bmi americas oil and gas insight march 2016

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CONTENTS

AmericasOil and Gas

BMI’s monthly market intelligence, trend analysis and forecasts for the oil and gas industry across the Americas

March 2016 Issue 118

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ISSN: 1750-7723

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United States .................................................................................1Unconventional M&As Offer Valuable Opportunities ..............................................1

Demand For Refined Fuels Approaching A Peak ...................................................... 2

Lifting The Crude Export Ban: Initial Implications ................................................... 3

Mexico ...........................................................................................5Onshore Round Solidifies Production Upside ........................................................... 5

Downstream Improvements Will Alter Pemex's Portfolio .......................................... 6

Canada ...........................................................................................7Husky Decision An Outlier, Producers To Delay Development ........................................ 7

Colombia ........................................................................................8Investment In Shale Will Yield Limited Success ....................................................... 8

Venezuela ....................................................................................10Petrocaribe Nearing Final Days .............................................................................10

Argentina .....................................................................................10Lower Domestic Crude Prices Will Not Deter Investment ........................................10

UNITED STATES

Unconventional M&As Offer Valuable OpportunitiesBMI View: The potential acquisition by US independent Devon Energy of Felix Energy points to a rising trend of M&A activity among smaller E&Ps and supports our view that companies will be keen to bolt on acreage within the major shale plays.

On December 3, US independent Devon Energy reportedly made an of-fer for Felix Energy for a cash-plus-shares deal. While the amount of the acquisition is unconfirmed at USD2bn, we believe this development is in-dicative of a wider trend that smaller, more leveraged companies are under substantial pressure to offload assets amid consistently low crude prices.

We previously highlighted that a growing acceptance that benchmark prices will remain weak for an extended period of time will drive merg-ers and acquisitions (M&A) activity into the new year (see 'Growing Consensus Over Lower Oil Price Supports M&A Uptick', November 26 2015). With WTI crude prices consistently trading below USD55/bbl since July 6, oil producers have been under tremendous financial strain despite concerted efforts to cut production costs over the past year. Continued downside pressure on WTI has resulted in greater assurance regarding the value of upstream companies and their assets, thereby facilitating M&A activity.

The proposed takeover by Devon also supports our view that there is consistent communication between producers who are looking to optimise their asset portfolios by bolting on adjoining acreage to boost their competitiveness within the broader industry downturn.

We believe this particular deal is of interest given the acreage that is on offer. While much attention within the unconventional space has been

H215 Weakness Limiting Upstream ProspectsFront-Month WTI Price, USD/bbl

Source: Bloomberg

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Americas Oil & GasUNIted StAteS

directed toward the 'big three' plays – the Permian, Eagle Ford, and Bakken – Felix's asset base is exclusively located in the Anadarko Basin of Oklahoma, an area we previously highlighted as the top emerging shale region in the country (see 'Oklahoma Countering Shale Downtrend', June 22 2015).

Though production within the basin has declined in recent months alongside the majority of other shale plays, the underlying strength of the area makes this a valuable asset. Namely, the South Central Oklahoma Oil Play and Sooner Trend, Anadarko Basin and Canadian and Kingfisher counties (STACK) plays have attractive breakeven structures, high recoverable liquids volumes and strong initial production rates.

Devon's strength within the Anadarko basin makes it well-positioned to link its portfolio with that of Felix, bolstering its long-term prospects within the play. Namely, the strategic purchase of Felix's 75,000 net sweet spot areas would complement Devon's nearly 280,000 net risked acres where upstream developments are continuing amid the price downturn. Devon has furthered its com-mitment to the STACK by leveraging enhanced completion designs and reducing drilling time to achieve a reported 15% decrease in total well costs this year, illustrating its understanding of the play and making it an optimal fit with Felix's assets.

Demand For Refined Fuels Approaching A PeakBMI View: Changes in fuel standards will limit consumption growth for refined fuel products in the US over the next decade. 2015 will prove to be an outlier within a broader long-term downward trend.

Demand for refined petroleum goods in the US is nearing a peak as structural changes within the market discourage higher consumption levels. Namely, strict fuel economy targets being implemented in the US along with higher blending mandates for biofuels will weaken consumer demand for fuel over the next decade in spite of lower prices at the pump.

Increased fuel economy standards will limit potential upside for fuels consumption, with demand unlikely to return to levels seen in the last decade. As such, we forecast total consumption of refined fuels to rise by an average rate of 1.3% between 2015 and 2017 before falling to an average rate of 0.1% over the remainder of our 10-year forecast period at the time of writing.

Stricter Rules Disincentivise DemandThe steep decline in crude benchmark prices since 2014 resulted in a similar reduction in the price of refined fuels. This lowered average retail prices for both gasoline and diesel by approximately 27.0% y-o-y in 2015, falling below USD3.00/gallon for the entire year compared to an average of nearly USD3.75/gallon for regular and medium grade gasoline and USD3.80/gallon for diesel fuel in 2014.

Lower prices at the pump reinvigorated US consumption in 2015, reversing a long-term downtrend over the past decade. However, following consumers' readjustment to new price levels, we believe demand for refined fuels will become more tempered (see 'Lower Oil Prices Boost Fuel Consumption', March 30 2015).

Specifically, changing structural dynamics – combined with a de-clining number of drivers in major urban centres and the emergence of the electric vehicle segment – will limit upside over the long run (see 'Premium EV Brands Will Defy Low Fuel Prices', June 5 2015).

A new chapter in US fuel efficiency standards will begin in 2017, limiting consumption over the long run and proving the surge in demand over 2015 will be short-lived. With motor gasoline and diesel comprising two-thirds of domestic market demand, the US government has increased its focus on creating a new generation of

FINAL RENEWABLE FUEL VOLUMES 2014 2015e 2016f 2017f

Cellulosic biofuel (mn gallon) 33.0 123.0 230.0 n/a

Biomass-based diesel (bn gallon) 1.63 1.73 1.90 2.00

Advanced biofuel (bn gallon) 2.67 2.88 3.61 n/a

Renewable fuel (bn gallon) 16.28 16.93 18.11 n/a

e/f = estimate/forecast. Source: EPA

Demand Capped By Structural ChangesUS – Demand For Refined Fuels

f = BMI forecast. Source: EIA, BMI

Dip In Benchmark Incentivised ConsumptionUS – WTI Front-Month Price, USD/bbl (LHS) & Primary Refined Fuels,

USD/Gallon (RHS)

Source: Bloomberg

3www.oilandgasinsight.com


cleaner vehicles to mitigate the effects of climate change and reduce refined fuels consumption.

Namely, US passenger cars and light trucks model year 2017-2021 will be required to travel 40.3-41.0 miles per gallon (mpg) versus an average of just under 30mpg over the past decade. Moreover, for cars manufactured between 2022 and 2025, the mandated level increases to an average of 48.7-49.7mpg. These rules will weaken demand in both the motor gasoline and more nascent diesel fuel markets which is already facing a setback following the VW scandal earlier this year (see 'EPA Ruling Hits VW's US Advantage', September 21 2015).

In addition, in November 2015, the Environmental Protection Agency (EPA) released the volume requirements of biofuels in the US gasoline supply in the Renewable Fuel Standard (RFS) for 2014 through 2016. The mandated blending volumes for all types of renewable fuels increased markedly over the three-year period, providing further downside for conventional refined fuels demand over the long term.

Lower Demand Will Keep A Lid On PricesIn light of lower consumption trends, we expect benchmark crude prices will find it challenging to realise a more pronounced recovery. Producers will continue to scale back upstream developments as sustained weakness in crude markets increases pressure to ensure profitability by minimising costs.

This dynamic will provide modest support for WTI prices over the next several years, particularly after 2018 when global supplies and demand begin to balance. However, we believe structural changes in the US market will outweigh market trends in the US, inhibiting upward pressure over the long run as average yearly crude prices remain below USD75/bbl through 2024 (see 'Demand Weakness Will Restrain Prices', November 6 2015).

Lifting The Crude Export Ban: Initial ImplicationsBMI View: The lifting of the US crude export ban will have a limited impact on liquids production over the next year due to persistently weak project economics. A tightening of the spread between Brent and WTI will subdue demand for US cargoes overseas, with Canada remaining the US's primary export market. Exports to Latin America will also grow, given their demand for light sweet crude.

The reversal of the 40-year ban on crude exports on December 18 will not revive the US's upstream industry. While a landmark change in policy, this reform comes at a time when US oil producers have little to benefit from the export market, given stuttering production domestically and weak international demand growth for light sweet crudes. We maintain our forecast for a contraction in output in 2016 with little prospect for strong production gains thereafter.

US Supplies Entering Hotly-Contested MarketThe introduction of US exports will allow producers to compete freely in the global market. This will result in a further narrowing of the spread between the WTI and Brent benchmarks which has tightened significantly over the past year due to a slowdown in output growth and continued infrastructural debottlenecking in the US. As a result, US crude exports will be less competitive than similar grades overseas when accounting for higher shipping costs and longer transit times.

Given continued demand for heavy and medium sour crudes, the US's light sweet supplies will become available for export. We cau-tion, however, that these supplies are entering a highly-competitive, oversupplied market. A number of the traditional suppliers of similar light grades – such as Nigeria and Angola – have struggled to place their own volumes in recent quarters. Discounted official selling

Future Supplies Will Be Sold At A Lower PriceUS – WTI Front-Month Price, USD/bbl

f = BMI forecast. Source: BMI, Bloomberg

Narrow Spread Decreases US Crude Competitiveness

WTI & Brent Front-Month Prices, USD/bbl (LHS) & WTI-Brent Spread, USD/bbl (RHS)

Source: Bloomberg

2015 Resurgence Will Not Reverse Long-Term Downtrend

US – Motor Gasoline & Diesel Consumption, 000b/d

Source: EIA



prices for a number of West African grades are indicative of this trend and highlight the competitiveness of the light sweet market (see 'Exports To Pressure European Crudes', September 3 2015).

We therefore believe that US exports will largely stay within the Americas given their proximity to potential importers. We expect Canada will remain the largest importer of US crudes in light of favourable demand dynamics and existing transport infrastructure. Namely, we expect Canadian economic growth will accelerate in 2016 from stronger manufacturing exports and higher household consumption (see 'Strong Exports Will See Economic Growth Ac-celerate', December 4 2015).

This will increase crude demand at Canada's light-geared refiner-ies which already import US supplies due to an exemption in the US's previous export regulations. However, we caution that US exports will still face significant competition within Canada as evidenced by the recent decline in US shipments attributed to the narrower WTI-Brent spread which displaced more costly rail imports with seaborne supplies (see 'Narrower Spread Will Disincentivise Bakken Crude Imports', September 9 2015).

Within Latin America, we expect Mexico will be the largest im-porter of US supplies given refiners' continued demand for ultra-light crude to blend with heavier domestic grades. Mexican production of light oil has fallen sharply in recent years due to national oil company Pemex's underinvestment in these resources. While we expect this trend will reverse in the wake of ongoing energy sector reforms, we do not expect these volumes will be produced before 2018, maintaining demand for imported supplies over the next two years. The crude swap arrangement which was approved earlier this year will also support future trade agreements between the two countries (see 'Crude Swap Will Support North American Market', August 18 2015).

East Coast Refiners Will Lose AdvantageExports will alter the dynamics of the downstream sector. Namely, Gulf Coast refineries will likely import larger quantities of medium and heavy sour grades for which they were designed as lighter sup-plies make their way out of the country. This will optimise refinery feedstock and improve downstream efficiencies throughout the USGC downstream hub.

Facilities on the East Coast, however, are likely to suffer from this change in policy. These refineries have benefitted from strong crack spreads as rail transport costs were offset by discounted rates for WTI-linked Bakken feedstock. However, as the spread between

WTI and Brent narrows, refiners' costs will increase, thereby squeez-ing profits at affected facilities. This could, in turn, increase demand for seaborne imports, depending on shipping costs and transit times.

Midstream Priorities Will ShiftGreater international demand for the US's land-locked crude will incentivise utilisation of midstream infrastructure. Specifically, we believe the lifting of the ban will strengthen demand for crude-by-rail usage from the Bakken as pipeline takeaway capacity remains at a deficit. We caution, however, that utilisation rates will be limited by weaker incentives for US imports due to the narrower price differential.

Also, first shipments will likely come from crude stocks, pro-viding much-needed relief for these overly-supplied facilities. As of the week ending December 11, total commercial crude storage in the US had reached 74.3% utilisation, reflecting the contango structure of the market as producers await a more profitable price. A stagnation or potential draw down in storage will reduce demand for corresponding infrastructure, particularly along the Gulf Coast.

Finally, we could see increased demand for pipelines over the long term. We believe this would primarily impact the Bakken play due to its continued reliance on more costly rail infrastructure. How-ever, this will take several years to materially impact capacity given regulatory and environmental constraints on project developments.

Stocks Nearing A PeakUS – Weekly Crude Stocks Ex. SPR, mn bbl

Source: EIA

US Supplies Already Under Pressure US – Crude Exports To Canada*, 000 b/d

*Monthly data through September 2015. Source: EIA


Americas Oil & GasMexIco

MEXICO

Onshore Round Solidifies Production UpsideBMI View: The success of Mexico's third license tender demonstrates ongoing government efforts to improve the attractiveness of the up-stream investment environment, strengthening momentum for future rounds. The development of onshore deposits will increase demand for OFS providers and supports our upbeat long-term production forecast.

On December 15, Mexico's National Hydrocarbon Agency (CNH) held the third tender of Round One auctions, launched to maximise investment into Mexico's underdeveloped gas and liquids sector. Having assigned all 25 of the blocks on offer, the latest tender sig-nificantly outperformed the expectations of both the energy ministry (Sener) and the CNH which had anticipated a 20% success rate. This suggests that the most recent regulatory changes provided sufficient incentives for private exploration and production firms (E&Ps) to participate in the reform process, highlighting the importance of an open and attractive regulatory regime (see 'Full Potential Rests On Greater Government Support', May 12 2015).

Development Supports Positive OutlookWith a total of approximately 1.8mn bbl of oil and 98.0mn cu m of 3P reserves across the offerings, the onshore fields will support production of both resources beginning in 2018. 19 of the areas assigned are already actively producing, but have suffered from chronic underinvestment in recent years by national oil company Pemex. We believe the era of declining output in Mexico is nearing its end as onshore development begins to ramp up.

As a main goal of the third tender, the CNH will ensure that these onshore blocks remain active while promoting long-term develop-ment from all 25 areas. While winning bidders have up to two years to formulate upstream plans as part of the 25-year concessions, existing infrastructure within the blocks will facilitate and likely expedite development plans. As such, we expect incremental output from onshore plays to be the first new volumes to emerge from the Round One process.

Mexican Dominance Will Shore Up SupportThe result of the onshore round will foster the development of Mexico's nascent private exploration and production (E&P) sector (see 'Start-Ups Well Positioned In Onshore Bidding Round', De-cember 14 2015). Of the 96 companies that demonstrated interest in the onshore round, 64 paid to access the data room, including

RONDA UNO – ONSHORE TENDER WINNERSBlock Company Country Of

Origin Share Of Profits

Offered (%)

Tajón Compañía Petrolera Perseus, S.A. de C.V. Mexico 60.82

CuichapaPoniente Servicios de Extracción Petrolera Lifting de México, S.A. de C.V. Mexico 60.82

Moloacán Canamex Dutch B.V. with Perfolat de México, S.A. de C.V. and American Oil Tools S. de R.L. de C.V. Holland/Mexico 85.69

Barcodón Diavaz Offshore, S.A.P.I. de C.V. Mexico 64.50

Mundo Nuevo Renaissance Oil Corp S.A. de C.V. Canada 80.69

Paraíso Roma Energy Holdings, LLC with Tubular Technology S.A. de C.V. and Gx Geoscience Corporation, S. de R.L. de C.V.

US/Mexico 35.99

Catedral Diavaz Offshore, S.A.P.I. de C.V. Mexico 63.90

Topén Renaissance Oil Corp S.A. de C.V. Canada 78.79

Mayacaste Grupo Diarqco, S.A. de C.V. Mexico 60.36

Malva Renaissance Oil Corp S.A. de C.V. Canada 57.39

Peña Blanca Strata Campos Maduros, S.A.P.I. de C.V. Mexico 50.86

Benavides Prima-vera

Sistemas Integrales de Compresión, S.A. de C.V. with Nuvoil, S.A. de C.V. and Constructora Marusa, S.A. de C.V.

Mexico 40.07

Fortuna Nacional Compañía Petrolera Perseus, S.A. de C.V. Mexico 36.88

Ricos Strata Campos Maduros, S.A.P.I. de C.V. Mexico 41.50

Mareógrafo Consorcio Manufacturero Mexicano, S.A. de C.V. Mexico 34.25

Carretas Strata Campos Maduros, S.A.P.I. de C.V. Mexico 50.86

Pontón Geo Estratos, S.A. de C.V. with Geo Estratos Mxoil Exploración y Producción, S.A.P.I. de C.V. Mexico 61.50

Tecolutla Geo Estratos, S.A. de C.V. with Geo Estratos Mxoil Exploración y Producción, S.A.P.I. de C.V. Mexico 68.40

Secadero Grupo R Exploración y Producción, S.A. de C.V. with Constructora y Arrendadora México, S.A. de C.V.

Mexico 60.74

Duna Construcciones y Servicios Industriales Globales, S.A. de C.V. Mexico 20.08

San Bernardo Sarreal, S.A. de C.V. Mexico 10.56

Calibrador Consorcio Manufacturero Mexicano, S.A. de C.V. Mexico 41.77

La Laja Geo Estratos, S.A. de C.V. witth Geo Estratos Mxoil Exploración y Producción, S.A.P.I. de C.V. Mexico 66.30

Calicanto Grupo Diarqco, S.A. de C.V Mexico 81.36

Paso de Oro Geo Estratos, S.A. de C.V. witth Geo Estratos Mxoil Exploración y Producción, S.A.P.I. de C.V. Mexico 67.61

Source: CNH


Americas Oil & GasMexIco

supermajors ExxonMobil and Total as well as Statoil and China National Offshore Oil Corporation. However, 26 companies and 14 consortiums ultimately participated, the overwhelming majority of which were newly-formed Mexican E&Ps including Perote E&P and GPA Energy. Meanwhile, the larger integrated producers did not present bids, suggesting these offerings were too small or too unprofitable to justify investment.

The dominance of private Mexican companies will help allevi-ate one of the primary threats facing the reform movement, given the importance of these resources to the citizens themselves. With domestic E&Ps winning rights to operate or participate in 22 of the 25 contracts, we believe broader support for the privatisation of the industry will strengthen, reducing the risk of demonstrations, which have increased over the past two years.

OFS Opportunities Opening UpOnshore developments will offer a critical new pool of demand for the embattled oilfield services (OFS) sector. Having come un-der tremendous strain over the past year in the wake of falling oil prices, OFS companies have been forced to cut costs and increase efficiencies as E&Ps throughout the world continue to pull back investments to protect positive free cash-flow (see ' Majors To Play Role In Market Rebalancing', November 4).

Quicker ramp-up of upstream projects – particularly in the 19 actively-producing blocks – will require equipment that is cur-rently in oversupply including wellhead and service capabilities and downhole expertise. With lower global demand having eroded costs for these services, smaller developers within Mexico will be able to benefit from cost deflation in the industry, crucial within a low commodity price environment.

Downstream Improvements Will Alter Pemex's PortfolioBMI View: Pemex's announced USD23bn downstream spending plan will be mostly funded through the newly-formed Fibra E invest-ment vehicle, boosting refining capacity over the next three years. We caution that extensive asset divestment on the part of Pemex could threaten its long-term profitability given our outlook for sustained lower oil prices over the next decade.

Mexican national oil company (NOC) Pemex affirmed its plans to modernise the country's downstream sector over the next three years through a USD23bn spending plan. While lower oil prices called into question the company's plans earlier in the year, we believe the Fibra E investment vehicle launched in November will provide a significant boost to the national oil company (NOC) (see 'Fibra E To Advance Energy Sector Liberalisation', November 5 2015). This will offset declines in government spending and supports our positive outlook within the sector.

Investment Supports Downstream PlansA stronger environmental mandate following the UN 2015 Paris Climate Change Conference (UN COP21) will couple with the new Fibra E investment tool to revive downstream development in Mexico over the next three years. The government is hoping to modernise its industrial facilities to increase production of ultralow sulphur (ULS) fuels, resulting in a reduction of CO2 emissions by 7mn tonnes per annum.

The Fibra E programme offers an ideal mechanism to direct

Onshore Blocks Cement Upstream MomentumMexico – Total Hydrocarbons Production


Fibra E Enables Further Sector DevelopmentFibra E Ownership Structure

Source: Secretaría de Hacienda y Crédito Público

PEMEX DOWNSTREAM STRATEGYPlan Amount Allocated (USDbn) Strategy

Renovate Technological Museum 0.3 Create the National Energy Technology Museum

Build co-generation capacity 3.0 Capture steam from three refineries for power generation

Increase ULS petrol production 3.1 Upgrades at all six refineries, decrease emissions by 90%

Increase ULS diesel 3.9 Upgrades at all six refineries

Increase utilisation of residual products 12.3 Modernise Salina Cruz, Tula and Salamanca to reduce use of coke from 20 to 3%

Total 22. 6

Source: Pemex company data


Americas Oil & GascANAdA

private capital into Mexico's energy infrastructure. An offshoot of energy sector liberalisation, its creation illustrates the government's continued commitment to the reform process while maintaining Pemex's prominence within the market.

Fibra E regulations require a corporate sponsor – such as Pemex – to contribute equity interests in developed infrastructure assets, for which they can raise capital by selling shares via the Mexican Stock Market (BMV). In this instance, Pemex would continue to operate the assets while generated cash flows would be distributed among stakeholders, according to their respective share of ownership.

This structure will open Mexico's downstream sector to a wider pool of investors through the BMV and will incentivise participa-tion through tax incentives. With only existing, positive cashflow generating assets allowed in this programme, this will reduce overall investor risk and ensure significant take up of Pemex's future offers, providing much-needed capital for the NOC's downstream plans.

While we are optimistic with respect to international investor interest, we maintain our more cautious outlook for refining capacity growth at the time of writing, given the scope of the modernisation plan. Specifically, Pemex hopes to spend USD19bn of the funds exclusively on refinery upgrades, reducing refined fuel imports by 139,000b/d. To date, we can confirm agreements at the Minatitlan, Salamanca, and Tula facilities, totalling 93,000b/d in additional downstream capacity which we believe will materialise between 2018 and 2019 (see 'Downstream Prepping For Upstream Growth', November 20 2015).

Divestments May Erode Pemex Balance SheetIn order to secure adequate funding for the downstream modernisation projects, Pemex will need to offer stakes in some of its most profitable assets. In an increasingly risk-averse environment following the fall in commodity prices, international investment will be incentivised by facilities that ensure strong future cash flows such as those within Pemex's downstream portfolio. In addition its six refineries, Pemex operates nine gas processing centres, two petrochemical facilities and more than 1,300km of pipelines and associated storage infrastructure, all of which enjoy a strong domestic demand outlook.

As the sole operator in Mexico's USD49bn downstream mar-ket, these assets have helped support Pemex's balance sheet in a time of declining upstream profits from steadily declining output and sharply lower oil prices. Specifically, in Q315 Pemex posted a USD9.5bn loss which was mainly attributed to a 39.1% decline in the value of its crude exports. However, the company's finances

were supported by stronger refining margins and a higher volume of domestic fuel sales.

Pemex is hopeful that liberalisation of the market will decrease their reliance on downstream revenues as stronger output levels and higher crude prices boost upstream profits – activities which are excluded from the Fibra E regime. However, we caution that this upside could prove insufficient to outweigh the decline in downstream revenues due to our more bearish oil price outlook whereby prices will average below USD70/bbl through 2020. The divestment of midstream and downstream facilities will therefore offer a short-term capital infusion for the modernisation plan, but could ultimately threaten the long-term profitability of the NOC.

CANADA

Husky Decision An Outlier, Producers To Delay DevelopmentBMI View: The decision by Husky to advance development of its Rush Lake, Edam and Vawn heavy oil projects in Saskatchewan will not boost Canada's oil sector over the next decade. The high-cost nature of similar upstream developments will not be justified within a low crude price environment.

Canadian energy company Husky Energy announced it would complete the 10,000b/d phase II of its Rush Lake heavy oil project, its Edam East and Edam West thermal oil developments and its 10,000b/d Vawn project in Saskatchewan, all by 2021. This is a significant departure from the vast majority of its oil producing peers in Canada, who have suspended or cancelled numerous projects over the past several months amid a weak oil price environment.

While notable, we caution that Husky's decision will do little to stem the inevitable decline in Canadian heavy oil production, beginning in 2018. With the fall in WTI prices precipitating sub-stantial weakness in Western Canadian Select (WCS), the majority of producers in Canada will forgo any pending or unconstructed upstream projects, thereby putting an end to the multiyear project pipeline which began in 2010.

We believe Husky decided to move forward with these devel-opments due to the integration of these assets with its downstream network. The company is keen to boost its ability to refine lower-cost feedstocks at its 160,000b/d refinery in Lima, Ohio in an effort to

Modernisation Supports Capacity GrowthMexico – Refining Capacity Growth

e/f = BMI estimate/forecast. Source: EIA, BMI

Downturn AheadCanada – Total Liquids Production



Americas Oil & GascoloMBIA

improve margins in the downstream sector which have become an important revenue generator as crude prices fall.

With Canadian crude prices expected to remain below USD40/bbl well into 2016, Husky and its peers in the heavy oil and bitumen market will suffer from significant financial strain. Falling upstream revenues will outweigh cost-cutting efforts, solidifying weaker op-erating margins and an eventual stagnation in heavy oil output (see 'Tough Times Ahead For Oil Sands Producers', August 14 2015).

This view is anchored in our oil price outlook whereby a con-tinued oversupply in the market will sustain downside pressure on benchmark prices until 2018 in spite of a pull back in US crude

production (see 'Prices Range-Bound As Glut Persists To 2018', December 9 2015). The WCS benchmark has traded at a USD13-15/bbl discount to WTI over the past year to account for its heavier composition and higher shipping costs. Given our outlook for WTI to average below USD55/bbl per year through 2018, WCS is likely to trade below commercial breakeven costs for many heavy crude projects, the bulk of which require a WTI price in excess of USD50/bbl.

At the time of writing, we estimate total crude output in Canada will reach 4.6mn b/d in 2015 and will increase to more than 5.0mn b/d by 2017. We therefore believe the combined 34,500b/d from the Rush Lake, Edam and Vawn developments pose little upside to the overall health of Canada's upstream market through 2024, supporting our long-term bearish production outlook.

COLOMBIA

Investment In Shale Will Yield Limited SuccessBMI View: Efforts by ConocoPhillips, ExxonMobil and CNE within Colombia's shale sector will not revive development of these resources over the next several years. These higher cost projects will prove difficult to justify amid an environment of continued oil price weakness.

We expect recent developments in Colombia's nascent shale sector will fail to result in meaningful upstream development. On December 3 2015, US-based independent ConocoPhillips and CNE Oil and Gas – a subsidiary of Canacol – announced they would extend their exploration contracts within Colombia.

The agreement will now include non-traditional oil resources in the VMM-3 block, taking advantage of regulations passed by the na-tional hydrocarbon agency in 2014 to incentivise shale development. The following day, supermajor ExxonMobil filed an environmental permit to explore for shale resources in the VMM-37 block. While promising, we believe these efforts will not spur progress to an extent that would result in growth of unconventional reserves or production, in light of continued oil price weakness (see 'Unconventionals Will Not Attract Capex', March 25 2015).

We therefore maintain our modest oil production growth forecast in Colombia through 2024 whereby output will not exceed 2016

Source: Bloomberg

WTI's Fall Signalled Heavy Oil's DemiseWSC (Top) & WTI (Bottom) Front-Month Price, USD/bbl

Canadian Crude Being Produced At A LossWTI Full-Cycle Breakeven Price For Selected Oil Sands Projects, USD/bbl

Note: Black line = BMI core oil sands profitability level; yellow line = current WCS spot price. Source: BMI, BMO Capital Markets, Citi Research, Cenovus

Unconventionals Not A FactorColombia – Total Liquids Production



Americas Oil & GascoloMBIA

levels. We believe declining upstream investment by both public and private partners will cause natural depletion to outweigh any incremental gains (see 'Reduced Attacks Improve Short-Term Pro-duction Outlook', August 24 2015).

Economics Do Not Favour DevelopmentWhile each of the aforementioned companies have experience with unconventional resources, we do not believe project eco-nomics in Colombia will incentivise their development over the next several years. Given a lack of infrastructure and equipment to support shale operations, the cost of development in Colombia will prove too high to justify the necessary investment within a low oil price environment.

Moreover, continued weakness in benchmark prices will main-tain substantial financial pressure on exploration and production companies, forcing them to reduce capital expenditures in an effort to match spending with revenues by 2016 or 2017. We now expect companies will prioritise investment on finishing major projects, rather than expanding into new, high cost markets (see 'Majors To Play Role In Market Rebalancing', November 4 2015).

In the case of ConocoPhillips, we do not believe it is well-positioned to increase investment into Colombia's unconventional resources by the required minimum of USD85mn. The company has extensive experience developing shale in the US's Niobara and

Permian plays as well as the Duvernay and Montney in Canada. However, a sharp decline in revenues over the past year has led to a pullback in various regions including the US Gulf of Mexico and unconventional development in China.

In addition, Conoco's previous joint venture with Canacol to explore for shale oil – which was announced in February of 2013 – suffered repeated delays, ultimately failing to yield any success. Though Canacol is already exploring for unconvention-als in seven blocks within the Middle Magdalena Basin (MMB), we do not believe it has sufficient financial firepower to progress with these projects.

Finally, with respect to ExxonMobil, the company has yet to de-velop its own existing shale assets within the MMB, suggesting a prioritisation of their spending elsewhere. As recent as February of 2015, the supermajor deferred its shale exploration plans in Colombia owning to the fall in crude prices. While the company is in a better financial position to advance its unconventional plans, we believe it will ultimately chose to invest in proven, less risky upstream opportunities.

Regulations Incentivise ExtensionsWe believe the extension of the exploration contracts underscores the investor-friendly nature of Colombia's energy framework rather than the potential of its resource base. This is illustrated by its first place rank in our upstream industry risk component within our Latin American Risk/Reward Index (RRI), scoring 85.0 out of a possible 100.0 points.

We believe Colombia's favourable investment dynamics encour-aged ConocoPhillips, CNE and ExxonMobil to secure their positions within this widely undeveloped unconventional market in the event of a market recovery. However, in light of our below-consensus oil price forecasts whereby Brent will average below USD70/bbl through the end of the decade, we do not believe such an opportunity will present itself for the foreseeable future.

Middle Magdalena Shale Will Remain In PlaceMap Of Colombian Hydrocarbon Basins

Source: BMI

In The RedConocoPhillips – Key Profit Metrics, Earnings (LHS) & EPS (RHS)

Source: ConocoPhillips

Colombia Leading The PackLatin America – Upstream Industry Risk Index, Out Of 100

Source: BMI Oil & Gas Risk/Reward Index


Americas Oil & GasVeNezUelA

VENEZUELA

Petrocaribe Nearing Final DaysBMI View: Continued deterioration of the Venezuelan economy and its upstream sector will exacerbate downside pressure on the Petrocaribe programme in 2016. The inauguration of the opposition-led National Assembly will further undermine the Petrocaribe alliance given its reformist agenda.

The continued slide in crude prices will wreak havoc on Venezuela's already tenuous economic situation and undercut any efforts to support upstream development in 2016. This will bring an end to the 20-year-old Petrocaribe oil alliance as Venezuelan national oil company (NOC) Petróleos de Venezuela (PdVSA) will prove un-able to supply member countries.

Not Enough To Go AroundOil production in Venezuela will decline over the next several years owning to chronic underinvestment into the sector which will be exac-erbated by the global industry slowdown. Reduced profitability from sustained lower oil prices, coupled with continued resource manage-ment, will make it difficult for the government to fund its expansive social development programmes, particularly as Petrocaribe members struggle to repay their own debts to Venezuela (see 'External Account Dynamics To Weaken On Venezuelan Instability', February 26 2015).

We expect total output will continue to decline over the next several years, averaging -2.1% y-o-y through 2020. While Venezuela will remain one of the largest crude producers in the region, consist-ent declines do not support a continuation of the oil alliance given elevated domestic demand – due to subsidised fuel prices – coupled with committed volumes of approximately 300,000b/d to China through oil-for-loans arrangements. As such, we do not believe PdVSA will be able to maintain exports of nearly 200,000b/d to Petrocaribe member countries over the next year.

New Leaders Will Not Support Old PoliciesAs the new opposition-led National Assembly takes its place over the next several months, we expect Petrocaribe will be increasingly scrutinised. A sweeping electoral victory on December 6, where the opposition coalition won a veto-proof two-thirds majority, will open the door to their progressive agenda which is broadly against the oil alliance.

The Venezuelan government has already taken steps to phase out the Petrocaribe programme by increasing the interest rate it charges on its oil loans for several members, as well securitising and selling Petrocaribe debt abroad over the past year. However, we expect the new parliament will take further steps to dismantle it. While we acknowledge the potential threat of policymaking gridlock in the coming months, we maintain that the underlying weakness of the country's extractive sector will ultimately deem this programme unsustainable in the near term (see 'Key Risks For 2016', January 6).

This will leave importing member countries at risk of supply shocks and threaten their external accounts as Petrocaribe provides both subsidised oil as well as financial assistance. The risk of a bal-ance of payments crisis will therefore remain elevated for several importers over the next year, including Nicaragua and Belize (see 'External Position Highly Vulnerable To End Petrocaribe', August 10 2015). As such, we believe those reliant upon Venezuelan crude exports will be forced to seek alternative suppliers of crude, develop their own upstream resources, or diversify their power sectors away from oil-fired thermal capacity (see 'Renewables Opportunities Amid Challenging Environment', August 27 2014).

ARGENTINA

Lower Domestic Crude Prices Will Not Deter InvestmentBMI View: The reduction in Argentina's domestic crude prices is a positive signal for upstream investors as the country comes increas-ingly in line with international market standards. Continued reforms within the sector will boost investment into unconventional projects given Argentina's vast resource potential.

On January 5, the newly inaugurated administration of Argentina announced a reduction in the country's mandated domestic crude prices, continuing the presidents' ambitious reform strategy. Specifi-cally, prices for both Medanito and Escalante crudes were reduced by 10-12% in response to continued weakness in global benchmark prices. This has created a significant premium for both grades, de-creasing their international competitiveness.

We believe the reduction of domestic prices will not deter in-vestment into Argentina's underdeveloped resources over the next year. The country's crude prices will remain at a premium, offering

An Unhealthy RelationshipMap Of Petrocaribe Members

Source: D-Maps, BMI

No Recovery In SightVenezuela – Total Liquids Production



Americas Oil & GasArgeNtINA

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some insulation from the broader industry downtrend. This policy, combined with the lifting of capital controls and domestic currency weakness – reducing foreign companies' development costs – will render the country's vast resources highly attractive, forming a bright spot in an otherwise bleak global market (see 'Domestic Policy Pivot Will Drive Investment', December 2 2015).

Vaca Muerta's Prospects On The RiseHolding an estimated 16.2bn bbl of oil resources and 8.7trn cu m of natural gas, the Vaca Muerta shale play is nearing a crucial turning point. We expect upstream developers will scale back investments further in 2016, turning their focus toward finishing major projects. However, producers remain watchful for low-risk opportunities that will offer long-term rewards. Given improving above ground pros-pects in Argentina, we expect developers will position themselves to take advantage of this unique opportunity.

Crucially, Argentina's domestic crude prices will not be reduced enough to render shale developments unprofitable. According to company reports, drilling costs at the Chevron-YPF joint venture – the country's largest upstream project – have fallen substantially over the past several years, from USD11mn in 2011 to approximately USD6.5mn in 2015. This, alongside continued improvements in hydraulic fracturing, will bring commercial breakevens closer to USD50/bbl, below the elevated domestic prices (see 'Vaca Muerta To Drive Production Growth', June 9 2015).

Investor interest in the Vaca Muerta has already begun to strengthen this year, supporting our upbeat production forecast. Specifically, on January 7, Germany-based Wintershall signed a new exploration contract with plans to invest USD110mn in six oil wells through 2017. On the same day, junior operator President Energy announced it would expand its five-well workover program and may drill new wells in 2016. These followed supermajor Exx-onMobil's announcement in December 2015 that it would invest

approximately USD14bn in developing the Vaca Muerta over the next several years.

While President Mauricio Macri has initiated an aggressive pace of market-friendly reforms, we do not believe his administration will do away with the crude price-setting regime in the near future. Originally enacted to boost energy output and protect jobs within the country's hydrocarbon industry, this policy has largely helped support development of Argentina's largely untapped shale resources amid the downturn, particularly by state-owned YPF (see 'High Domestic Oil Price Insulates Shale', January 13 2015).

Unconventional development in Argentina remains in a nascent stage with approximately 400 wells having been drilled throughout the Vaca Muerta to date. As such, production costs remain elevated relative to similar shale projects in the US, rendering this pricing strategy highly valuable.

On The UpswingArgentina – Oil & Natural Gas Production


Former Pricing Policy Deemed UnsustainableFront-Month Brent Price Versus Domestic Crude Prices, USD/bbl

Source: Bloomberg, YPF

Devaluation Will Support Foreign InvestorsArgentina – Average Exchange Rate, ARS/USD

e/f = BMI estimate/forecast. Source: Bloomberg, BMI

bmi americas oil and gas insight march 2016

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