2011
2012
2013
2014
2015
Jan
503.7
463.7
500.8
504.1
505.0
550.1
557.7
Feb
498.2
470.1
509.1
502.8
509.4
550.8
Mar
497.2
478.3
501.6
499.3
504.2
556.6
Apr
495.2
479.8
503.8
500.4
515.7
560.2
May
486.1
478.4
497.5
497.8
521.5
554.3
Jun
491.6
490.7
494.9
501.7
524.0
555.3
Jul
483.2
491.8
491.6
507.9
530.3
558.3
Aug
476.6
484.9
495.6
512.0
536.7
558.3
Sep
475.2
489.9
494.9
506.4
535.1
550.9
Oct
474.3
497.5
501.5
502.9
539.9
557.2
Nov
476.9
507.9
504.1
504.2
545.0
562.8
Dec
469.8
499.3
500.6
503.4
548.2
561.1
Year average
485.6
486.1
499.6
503.6
526.3
556.3
Ecuador: Total state production 2009
2010
2011
2013
Ecuador: Total national production
Ecuador: Total national production 520
557.7
431.3
480
Jan
284.4
273.5
354.9
362.4
373.9
426.1
281.2
276.6
364.1
361.9
379.0
426.8
430
Mar
279.6
283.6
357.8
358.1
375.7
433.1
420
Apr
282.5
284.8
358.4
359.6
383.9
437.1
May
285.2
280.8
357.3
357.9
389.9
430.6
288.4
286.4
356.1
363.1
390.7
432.0
400
Jul
282.7
287.0
353.1
371.5
399.3
435.7
390
Aug
280.1
313.8
357.3
373.8
408.6
434.7
Sep
280.0
318.4
352.8
370.7
408.7
429.0
380
326.6
357.9
368.0
412.7
434.5
360.5
368.9
418.5
437.5
Dec
277.2
346.8
361.7
366.2
422.4
436.2
Year average
281.6
301.2
357.6
365.2
396.9
432.8
Ecuador: Total private-sector production 2009
2010
2011
2012
2013
431.3
2015
126.4
219.3
190.1
146.0
141.7
131.2
124.1
216.9
193.5
144.9
141.0
130.4
124.0
Mar
217.6
194.7
143.8
141.3
128.5
123.6
Apr
212.7
194.9
145.4
140.7
131.9
123.1
May
201.0
197.6
140.2
140.0
131.6
123.7
Jun
203.2
207.1
138.9
138.6
133.3
123.2
Jul
200.5
204.8
138.5
136.4
131.0
122.6
Aug
196.5
171.1
138.3
138.2
128.1
123.6
Sep
195.2
171.6
142.2
135.8
126.4
121.8
Oct
196.4
170.9
143.6
134.9
127.2
122.7
Nov
197.3
173.5
143.6
135.3
126.5
125.4
Dec
192.6
152.5
138.9
137.1
125.8
124.9
Year average
204.0
184.9
142.0
138.4
129.3
123.5
’000 b/d
360
2014
Jan
'000 b/d
370
’000 b/d
Feb
Oct
2012
2013
2014
410
Jun
334.5
Jul
440
Jan
279.9
Apr
Ecuador: Total state production
Ecuador: Total state production Feb
279.6
2012
2013
2014
500
2015
Oct
’000 b/d
580
540
2014
Nov
'000 b/d
560
’000 b/d
2012
— Argus estimates/official data
350
Jan
Apr
Jul
Oct
Ecuador: Total private sector production
Ecuador: Total private-sector production '000 b/d
’000 b/d
145
140
135
2012
2013
2014
130
125
126.4
120
Jan
Apr
© 2015 Argus Media Ltd www.argusmedia.com
Jul
Oct
Page 15
Argus Latam Energy — Energy output
Ecuador: Crude transported by pipeline (total) ’000 b/d
2009
2010
2011
2012
2013
2014
2015
Jan
477.3
443.3
488.1
499.3
502.3
503.4
542.6
Feb
461.6
447.9
498.3
470.9
482.6
510.4
Mar
491.2
449.2
486.1
480.2
478.4
503.8
Apr
457.5
454.4
479.9
474.8
496.0
540.0
May
471.7
455.6
477.9
483.7
507.6
539.7
Jun
466.8
454.3
468.6
485.1
491.4
497.3
Jul
472.5
474.0
463.1
489.5
524.0
534.5
Aug
465.2
460.3
475.3
493.4
518.8
540.8
Sep
430.9
478.2
468.6
484.9
521.6
528.6
Oct
469.5
495.0
473.3
481.4
527.7
517.1
Nov
457.2
467.2
488.2
479.6
512.5
551.7
Dec
446.7
481.4
456.7
492.0
526.6
532.0
Year average
464.1
463.5
476.9
484.7
507.5
525.0
480
460
Jan
2010
2011
2012
2013
2014
2015
340.1
366.8
360.7
368.2
360.1
367.6
Feb
357.2
336.7
371.7
337.3
360.0
368.1
Mar
357.5
348.8
354.3
346.3
345.1
359.3
Apr
341.4
342.3
348.5
344.9
360.5
355.2
May
356.0
340.8
347.4
351.1
352.8
365.4
Jun
359.4
344.2
338.7
355.6
332.9
363.2
Jul
355.8
355.4
334.7
360.0
372.5
357.2
Aug
356.1
350.4
344.1
364.0
368.7
369.9
Sep
330.6
362.8
337.1
350.2
372.1
367.6
Oct
354.3
361.4
329.3
347.9
369.0
362.4
Nov
350.4
359.4
330.9
345.9
366.9
372.6
Dec
342.4
353.6
340.1
364.5
369.5
356.8
Year average
351.5
349.7
345.2
352.5
361.5
363.2
330
Jan
2010
2011
2012
2013
2014
2015
121.3
138.6
134.0
143.3
175.0
Feb
104.4
111.2
126.6
133.6
122.5
142.3
Mar
133.7
100.4
131.8
133.9
133.3
144.6
Apr
116.1
112.1
131.5
129.9
135.4
184.7
May
115.7
114.8
130.4
132.5
154.8
174.2
Jun
107.5
110.1
129.9
129.5
158.6
134.2
Jul
116.6
118.6
128.5
129.5
151.5
177.3
Aug
109.2
109.9
131.2
129.4
150.1
171.0
Sep
100.3
115.4
131.5
134.6
149.5
161.0
Oct
115.2
133.6
144.0
133.5
158.7
154.7
Nov
106.8
107.7
157.3
133.7
145.7
179.1
Dec
104.3
127.8
116.6
127.4
157.2
175.2
Year average
112.6
113.8
131.7
132.2
145.9
161.8
120
Jan
45.9
50.3
54.2
43.0
47.5
54.0
Mar
39.6
32.5
31.7
35.8
51.5
54.4
Apr
36.5
29.1
36.9
46.6
48.2
54.5
2012
2013
2014
Apr
Jul
Oct
175.0
50.7
43.8
48.5
200
140
2015
37.4
Oct
160
2014
35.1
Jul
b/d
Ecuador:
Crude
transported
pipeline(private)’000
(private)'000 b/d
Ecuador:
Crude
transported
byby
pipeline
180
’000 b/d
35.5
Apr
367.6
103.2
40.0
2012
2013
2014
340
2009
Jan
380
350
120.6
Feb
Oct
360
Jan
2013
Jul
Ecuador:
Crude
transported
by pipeline
(state)’000
'000 b/d
Ecuador:
Crude
transported
by pipeline
(state)
b/d
370
Ecuador: Crude transported by pipeline (private)’000 b/d
2012
Apr
542.6
2009
2011
2012
2013
2014
500
356.7
2010
560
520
Jan
2009
Ecuador: Crude transported by pipeline (total) '000 b/d
Ecuador: Crude transported by pipeline (total) ’000
b/d
540
Ecuador: Crude transported by pipeline (state) ’000 b/d
Ecuador: Total production of gasoline 24 March 2015
Ecuador: Total production of gasoline
Ecuador: Total production of gasoline '000 b/d
’000 b/d
64
60
56
May
39.6
33.7
31.8
50.2
46.0
51.0
52
Jun
40.1
37.1
34.3
47.1
51.3
60.5
48
Jul
36.1
34.3
45.0
51.1
54.4
57.8
Aug
39.3
33.4
44.0
44.1
55.8
54.0
44
Sep
40.9
35.9
43.8
53.7
47.5
54.1
40
Oct
35.4
37.2
38.1
49.0
51.3
41.9
36
Nov
40.6
35.3
43.5
46.8
52.4
48.6
Dec
43.0
35.7
44.1
48.4
54.8
49.1
32
Jan
Year average
38.9
34.7
40.5
46.8
50.9
53.3
2012
2013
2014
Apr
Jul
Oct
50.7
© 2015 Argus Media Ltd www.argusmedia.com
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