the evolving domestic & global crude oil pricing landscape: an inside look at the gulf coast ...

The Evolving Domestic & Global Crude Oil Pricing Landscape:

An Inside Look at the Gulf Coast Infrastructure & Supply Chain

A GENSCAPE WHITE PAPERNovember 2014

OIL

TABLE OF CONTENTS

Executive Summary 2

The Good Ol Days 2

Canada and the U.S. Midcontinent Bottleneck 4

Horizontal Drilling Brings New Crude to Market 5

Infrastructure Expansion Creates New Markets 8

Storage 10

Islands of Opacity: The Fracturing of the U.S. Gulf Coast Market 11

The Importance of Gulf Coast Market-Level Fundamentals 11

Conclusion 12

Appendix: U.S. Gulf Coast Coverage 13

Suzanne Evans, Senior Oil Product Manager, Genscape Hillary Stevenson, Manager, Supply Chain Network, Genscape

2November 2014The Evolving Domestic & Global Crude Oil Pricing Landscape: An Inside Look at the Gulf Coast Infrastructure & Supply Chain

EXECUTIVE SUMMARYThe unprecedented increase in North American crude oil production over the past five years has significantly changed the fundamental relationship between domestic and global crude oil pricing. Where there was once uniformity and cohesion between the spot U.S. crude market and the global oil market, the recent domestic crude oil production boom of new grades and the end of the Cushing, OK, bottleneck has cut the cord. This, along with the fracturing of the U.S. Gulf Coast market into individual, grade-specific supply hubs, has created a lack of transparency and has caused price volatility both in the traditional U.S. benchmark West Texas Intermediate and other domestic grades.

The massive infrastructure expansion to bring these new crudes to market has exacerbated this opacity and fracturing of the Gulf Coast market. The pace of development and the new connections from the well-head to specific refining centers has created a mismatch between incoming capacity and demand in several areas, further muddying the waters for supply and demand fundamentals. Aggregate fundamental data can no longer paint the picture of the Gulf Coast crude market because of growing production, additional crude grade variety, and the segregation of a holistic regional market into smaller, local segments.

Fundamental transparency enhances market efficiency, reduces market volatility, and sets the foundation for benchmark pricing to emerge. With more than 8 million bpd of refining capacity, the Gulf Coast is quickly becoming the most critical location for crude spot market activity and potential benchmarks to reflect market value for North America. The rapid development and inherent relevance of these key pricing centers creates a need for granular, fundamental data. Genscapes proprietary data for Gulf Coast pipeline flow volumes and crude storage inventories fills that void.

THE GOOD OL DAYSPrior to 2009, the U.S. crude market was completely linked to the global oil market. The relationships between three global crude benchmarks Brent, WTI, and Dubai determined the flow of waterborne crude. The U.S. reliance on oil imports was the foundation for this relationship, and net-short U.S. refiners pulled crude west when needed. Prices dictated this flow, and the fundamentals behind the

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The Evolving Domestic & Global Crude Oil Pricing Landscape: An Inside Look at the Gulf Coast Infrastructure & Supply Chain

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November 2014 3The Evolving Domestic & Global Crude Oil Pricing Landscape: An Inside Look at the Gulf Coast Infrastructure & Supply Chain

prices were transparent. These spreads drove the flows and controlled the price direction for waterborne and domestic crude grade differentials in comparison to WTI.

A decade ago, U.S. crude demand was the price driver for the entire global market. The United States was the largest consumer of crude oil in the world. In 2005, crude import levels were as high as 11 million bpd, as domestic crude oil production stayed just above a nascent 4 million bpd. This dependence of foreign imports, driven in part by voracious U.S. gasoline demand, bound the U.S. crude market to the global markets movements and underlying fundamentals.

The U.S. pricing benchmark, WTI, was based in the Midcontinent, where refineries were net-short crude. The price of WTI acted as a signal to the global market of the supply/demand balance in the Midcontinent, mostly drawing crude oil flows towards the United States and up Gulf Coast-originating pipelines such as Enterprises Seaway to Cushing and Marathon-operated Capline to Patoka, IL. Typically, WTI traded at a premium to European benchmark Brent, and when this premium reached a favorable level, typically around a $2-3/bbl, crude flows shifted entirely west to the United States rather than east (a direction controlled by the Dubai benchmarks spread relative to Brent).

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On the Gulf Coast, offshore crude grades and spot import cargoes comprised the regional physical market. Regional refineries were also net-short crude and competed with the Midcontinent refineries for crude. The Gulf Coast grades, such as regional benchmarks Mars and Louisiana Light Sweet (LLS), typically traded at a discount to WTI. However, at times, Gulf Coast grades, WTI and foreign crudes would compete against each other in the US Midcontinent.

The supply/demand fundamentals for the Gulf Coast were transparent. Gulf Coast (PADD 3) inventories compared with Midcontinent (PADD 2/Cushing levels) provided a clear picture as to relative supply between the two regions, as PADD 3 pipelines fed into PADD 2. Moreover,

A unified PADD 3 inventory number can no longer explain what is driving, or can effectively drive, price in these new Gulf Coast spot markets.

Source: EIA, CME Group


storage across the Gulf Coast was typically unified around Louisiana where offshore grades flowed onshore via the Louisiana Offshore Oil Port (LOOP). The influx of incremental crude imports to the United States was measured by PADD 3 import data.

Fundamental data explained the market, as the market construct itself was efficient in nature. The Gulf Coast market tied back to WTI, and both WTI and the Gulf Coast market were in sync with the global crude market.

CANADA AND THE U.S. MIDCONTINENT BOTTLENECKBurgeoning North American crude oil production demolished the U.S. crude markets architecture. The change began in 2010, when Canadian heavy crude started to flow at greater volumes and further south into the Midcontinent thanks to pipeline builds and expansions, such as the construction of TransCanadas Keystone system. This began to supplant the need for waterborne crudes to move north. This isolated the Midcontinent, and WTI, from the Gulf Coast and the global crude market. The benchmark spread between Brent and WTI reacted violently to this isolation. WTI fell to a record discount of $26/bbl relative to Brent in August 2011 due to tightness in the European oil market. The following year in November, WTI fell to a $22/barrel discount relative to Brent as crude inventories in Cushing approached historical highs.

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There was no relief valve for the supply glut that formed in Cushing, as pipelines, such as Capline and Seaway, flowed northward, in the wrong direction. Those directional flows were linked to the traditional crude market architecture. The Gulf Coast refining complex, the largest center of crude oil demand in North America, was closed to Canadian crude. The Gulf Coast remained connected to the global market but was out of sync with WTI to the extent that even sour crudes such as Mars traded at premiums to the U.S. benchmark grade, a higher quality sweet crude.

Source: Genscape, CME Group


HORIZONTAL DRILLING BRINGS NEW CRUDE TO MARKETThe advent of tight oil drilling in U.S. domestic plays in 2011, particularly in the Texas Eagle Ford, Permian Basin and North Dakota Bakken, started to detach the Gulf Coast crude market from the rest of the world. Crude-by-rail movements of Bakken provided a new source of supply for the traditional Light Louisiana Sweet market. Dramatic growth in Eagle Ford and Permian production, along with a huge infrastructure build-out to bring this supply to the Gulf Coast market, helped to displace waterborne imports and unwind the U.S. crude markets connection to the global market.

Permian Basin/WTI: The Permian Basin in West Texas and eastern New Mexico has been the hotbed of domestic onshore conventional oil production for years, and is the source basin for the WTI crude stream. Strong crude prices and developments in horizontal drilling have opened the door to unconventional production there.

Several shale plays exist in the basin, including Wolfcamp, Spraberry, Bone Springs, and Wolffork. The Wolfcamp/Spraberry fields alone have 75 billion barrels of recoverable reserves, according to the U.S. Geological Survey. The Permian is relatively close in proximity to both Cushing (Midcontinent refiners) and the Gulf Coast refining complex, and recent pipeline completions have connected Permian unconventional production to Houston and Nederland.

Current Permian Basin production is just above 1.6 million bpd, and is expected to rise to nearly 2.6 million bpd by year-end 2018, according to Genscape forecasts powered by Spring Rock. This includes both WTI and sour grade West Texas Sour. This rising production has already sparked the development of Permian crude spot markets in Houston as well as Nederland (Beaumont/Port Arthur).

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Source: Genscape forecasts powered by Spring Rock


Bakken: The Williston Basin in North Dakota, Montana, and southern Canada has yielded crude oil production from conventional drilling for some time, but the advent of horizontal drilling in the prolific Bakken and Three Forks shale formations transformed this region into a hub of unconventional crude production. The U.S. Geological Service estimates that these two formations hold 7.4 billion barrels of recoverable reserves. Bakken crude is the standard grade produced in this basin.

Production from the U.S. side of the Williston Basin, the sedimentary basin that contains the productive Bakken shale formation, exceeded 1.2 million bpd in September, according to Genscape. By the end of 2018, Genscape forecasts that U.S. Williston Basin production will breach 1.5 million bpd. The rampant unconventional crude production for Bakken started in 2009, and spurred a flurry of pipeline expansion and rail projects. With this buoyant production, Bakken is finding its way to the three U.S. coasts, specifically St. James, LA, in the Gulf Coast, and is now being delivered in blends against CME Groups NYMEX light sweet crude futures contract.

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Eagle Ford: The Eagle Ford shale play, located in South Texas, is one of the many unconventional oil and gas plays in the U.S. experiencing an unprecedented rate of exploration and production. In 2010, the U.S. Geological Survey estimated the undiscovered oil reserves in the Eagle Ford shale at a mean of 853 million barrels of oil, which could be on the conservative side given reserve estimates from individual producers in the Eagle Ford. For example, EOG Resources, one of the largest producers in the play, estimated the potential reserves of its assets at 690 million barrels of oil alone. Eagle ford is only 100 miles west from the Gulf Coast refining complex.



What also sets the Eagle Ford apart is its quality variability. Bakken, WTI and WTS are consistent in API gravity, but Eagle Ford quality varies from 40 degrees API crude to over 60 degrees API condensate. Crude oil/condensate over 45 degrees API accounts for nearly 40 percent of South Texas crude production, according to Genscape.

Eagle Ford production has ballooned in just a few years to a current 1.6 million bpd, and could top 2.6 million bpd in late 2018, according to Genscape. Between the Permian Basin and Eagle Ford, more than 5 million bpd of Texas crude could reach the Gulf Coast in the next four years. This rapid rise in production sparked a massive build out of pipeline, storage and dock infrastructure in Corpus Christi, TX, and Houston.

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Canadian Oil Sands/Western Canadian Select: Canadas development of its huge oil sands resources in Alberta and the subsequent rise in exports to the United States led to Canada overtaking Saudi Arabia as the main supplier of crude to the United States in 2004. WCS crude, the dominant grade, is primarily heavy and is a natural fit for the Gulf Coast, a demand center with extensive coking capacity. The completion of the Seaway pipeline reversal and Transcanadas Cushing-to-Houston 700,000 bpd Gulf Coast pipeline are bringing more WCS into the Gulf Coast at Houston and Beaumont.

However, Canadian production could be capped by continued delays in the construction of Transcanadas 830,000 bpd Alberta-to-Nebraska Keystone XL pipeline and the lengthy timelines for completion of Canada West Coast pipeline projects, including Kinder Morgans TransMountain and Enbridge Northern Gateway pipelines. Alberta oil sands production has reached 2.1 million bpd and is expected to exceed 4.1 million bpd by 2018, according to Genscape. Takeaway capacity out of Western Canada will be critical for this level of forecasted production to come to fruition.



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INFRASTRUCTURE EXPANSION CREATES NEW MARKETSThe Midcontinent so-called wall of crude, combined with the rapid increase in tight oil production in Texas and North Dakota, has prompted a massive infrastructure build-out to transport, store and market these crudes to the Gulf Coast -- where nearly 47 percent of the U.S. refining capacity resides. This infrastructure build-out, both in crude oil pipelines and storage, is unprecedented and has progressed at a pace almost as rapidly as the surge in domestic crude production.

However, this expansion in crude infrastructure has simultaneously reshaped the Gulf Coast spot market, isolating individual refining centers on the Gulf Coast from each other -- each location with its own unique and opaque supply/demand fundamentals. This has not only created new spot markets, but spot markets that defy the traditional Gulf Coast crude market paradigm.

The Gulf Coast infrastructure build-out has alleviated the Midcontinent crude bottleneck. The bottleneck began to ebb following the Seaway pipeline reversal in 2012, allowing crude to flow south and reach Gulf Coast refiners. The completion of TransCanadas Gulf Coast Project in late 2013 and the upcoming completion of the Seaway Twin line has opened the floodgates, connecting the Gulf Coast back to the rest of North America while distancing those spot markets from global crude as the export wall remained intact.

In addition, recent infrastructure expansions have opened increasing domestic production volumes to Gulf Coast refining centers. Piipeline projects such as Sunoco Permian Express (Phases I and II), Magellan BridgeTex, Magellan Longhorn, Kinder Morgan Crude and Condensate and the upcoming PAA Cactus pipeline were commissioned to transport the ever growing Permian Basin and Eagle Ford production, eliminating the need to ship new barrels north to Cushing in order to be transported south to the Houston and Nederland markets. Now, Gulf Coast refiners have direct access to the Canadian, Midcontinent and West Texas production centers on a massive scale.



But this new infrastructure was not enough; the flood of domestic barrels cued even more infrastructure changes including the eastward reversal of Shells Houma, LA,-to-Houston (Ho-Ho) crude pipeline in late 2013, Centurion South reversal in August 2014, and the restart of ExxonMobils Pegasus South in July 2014. The goal of this infrastructure was to connect Texas crude markets to additional sources of demand and restore previously shut transportation capacity to Nederland.

However, these new crude flow pathways create new logistical issues, particularly in the Permian Basin. With the completion of BridgeTex pipeline, near 300,000 bpd more outgoing pipeline capacity from the Colorado City, TX storage hub exists than incoming capacity, but not for long. It is expected that by the end of 2014, pipeline projects will add 140,000 bpd of Colorado City incoming pipeline capacity and by the middle of 2015, new pipelines will reverse the Colorado City imbalance shifting the pipeline capacity to a net-positive 85,000 bpd. More barrels entering Colorado City than leaving may create a bottleneck for Permian crude.

In Corpus Christi, the Cactus pipeline may create similar logistical issues. More than 1.3 million bpd of pipeline capacity is available to move Eagle Ford crude to Corpus Christi. The 200,000 bpd Cactus pipeline, which will bring Permian sweet and sour crude into Corpus Christi, may add to this. The pipeline will deliver to Gardendale, TX, where up to 40,000 bpd of crude can be railed to St. James; crude can move to Three Rivers, TX, and Corpus Christi via the Plains All American/Enterprise 350,000 bpd Eagle Ford Crude Oil pipeline, which will be expanded to 470,000 bpd (Q2 2015) to accommodate Cactus volumes. Or, crude can route to the Houston market from Three Rivers via the PAA/Enterprise line in combination with Enterprises 350,000 bpd South Texas Crude Oil System.


At the Corpus Christi destination, Eagle Ford crude has access to 1.8 million barrels of storage capacity and the Eagle Ford JV barge dock facility. With this kind of optionality, Eagle Ford barrels may not be displaced. If they are, several condensate stabilization facilities are being constructed, which will allow Eagle Ford stabilized condensate to be exported. All of these infrastructure changes make fundamental data on major crude pipeline flows essential to understanding spot market price shifts.

Total pipeline capacity into Corpus Christi exceeds 1.3 million bpd. But there is mismatch between incoming Eagle Ford barrels and local refining capacity in Corpus Christi. This has positioned the port as a waterborne loading market center, where Eagle Ford can reach destinations from the Gulf Coast to as far north as Canada. Dock space and vessel availability has not kept pace with the need for Eagle Ford exit capacity.

STORAGEFirst came pipelines, second came storage tanks. Since 2013, new Texas crude storage terminals, such as the Enterprise Crude Houston oil terminal (ECHO), Kinder Morgan Galena Park, Kinder Morgan Greens Port Terminal, Magellan Galena Park, Oiltanking Appelt, Buckeye TX Processing, and PAA Corpus Christi Terminal, have been constructed to accommodate the flood of crude oil. This has resulted in more than 10 million barrels of new storage capacity in the Gulf Coast, according to Genscape. And this is but the tip of the iceberg. More than 15 million barrels of new storage capacity is under construction in Houston, Beaumont, Nederland, and Corpus Christi, with another 19 million barrels of proposed storage capacity potentially coming online by 2017, according to Genscape.

However, this new crude storage capacity is unlike that of traditional storage centers: Cushing, St. James or Patoka, IL. These new Gulf Coast storage terminals are widely spread in geography and construction of infrastructure to connect these terminals is ongoing. Because of this, Gulf Coast storage operators will have a difficult time balancing inventories during refinery turnaround season and pipeline disruptions due to limited connectivity and available capacity. Therefore, granular data on crude inventories, available capacity and construction timeframes is essential to understanding the key Gulf Coast supply/demand fundamentals. Aggregate PADD 3 inventory data and delayed twice-yearly storage capacity data, published by the EIA, is simply not sufficient.

More than 15 million barrels of new storage capacity is under construction in Houston, Beaumont, Nederland, and Corpus Christi, with another 19 million barrels of proposed storage capacity potentially coming online by 2017.


ISLANDS OF OPACITY: THE FRACTURING OF THE U.S. GULF COAST MARKETNew sources of crude supply, both domestic and Canadian, have caused fundamental opacity. The new infrastructure landscape is vast and complex, with key pipelines from Cushing, Eagle Ford and the Permian Basin reaching multiple destinations on the Gulf Coast. This has fractured the Gulf Coast crude market into islands of opacity. New domestic crudes and the new connection to Canadian crude shattered the Gulf Coast market into separate, unique pieces of the puzzle.

Each of these markets Corpus Christi, Houston and Beaumont is receiving a variety of different crude grades at different volumes. There is some connectivity via waterborne movements of crude from Texas markets to Louisiana and the Ho-Ho line, but these connections are limited. Infrastructure has not yet addressed the issue of this market center isolation. Instead, these crude grades have traded at severe discounts compared to their economic value because of these logistical constraints. Rather than a homogeneous WTI-Cushing spot market, or a crude blending market like LLS, separate spot markets have developed in each of these centers.

The emergence of these fractured spot markets was the death knell for the traditional U.S. crude market structure. As domestic crude flowed in at increasing rates, crude imports dropped, delinking the Gulf Coast from the global market. U.S. crude imports have declined to as low as 6.8 million bpd in September, the lowest levels since 2000, according to EIA data. This is a far cry from the 11 million bpd highs seen in 2005. As a result, the former unification of the Gulf Coast refining center as one holistic spot market fell apart.

A lack of transparency further complicates this market fracturing. Because of the variety of different grades and localized supply/demand fundamentals, basis differentials to traditional benchmarks like WTI or even LLS in Houston, Corpus Christi and Beaumont vary widely across these grades. The fundamentals themselves for pipeline inflows into these new spot crude hubs and critical storage level information are opaque. This also complicates the ability to compare grades between these different market centers.

THE IMPORTANCE OF GULF COAST MARKET-LEVEL FUNDAMENTALS Traditional fundamental data sources are now incapable of providing transparency for this new market paradigm. The tried-and-true fundamental benchmarks, the U.S. Energy Information Agencys PADD 3 weekly crude inventories and PADD 3 weekly crude imports, do not tell the tale nor do they provide insight as to what is happening in those emerging market centers. The agency aggregates the Gulf Coast with inland Texas on storage, not allowing for any glimpse of granularity. And with domestic crudes supplanting imports at the Gulf Coast, a PADD 3 crude import value is quickly losing relevance.

12 Copyright 2014, Genscape Incorporated. All rights reserved. November 2014The Evolving Domestic & Global Crude Oil Pricing Landscape: An Inside Look at the Gulf Coast Infrastructure & Supply Chain

On the Gulf Coast, market-level fundamentals are what now drives spot market differentials, arbitrage opportunities for waterborne movements, and crude grade valuation by refineries. The EIAs weekly PADD 3 crude oil inventories compile a variety of crude slates: Permian, Eagle Ford, Canadian, LLS, imports, each of which have their own separate and unique supply fundamentals because of the fracturing of the Gulf Coast market.

A decade ago, the reliance on foreign imports, and the relevance of EIA data for PADD 3 inventories, leveled the playing field across all market participants in terms of fundamental information. Gulf Coast refiners competed equally with Midcontinent refiners for the same pool of incremental crude oil imports. The incremental supply of crude was relatively transparent from a fundamental perspective, and there was typically equal opportunity for those imports.

Now with U.S. domestic crude production, the influx of Canadian crude oil into PADD 3, and the vast yet splintered expansion in crude transportation pathways, nothing is equal anymore. The market is split into fragments, leaving participants in the dark. There is no longer unified competition for supply among Gulf Coast refiners. A unified PADD 3 inventory number can no longer explain what is driving, or can effectively drive, price in these new Gulf Coast spot markets.

CONCLUSIONThe recent domestic crude production boom and shifts in traditional crude oil pathways have fundamentally changed the foundation of the Gulf Coast crude oil market. Pricing has completely changed from a benchmark and regional spot market perspective, as those connections between the Midcontinent (Cushing), the Gulf Coast, and the global market are completely undone.

Market participants are struggling to compare worth between these bourgeoning, separate, and opaque spot markets on the Gulf Coast. The shattering of the traditional Gulf Coast crude market into these unconventional fragments underscores the need for new, granular fundamental benchmarks to support market efficiency and spur price benchmark evolution.

Any glimpse into the islands of opacity -- Houston, Corpus Christi and Beaumont -- brings light and critical insight to these evolving spot markets. Genscape, through its network of proprietary monitoring technology for crude pipeline flows and storage levels, provides this unmatched glimpse to key market fundamentals in the Gulf Coast, the probable home of the next pricing benchmarks for North American crude.

THANKS FOR READING!Genscape provides proprietary insight into the entire U.S. Gulf Coast Oil Infrastructure & Supply Chain.

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APPENDIX: U.S. GULF COAST COVERAGE

Planned storage facility monitoring in the Gulf Coast include: *The numbers below reflect operational tanks and tanks under construction effective Oct. 24.

Owner Storage Facility LocationOperational Crude Capacity (bbls)

Number of Operational Tanks

Construction Crude Capacity (bbls)

Number of Construction Tanks

Future Expansion Plan

Houston

Enterprise ECHO Houston 1,650,000 6 4,400,000 11

Enterprise Morgan's Point Houston 100,000 1 0 0

Enterprise Seaway Galena Park Houston 900,000 3 0 0

Enterprise Seaway Texas City Station Texas City 3,296,000 6 600,000 1

Enterprise/P66 Jones Creek Terminal Freeport 5,188,000 12 0 0

ExxonMobil Baytown Refinery Houston 5,108,000 16 313,000 2

ExxonMobil/Genesis Webster Station Webster 1,063,000 11 250,000 2 70,000 bbls

HFOTCO Houston Fuel Oil Terminal Houston 3,200,000 8 0 0

Kinder Morgan Galena Park Houston 0 0 600,000 3

Kinder Morgan Greens Port Terminal Houston 250,000 2 0 0

Kinder Morgan Pasadena Terminal Houston 0 0 0 0up to 1,200,000 bbls

LyondellBassell Houston Refinery Houston 995,000 5 0 0

Magellan East Houston Houston 4,182,000 20 1,100,000 4

Magellan Galena Park Houston 480,000 3 0 0

Marathon Galveston Bay Refinery Texas City 4,630,000 9 0 0

Marathon Texas City Refinery Texas City 1,511,000 7 0 0

Oiltanking Appelt Houston 5,607,000 18 3,615,000 10 727,000 bbls

OiltankingOiltanking Houston Terminal

Houston 9,265,000 32 80,000 1

P66 Freeport Terminal Freeport 958,000 3 0 0

Petrobras Pasadena Refining System Houston 2,351,000 8 0 0

Phillips 66 Sweeny Refinery Sweeny 1,240,000 4 0 0

Shell Deer Park Refinery Houston 2,110,000 7 0 0

Targa Channelview Terminal Houston 80,000 1 0 0

700,000 bbls total storage (products & condensate) to be added with 35,000 bpd splitter

TransCanada Houston Tank Terminal Houston 0 0 700,000 2 700,000 bbls

Valero Houston Refinery Houston 1,475,000 6 0 0

Valero Texas City Refinery Texas City 2,361,000 7 0 0

Total: 58,000,000 195 11,658,000 36


Planned storage facility monitoring in the Gulf Coast include: *The numbers below reflect operational tanks and tanks under construction effective Oct. 24.

Owner Storage Facility LocationOperational Crude Capacity (bbls)

Number of Operational Tanks

Construction Crude Capacity (bbls)

Number of Construction Tanks

Future Expansion Plan

Beaumont/Nederland

ExxonMobil Beaumont Refinery Beaumont 2,575,000 11 0 0

GT Logistics GT OmniPort Port Arthur 220,000 4 0 02,280,000 to 4,780,000 bbls

Jefferson RefineryPort of Beaumont Transload Terminal

Beaumont 200,000 2 500,000 51,400,000 bbls

Motiva Port Arthur Refinery Port Arthur 3,310,000 15 0 0

Oiltanking Beaumont Terminal Beaumont 0 0 0 0up to 6,200,000 bbls

OiltankingOiltanking Port Neches Terminal

Port Neches 3,903,000 12 750,000 3

Phillips 66 Beaumont Terminal Nederland 4,686,000 21 0 0

Sunoco Logistics Nederland Terminal Nederland 20,794,000 60 4,120,000 8

Total Petrochemical Refinery Port Arthur 4,000,000 16 0 0

Valero Lucas Station Beaumont 1,915,000 7 0 0

Valero Port Arthur Refinery Port Arthur 2,457,000 8 0 0

Total: 44,060,000 156 5,370,000 16

Corpus Christi

Buckeye Buckeye Texas Processing Corpus Christi 750,000 5 0 0

Buckeye Buckeye Texas Hub Corpus Christi 585,000 6 0 0

CCI Corpus Christi Terminal Corpus Christi 0 0 0 0

3,250,000 bbls condensate/crude storage with splitter

Citgo Corpus Christi Corpus Christi 3,000,000 8 0 0

Flint Hills Corpus Christi East Corpus Christi 910,000 3 0 0

Flint Hills Corpus Christi West Corpus Christi 1,449,000 6 150,000 1

Flint Hills Ingleside Terminal Ingleside 2,841,000 15 0 0

Koch Viola Station Corpus Christi 300,000 2 0 0

Magellan Corpus Christi Terminal Corpus Christi 1,714,000 8 0 0

876,000 bbls condensate/crude storage with splitter

Martin Midstream Martin Terminal Corpus Christi 900,000 9 0 0

NuStar North Beach Terminal Corpus Christi 1,600,000 4 0 0

PAA Corpus Christi Terminal Corpus Christi 1,820,000 7 260,000 1

PAA Viola Barge Dock Corpus Christi 0 0 0 012 crude/condensate tanks

Valero Corpus Christi East Corpus Christi 1,764,000 9 0 0

Valero Corpus Christi West Corpus Christi 3,140,000 19 600,000 2

Total: 20,773,000 101 1,010,000 4

(Continued):


Planned and targeted pipeline monitoring in the Gulf Coast include:*Please note that these are preliminary targets that may change as the Genscape team completes research and feasibility assessments.

Pipeline Name Owner Capacity (bpd)

Houston

BridgeTex Magellan/Occidental 300,000

Houston to Houma Shell 375,000

Kinder Morgan Crude & Condensate Kinder Morgan 300,000

Longhorn Magellan 275,000

Rancho Enterprise/Magellan 350,000

Seaway Enterprise 400,000

Seaway Twin Enterprise 450,000

Nederland

Pegasus ExxonMobil 95,000

TransCanada Gulf Coast TransCanada 700,000; exp to 830,000

Upcoming Additional Pipelines:

Pipeline Owner Capacity Origin Destination Operational StatusGSCP FS Status

Cactus Pipeline PAA200000; exp 250,000

McCamey, TX Gardendale U/C-Apr 2015 Mar 2015

Double Eagle Magellan & KinderMorgan100,000; exp 150,000

Gardendale, TX Corpus ChristiOper for 3Riv to CC; KMCC connection exp Q1 2015

Mar 2015

Permian Express Sunoco 150,000 Wichita Falls, TX Nederland Operational Not likely

Permian Express II Sunoco 200,000 Colorado City, TX Wortham U/C-Q2 2015 Mar 2015

West Texas Gulf Sunoco 300,000 Colorado City, TXLongview, TX; southern route from Wortham to Nederland

Operational October

Jones Creek to Echo Lateral

Enterprise 850,000Jones Creek Terminal

ECHO Operational Not feasible

Echo to Beaumont Lateral

Enterprise 784,000 ECHO Terminal Beaumont/Port Arthur Operational Not feasible

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the evolving domestic & global crude oil pricing landscape: an inside look at the gulf coast ...

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