Bank of America - Energy Credit Conference June 2019 - Genesis Energy, LP
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Bank of America – Energy Credit Conference
June 2019
Disclosures & Company Information
Genesis Energy, L.P. NYSE: GEL Investor Relations Contact
Common Unit Market Value ~$2.7 billion(a) InvestorRelations@genlp.com
(713) 860-2500
Convertible Preferred Equity ~$0.8 billion(a)
Corporate Headquarters
Enterprise Value ~$7.0 billion(a)
919 Milam Street, Suite 2100
Annualized Common Unit Distribution $2.20 per unit Houston, TX 77002
Forward-Looking Statements
This presentation includes forward-looking statements within the meaning of Section 21A of the Securities Act of 1933, as amended, and
Section 21E of the Exchange Act of 1934 as amended. Except for the historical information contained herein, the matters discussed in this
presentation include forward-looking statements. These forward-looking statements are based on the Partnership’s current assumptions,
expectations and projections about future events, and historical performance is not necessarily indicative of future performance. Although
Genesis believes that the assumptions underlying these statements are reasonable, investors are cautioned that such forward-looking
statements are inherently uncertain and necessarily involve risks that may affect Genesis’ business prospects and performance, causing
actual results to differ materially from those discussed during this presentation. Genesis’ actual current and future results may be impacted
by factors beyond its control. Important risk factors that could cause actual results to differ materially from Genesis’ expectations are
discussed in Genesis’ most recently filed reports with the Securities and Exchange Commission. Genesis undertakes no obligation to
publicly update any forward-looking statements, whether as a result of new information or future events.
This presentation may include non-GAAP financial measures. Please refer to the presentations of the most directly comparable GAAP
financial measures and the reconciliations of non-GAAP financial measures to GAAP financial measures included in the end of this
presentation.
(a) As of June 3, 2019.
1
Key Investment Considerations
Market Leading Businesses with High Barriers to Entry
1
• Genesis is a market leader in four critical businesses
– (1) Deepwater Gulf of Mexico ("GOM") pipeline transportation, (2) Producer & marketer of U.S. natural soda ash, (3) Producer and
marketer of sodium hydrosulfide (“NaHS”) and (4) Refinery-centric onshore terminals and pipelines
• High barriers to entry including significant fixed entry cost, existing integrated asset footprint and long-term dedicated contracts
Diversified Businesses with Long-Life Infrastructure Assets
2
• Long-life diverse set of infrastructure assets that have been in continuous operations for decades
• Long-term customer relationships fostered over decades of service
Significant Operating Leverage with Minimal Capital Required
3 • Existing asset footprint has significant upside with expected volume growth in 2019 and beyond with little to zero growth capital required
• Self-funding expected 2019 growth capital of
Market Leading Businesses / High Barriers to Entry
Genesis Total LTM
Offshore Pipeline Transportation Segment Margin $716 MM (a)
• Practically irreplaceable integrated asset footprint focused on transporting crude
oil produced from the deepwater Central Gulf of Mexico to multiple onshore
markets 36%
40%
• Contracts structured as life of lease dedications to individual platforms & pipelines $288 MM
• Uniquely positioned with available capacity to capture volumes from incremental
deepwater production 7% 17%
Sodium Minerals & Sulfur Services
• Global low-cost producer of natural soda ash
• World class facilities and reserves located in world’s largest economic natural 36%
trona deposit 40%
$255 MM
• Leading refinery sulfur removal business with consistent cash flow profile
• Integrated logistical footprint and customer relationships across soda ash, caustic
soda and NaHS markets 7% 17%
Onshore Facilities & Transportation
• Integrated suite of refinery-centric onshore crude oil and refined products
pipelines, terminals and related infrastructure
40% 36%
• Leading 3rd party facilitator of feedstocks to ExxonMobil’s (“XOM”) Baton Rouge
$124 MM
refinery
• Certain onshore pipeline and terminal assets integrated with Genesis' Gulf of
Mexico crude pipeline infrastructure 7% 17%
Marine Transportation
• Young, modern fleet of inland boats and heated barges, all asphalt capable, with
almost exclusive focus on intermediate refined products ("black oil") 40% 36%
• 330 kbbl ocean going tanker American Phoenix built in 2012 and under term $49 MM
contract
• Nine ocean going barges / ATBs ranging in size from 65 - 135 kbbls each 7% 17%
Note: Pictures from top to bottom: Ship Shoal 332B Platform, soda ash operations, Port of Baton Rouge terminal tank farm, inland push boat.
(a) Last twelve months total Segment Margin and per segments as of March 31, 2019. 3
Diversified & Long-Life Infrastructure Assets
Key Business Fundamentals Long-Life Infrastructure Assets
Offshore Pipeline Transportation
• Deepwater crude oil production growth • ~2,400 miles of pipelines and platforms focused on
deepwater Gulf of Mexico
• Continued new developments and competitive • Major crude systems have been in operation for
subsea tieback economics decades across a range of crude oil prices from $10
to $140 per barrel
• No direct exposure to crude oil or natural gas prices
‒ Poseidon 1996 and CHOPS 2005
• Properly maintained with useful lives of 50+ years
Sodium Minerals & Sulfur Services • Stable domestic demand for soda ash complimented • Soda ash facilities and mines have been in
by increasing exports continuous operations since 1953 and have a
‒ Soda Ash demand: Glass manufacturing remaining reserve life of 100+ years(a)
(containers, windshields, and windows), • Sulfur services operates critical infrastructure inside
chemicals, detergents and lithium batteries the fence at 10 refinery locations and has 30+ years
• NaHS demand: Copper mining and pulp & paper of operating history
industries • Long-term customer relationships developed from a
track record of quality and reliability
Onshore Facilities & Transportation • Demand pull from refineries • Newly constructed pipeline and terminal assets in
Baton Rouge integrated with ExxonMobil's refinery
• Certain assets underpinned by take-or-pay contracts • Newly constructed pipeline and terminal assets at
with ExxonMobil Texas City and Raceland integrated with Genesis'
offshore footprint helping transport medium sour Gulf
• Expected volume growth from offshore volumes
of Mexico production further downstream to Gulf
delivered to integrated onshore assets
Coast refineries
• Legacy assets underpinned by long-term contracts
and demand pull from refineries
Marine Transportation • Demand for movements of heavy intermediate • Young, efficient fleet with useful life of 30+ years
refined products
• International Maritime Organization (“IMO”) 2020 • Refinery utilization and limited refinery storage
sulfur spec driving demand for hot oil capable fleet leading to absolute need for constant movement /
offtake of intermediate products
• Increasing spread between WTI & Brent crude oil
driving demand for Jones Act equipment
Note: Pictures from top to bottom: South Marsh Island 205 platform, soda ash operations, Raceland terminal tank farm, inland push boat. 4
(a) Based on current production rate in current seam.
Operating Leverage with Minimal Capital Required
Growth Drivers Operating Leverage
Offshore Pipeline Transportation
• Anticipated increase in Gulf of Mexico crude oil • Existing connectivity and excess capacity to capture
volumes driving both near-term and long-term incremental volumes
margin contribution
• Largely fixed operating costs with minimal to zero
increase in variable cost for any incremental
volumes
Sodium Minerals & Sulfur Services • Expected strength in soda ash pricing driven by • Largely fixed operating costs with minimal to zero
emerging middle class and increasing per capita increase in variable cost for any incremental
consumption of soda ash in Asia & Latin America volumes
• Sell every ton of soda ash we can safely produce
Onshore Facilities & Transportation • Pipeline capacity constraints out of Canada driving • Excess capacity and connectivity to capture
increased crude by rail volumes incremental volumes
• Increasing volumes out of Gulf of Mexico delivered • Largely fixed operating costs with minimal to zero
to integrated onshore asset footprint increase in variable cost for any incremental
volumes
Marine Transportation • Improved market conditions could lead to increased • Largely fixed operating costs creates ability to
marine day rates and utilization benefit from any market upturn in day rates and
utilization
• Minimal to zero increase in variable cost or
incremental capital for any increased utilization
Note: Pictures from top to bottom: Garden Banks 72 platform, soda ash operations, Texas City terminal tank farm, bluewater boat and barge. 5
Improving Financial Fundamentals & Guidance
Current Business Segment Outlook
Offshore Pipeline Sodium Minerals & Onshore Facilities & Marine
Transportation Sulfur Services Transportation Transportation
• Expected continued volume growth • Sodium Minerals remains on track • Current spreads between Canada • Continues to perform as expected
for full year guidance for 2019 and the Gulf Coast indicate
• Receiving volumes on Poseidon and • Continued belief that we are at or
tightening in take away capacity,
CHOPS from a 3rd party pipeline ‒ Expect international market near the bottom of the cycle
making rail movements economical
with insufficient capacity to deliver all supply / demand balance to
to our Scenic Station rail facility • Beginning to see strengthening of
of its committed volumes to shore remain tight
• May & June volumes at our Scenic day rates and utilization
• Remain on track to exit 2019 with ‒ International pricing likely to Station rail facility expected to • Encouraged about IMO 2020 with
40-50 kbd of additional volumes strengthen with no appreciable exceed take-or-pay levels hot-oil capable fleet
supply additions in coming years • Expect to see continued volume
• Finalizing agreements for
incremental volumes approaching: • Both the U.S. (natural) and China increases at our Scenic Station rail
(synthetic) are net exporters of facility in 2H 2019
‒ 80 kpd in 2020 (Inc. Atlantis 3)
soda ash • Legacy Onshore Facilities and
‒ 70 kbd in 2021 Transportation business continues
• Sulfur Services business continues
to perform as expected
‒ 150 kbd in 2022 (Inc. Mad Dog 2) to perform as expected
Current Financial Guidance
Key Metrics Guidance Notes 2019E Adjusted EBITDA ($MM)(c)
Long-Term Target
4.00x $760.0
Leverage Ratio (a)
To remain flat for foreseeable future; intend to use
Common Unit Distribution $0.55 per quarter
capital for highest and best use for all stakeholders $715.0 $720.0
Target Common Unit Use excess cash flow to repay credit facility or fund
1.40x – 1.60x
Distribution Coverage (b) organic growth projects $685.0
Assumes reasonable recovery in crude by rail
2019E Adjusted EBITDA (c)
$685 – $715 million $663.6
volumes and expected growth in offshore segment
Assumes reasonable recovery in crude by rail
4Q 2019E Adjusted EBITDA (c) $180 – $190 million
volumes and expected growth in offshore segment
2019E Expected Growth Capital
Unitholder Alignment / Long-Term Value Creation
Unitholder Alignment Long-Term Value Creation
• NO incentive distribution rights (“IDRs”) with non-economic • Management has a track record of acquiring and developing
General Partner (no sponsor) world class infrastructure assets at attractive valuations
– One of the first MLPs to eliminate IDRs in 2010 • Use capital for the highest and best use for all stakeholders
• Management and insiders are fully aligned with public • Common unit distribution of $0.55 per quarter or $2.20 per
common unitholders year
– Own approximately 11% of the outstanding common units • Culture committed to health, safety and environmental
stewardship
• Long-term incentive compensation for management and
employees tied to:
– Increasing available cash flow per unit
– Achieving long-term leverage targets
– Achieving company safety performance goals
7
Business Segment Detail
Offshore Pipeline Transportation Overview
Acquired World Class Footprint in Leading North American Basin
Long-Term Value Creation Stability and Future Growth
• Beginning in 2010 with the acquisition of CHOPS, 1,000 Historical CHOPS & Poseidon gross daily volumes $120
management has acquired an irreplaceable industry leading Disclosed potential growth volumes(b)
900
portfolio of midstream infrastructure in the deepwater Gulf of Avg. Crude Price (WTI) $100
800
Mexico at attractive valuations 150
700
$80
– Total capital spent to obtain footprint: ~$2.2 billion(a) 600 70
$ / bbl
• Integrated footprint has performed throughout the most 80
Kbd
500 $60
50
recent crude oil cycle and is well positioned to capture 400
incremental volumes with little to no capital to Genesis $40
300
– Offshore Pipeline Transportation Segment Margin 432 467 467 437
200 393
308 351 $20
• 2018A: $288.2 million 100
• 1Q 2019A Annualized: $305.6 million 0 $0
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Timeline of Key Events
Oct. 2010 - $330 mm July 2014 - $197 mm 2019
Genesis Acquires Genesis and Enterprise complete Remain on track to 2021
50% interest in construction of 50% / 50% owned exit 2019 with 40-50 kbd of Finalizing agreements
CHOPS from Valero SEKCO Pipeline additional volumes for an additional 70 kbd
2010 2011 2014 2015 2019 2020 2021 2022
Oct. 2011 - $205.8 mm July 2015 - $1.5 billion 2020 2022
Genesis Acquires Marathon's Genesis Acquires Enterprise's Finalizing agreements for an Finalizing agreements for
Gulf of Mexico assets, including: Gulf of Mexico assets, including: additional 80 kbd an additional 150 kbd
28% in Poseidon 50% in CHOPS (including Atlantis Phase 3) (including Mad Dog 2)
23% in Eugene Island 36% in Poseidon
29% in Odyssey 50% in SEKCO
(a) Approximate total gross capital spent including both growth and maintenance capital expenditures, net of any divestitures.
(b) Finalizing agreements. 9Offshore Pipeline Transportation Asset Summary
Leading Gulf of Mexico Midstream Service Provider
Deepwater to Shore Crude Oil Pipeline Solutions
• ~2,400 miles of pipelines and associated platforms primarily
located in the Central Gulf of Mexico CHOPS Poseidon Eugene Island Odyssey
• Leading independent midstream service provider uniquely
positioned to provide deepwater producers maximum Capacity ~500 kbd(a) ~350 kbd ~173 kbd(b) ~200 kbd
optionality with access to both Texas and Louisiana markets
– No priority / dependency on affiliated equity production
1Q 2019
• Focused on providing producers a “highway to shore” via our Avg. Daily ~242 kbd ~253 kbd NA(c) ~152 kbd
Cameron Highway Oil Pipeline System (“CHOPS”) and Volume
Poseidon Oil Pipeline ("Poseidon")
Delivery Texas Louisiana Louisiana Louisiana
– Laterals and other associated infrastructure serve as feeders to
CHOPS and Poseidon Mileage 380 358 184 120
• Provide transportation to shore for several of the most prolific Ownership 100% 64% 29% 29%
fields in the Gulf of Mexico
Integrated Infrastructure
Oil Laterals Natural Gas Platforms
Provide field-level Primarily services Multi-purpose
transportation to associated gas production
Overview
CHOPS / production from oil handling and
Poseidon laterals service facilities
Includes
Allegheny, Includes Includes
Selected Constitution, Anaconda, Manta Deepwater
Assets Marco Polo, Ray, Nautilus and Gateway (Marco
SEKCO, Shenzi others Polo) and others
and others
Genesis owned Genesis owned
Delivery Various
infrastructure infrastructure
(a) Includes capacity from pumps that could be installed at Garden Banks 72.
(b) Represents gross system capacity. System operates as an undivided joint interest. Genesis net capacity of ~39 kbd including associated laterals.
10
(c) System operates as an undivided joint interest and total volume is not available. Genesis net volumes of ~8 kbd.Gulf of Mexico Crude Oil Production
Continued Growth in the Deepwater
Gulf of Mexico Crude Oil Production(a)
• Deepwater Gulf of Mexico crude oil production has increased by
~59% since 2013 and total Gulf of Mexico production is forecasted Non-Deepwater Deepwater (>1,000 ft.) Avg. Crude Price (WTI)
to add an additional ~517 kbd by 2020(a) 2,500
2,270
$120
• Production increase has been primarily driven by producers’ ability
1,940 $100
to leverage existing infrastructure, improved drilling efficiency and 2,000
1,680 1,753
lower costs 1,604
1,515 $80
($ / bbl)
– Existing platforms provide installed production processing capacity 1,500 1,399
(kbd)
1,258
with existing pipeline connectivity to shore $60
– New discoveries within ~30 miles of existing production facilities are 1,000
often subsea "tied back" to existing infrastructure $40
• 29 new fields have started producing since 2015 500
$20
– 20 of these fields are tiebacks to existing production facilities
• New developments and subsea tiebacks continue to drive 0 $-
2013 2014 2015 2016 2017 2018 2019E 2020E
increasing deepwater production
Select Producer Commentary(b) Select Platform & Field Development History(c)
“Overall across the Gulf, we see six to seven projects that quite frankly we GEL Lateral GEL Lateral GEL Lateral GEL Lateral
didn't see just 18 months ago….And I think I would say from a development to CHOPS / to CHOPS / to CHOPS / to CHOPS /
cost per barrel perspective, we're continuing to drive it down. In our overall Poseidon Odyssey Poseidon Poseidon Poseidon
portfolio, our cost per barrel are down by 20% over the last couple of years”
"At Chevron, we see deep water as a material part of our overall upstream Constitution Delta House Lucius Marco Polo Shenzi
portfolio, and as such we have put together the size, the scale and the (70 kbd) (100 kbd) (80 kbd) (120 kbd) (100 kbd)
organizational capability needed to be successful in the Gulf of Mexico"
“We continue to build on the many accomplishments that we have achieved
at LLOG in the deepwater Gulf of Mexico. We had a number of significant
achievements in 2018, including bringing on eight new wells, continued Field, First Oil Field, First Oil Field, First Oil Field, First Oil Field, First Oil
exploration successes and being named operator in new projects." Constitution, 2007 Son of Bluto, 2015 Lucius, 2014 Marco Polo, 2004 Shenzi, 2009
Ticonderoga, 2007 Marmalard, 2015 Hadrian North, 2019 K2, 2005
“The teams are now working to commission and safely bring Appomattox Caesar/Tonga, 2013 Otis, 2016 Buckskin, 2019
5 additional prospects located
on-stream later this year. And since we made the investment decision in Constellation, 2019 Blue Wing Olive, 2 additional within 30 miles
Appomattox, we have reduced costs of that project with 40% further 2018 prospects located
1 additional
improving the competitiveness of that project…" prospect located La Femme, 2018 within 30 miles
within 30 miles Producing
Red Zinger, 2018 Planned tiebacks
(a) Source: BSSE and EIA’s March 2019 short term energy outlook forecast. Nearly Headless
(b) Conference call quotes per Seeking Alpha. CVX comments per 2018 OTC conference. Nick, 2019 11
(c) Platform capacity numbers are design capacity. Actual volumes, in some cases, have been higher.Central Gulf of Mexico Overview
Robust Inventory of Future Growth
Ram Powell
Petronius
Stonefly
Horn Mountain
Delta House
Nearly Headless Nick
Selected Recent Developments / Key FID
Field Producer First Oil
Stampede Hess 2018
Buckskin LLOG Est. 2019
Lobster
Constellation Anadarko 2019
Katmai
Hadrian North Anadarko 2019 Bullwinkle • Caicos
Droshky • Khaleesi / Mormont
Baldpate Allegheny
Nearly Headless Nick LLOG Est. 2019 • Samurai
• Warrior
Cardamom
Stonefly LLOG Est. 2019 Front Runner • Wildling
Constellation
Atlantis Phase 3 BP Est. 2020 Shenzi
Constitution Atlantis / Atlantis Phase 3
Mad Dog 2 BP Est. 2022 North Ticonderoga
Platte Mad Dog / Mad Dog 2
Guadalupe Heidelberg
Connected to Genesis Footprint Shenandoah
Big Foot
Coronado
Gila Tiber Yucatan
Kaskida • Caesar / Tonga
• Calpurnia
• Genghis Khan
• Holstein
Julia • K2
Leon
Moccasin • Marco Polo
St. Malo • Tahiti
Jack
Buckskin Lucius
Hadrian North
Phobos
Note: Map not intended to be an exhaustive list of prospects.
12Central Gulf of Mexico Midstream Dynamics
Uniquely Positioned with Available Capacity to Capture Additional Volumes
CHOPS / Poseidon Available Capacity to Shore(a)
• Uniquely positioned with maximum optionality and available capacity to
provide a “highway to shore” for deepwater producers 1,000
850 850 850 850
– CHOPS / Poseidon have ample capacity to service the continued
growth in Central Gulf production with a shore based solution 750
– Integrated system allows producer to choose transportation to either
kbd
500
Texas or Louisiana via CHOPS / Poseidon to take advantage of
224 252 253
premium pricing 226
250
– CHOPS is only system in the Central Gulf of Mexico with delivery 242
181 225 202
onshore to Texas -
• Laterals and existing infrastructure well positioned to capture future 2Q18 3Q18 4Q18 1Q19
volumes CHOPS Poseidon Available Capacity
Central Gulf of Mexico Deepwater to Shore Crude Oil Pipeline Solutions
Delivery TX City, TX / Houma, LA /
Gibson, LA Fourchon, LA
Locations Port Arthur, TX Raceland, LA
Amberjack 24”
Auger 20”
Poseidon 24”
CHOPS 30”
EIPS 20”
Paths to
Shore
CHOPS 30”
CHOPS/ CHOPS/
Strategic Poseidon
Poseidon Poseidon
Junction Platform GC 19
Platform Platform
Platforms Poseidon 16” SMI 205 Poseidon 20”
GB 72 SS 332 A&B
Amberjack
Constitution
Marco Polo
Allegheny
SEKCO
Integrated
Caesar
Shenzi
Infrastructure
/ Laterals
Deepwater Alaminos Canyon / Garden Banks /
Green Canyon / Walker Ridge Volumes
Production Keathley Canyon Volumes
(a) Includes capacity from pumps that could be installed at Garden Banks 72. Genesis owned & operated infrastructure 3rd Party owned & operated infrastructure Directly connected to GEL Texas City, TX and GEL Raceland, LA terminals 13Sodium Minerals Overview
Largest North American Producer of Low Cost Natural Soda Ash
• Market leading position with highly consistent cash flow profile Genesis has Largest Trona Lease Holding in U.S.
and significant barriers to entry
• ~4 million tons per year of natural soda ash production with an
estimated remaining reserve life of over 100 years(a) in current
seam
• Reserves located in world’s largest trona deposit, accounting
for over 80% of the world's economically viable soda ash(b)
• Facilities have been in continuous operation since 1953
• Diverse range of industries and end-market demand including
glass, chemicals, soaps and detergents
– Essential component to glass manufacturing
Lowers energy usage
Genesis
Increases workability of the molten glass
Soda Ash Production Facilities
Westvaco
ELDM Mono I & II Sesqui Granger
Year Built 1996 Mono I: 1972 / Mono II: 1976 1953 1976
Feed Solution Dry Ore Dry Ore Solution
Products Dense Ash Dense Ash Light, Dense & Fine Ash, S-Carb Dense Ash
Approximate % Genesis Production 22% 39% 26% 13%
(a) Based on 2018 production rate.
(b) USGS estimates based on 2018 data. Assumes Green River trona accounts for ~87% of US natural soda ash reserves based on 2009 USGS data. 14Natural Soda Ash Cost Advantage
Low Cost Position Drives Stable Cash Flow Generation
• Global low cost soda ash producer Natural vs. Synthetic Production(a)
– Average cost to produce natural soda ash is ~50% of the cost to Solvay
U.S. Natural China HOU
produce synthetic soda ash Process
– Synthetic soda ash consumes substantially more energy, incurs Salt (brine), Salt (brine),
additional costs associated with by-products and has a greater Raw
Trona Ore Limestone, Limestone,
carbon footprint Materials
Ammonia Carbon Dioxide
• Cost advantage allows Genesis to compete on global market
– Sold out 100% of production in each of the last 10 years Energy 4-6 10 - 14 10 - 14
Usage MMBtu / ton MMBtu / ton MMBtu / ton
• Genesis has been the technological innovator since the first
natural soda ash plant was built in Wyoming
Calcium Ammonium
– The “know how” and size and scale of the world’s largest trona
By-Products None Chloride Chloride
mine and soda ash facility gives us unique advantages over (waste product) (co-product)
our competitors
2018 Global Production Capacity(a) Relative Production Cost(a)
U.S. Natural 2.3x
19%
1.9x
1.8x
Solvay Process
45%
Others 1.0x
14%
China Hou
U.S. Natural EU Solvay China Solvay China Hou
22%
(a) Per IHS and Company estimates. 15Soda Ash Supply / Demand Outlook
Supply / Demand Balance Expected to Remain Tight
• Turkey expansion (Kazan) ~2.5 million metric tons per year Soda Ash Demand by Geography(a)
fully absorbed by market as evidenced by continued rise in
2013 - 2017 CAGR: 2017 - 2021 CAGR:
export pricing 2.6% 2.7%
CAGR
• No significant global natural supply expected to be online for 30.9 '13-'17 '17-'21
3+ years 27.8
25.2 1.5% 2.1%
• U.S. demand is relatively stable 5.6% 4.1%
• Domestic soda ash competitively positioned vs. global high 1.4% 2.4%
cost synthetic to supply export growth in freight advantaged
markets of Asia and Latin America 2.8% 2.2%
• Global demand (ex-China) expected to grow 800-900K MT per 2.9% 2.5%
year(a) 3.2% 2.9%
–Driven by emerging middle class and increasing per capita 2013 2017 2021
consumption in Asia and Latin America Latin America Asia (Ex-China)(b)
MEA Europe
• Both the U.S. (natural) and China (synthetic) are net exporters Indian Subcontinent Turkey
of soda ash
Global Supply Sources(a) 2018 Genesis Sales Volume by Geography
Low Cost
Latin America
Natural
North America 24%
Production
26% 43%
High Cost
Synthetic Asia-Pacific
74% 29%
EMEA
4%
Note: MEA stands for Middle East and Africa. EMEA stands for Europe, Middle East and Africa.
(a) In millions of metric tons. Per IHS, Company estimates and USGS. Ex-China, Ex-US and Canada.
16
(b) Includes Australia, Hong Kong, Indonesia, Japan, Malaysia, Myanmar, New Zealand, North Korea, Other Southeast Asia, Philippines, Singapore, South Korea, Taiwan, Thailand and Vietnam.Sulfur Services Overview
Market Leader of NaHS Production and Leading Provider of Sulfur Removal Services
• Market leading position with highly consistent cash flow profile Production Process and Sales Overview
and significant barriers to entry to replicate both asset and Nat Gas
NaHS Trucks
marketing footprint H2S
NaHS Unit Barges & Ships
• Consistent cash flow generation through all economic cycles "Gas Processing" Terminals
Nat Gas
• Long-term relationships with both refineries and customers Refiners Rail Cars
spanning 30+ years
• Sour “Gas Processing” units inside the fence at 10 refineries NaHS End Markets
play integral role in sulfur removal for each refinery Mining (54%) Pulp & Paper (31%) Others (15%)
– Run in parallel or in lieu of traditional sulfur removal units Chemical
Tanning
– Reliable and trusted operator of owned assets inside refinery
fence Environmental
• Produce NaHS through proprietary process utilizing Caustic Sulfur Removal Units
Soda (“NaOH”) reacted with high H2S gas
Relationship Annual
Refinery Operator Location History Capacity (DST)
• Take NaHS in kind as compensation for sulfur removal
services and sell NaHS primarily to large mining, pulp & paper Phillips 66 Westlake, LA 25 Years 110,000
and other customers: Holly Refinery Tulsa, OK 5 Years 24,000
Holly Refinery Salt Lake City, UT 9 Years 21,000
– ~80% of our cost of goods is NaOH
Citgo Corpus Christi, TX 15 Years 20,000
– ~75% of our sales contracts are indexed to caustic soda prices Delek El Dorado, AR 35 Years 15,000
(cost-plus)
Chemtura El Dorado, AR 15 Years 10,000
– Remaining ~25% of our contracts are adjustable (typically 30 Albemarle Magnolia, AR 35 Years 8,000
days advance notice) Ergon Refinery Vicksburg, MS 35 Years 6,000
Cross Oil Smackover, AR 25 Years 3,000
Ergon Refinery Newell, WV 35 Years 2,800
17Onshore Facilities & Transportation Overview
Integrated Asset Footprint with Exposure to Significant Refinery Demand
Baton Rouge Complex Texas City Terminal Raceland Terminal Other Legacy Onshore Assets
• Underpinned by take-or-pay (“ToP”) • Underpinned by ToP contracts with • Connection to Genesis owned • Crude oil pipelines in Mississippi,
contracts with ExxonMobil ExxonMobil and operated Poseidon pipeline Alabama & Florida
• Integral part of ExxonMobil’s Baton • Connection to Genesis owned • Rail unloading facility capable of • 270 miles of CO2 pipelines;
Rouge refinery logistics and slate and operated CHOPS pipeline handling 2 unit trains per day underpinned by long-term contracts
• Rail unloading facility (Scenic • Destination point for various Gulf of • Downstream pipeline delivery points • Crude and refined products storage
Station) capable of handling over 2 Mexico grades including CHOPS / include St. James, LA via LOCAP & / marketing
unit trains per day HOOPS ExxonMobil’s Baton Rouge refinery • ~200 trucks & ~300 trailers
• Connectivity to deepwater import / • Current downstream pipeline via ExxonMobil’s North Line
export docks at Port of Baton Rouge delivery points include ExxonMobil’s • ~400 leased railcars
• Exploring potential connectivity to
• Multiple fee “touch points” for Baytown refinery (via Webster)
pipelines for delivery downstream to
Genesis across the integrated • Exploring potential export export facilities in Louisiana
platform connectivity
Scenic Station Terminal Gulf of Mexico Connectivity
Texas City, TX Raceland, LA
LOCAP to St. James
GEL 18” Pipeline
to Webster XOM Pipeline to
Baton Rouge
Texas City Raceland
Terminal Terminal
Texas City Terminal
GEL Raceland
Houma Pipeline
CHOPS Poseidon
GOM GOM
Raceland Terminal
CHOPS Poseidon
18Asset Snapshot: Baton Rouge Complex
Integrated Crude & Intermediates Logistics Platform
• Integral part of day-to-day refinery logistics and feedstocks for Baton Rouge Complex
Exxon Mobil's Baton Rouge refinery (4th largest U.S. refinery
with 503 kbd of capacity) Port Hudson
Terminal
• Scenic Station is the primary home for Imperial / ExxonMobil's
equity Canadian production (Kearl, Cold Lake) that moves via
rail
Scenic Station
– Portion of volume is consumed at the refinery and remainder is Terminal
exported both internationally and domestically via Baton Rouge
Terminal (“BRT”) or Port Hudson Terminal
• Baton Rouge Terminal activity driven by (i) steady supply of XOM Refinery
vacuum gas oil (“VGO”) imports consumed by the refinery, (ii)
distressed opportunistic crude imports consumed by the Baton Rouge
refinery and (iii) rail exports from Scenic Station Terminal
Value Proposition – Multiple “Touch Points” for Genesis to Earn Fees
• Deliver barrels by pipeline to XOM refinery / Port Hudson / BRT
Port • 440 kbbls total shell tank storage capacity
Hudson Scenic
• Unload 100+ car unit trains from Alberta & other markets
Terminal Station
• Connected to Canadian National (direct) & Canadian Pacific (via KCS)
Terminal
Railroads
• Capable of receiving and unloading over 2 unit trains per day
Baton • Receive barrels by pipeline from Scenic Station & load ships for export
Rouge Baton • Receive barrels by ship & deliver barrels by pipeline to XOM refinery
Terminal Rouge • 1,700 kbbls total shell tank storage capacity
XOM Terminal • Connectivity to 2 deepwater docks (Port of Baton Rouge)
Refinery • Import / export capabilities for both crude oil and intermediates
• Receive barrels by barge / truck
Scenic Terminaling Fee • Pipeline delivery to XOM refinery / other area refineries
Station Port
Paid to GEL • Receive barrels by pipeline from Scenic Station & load barges
Terminal Hudson
• 556 kbbls total shell tank storage capacity
Pipeline Fee Terminal
• Origination of 18 mile, 24” pipeline to Scenic Station, XOM refinery and
Paid to GEL Baton Rouge Terminal
19Marine Transportation Overview
Bottom of the Cycle & High Degree of Operating Leverage
Genesis Marine Equipment
• Inland barges are all asphalt capable, heated barges primarily
utilized in black oil service American
Inland Offshore
Phoenix
• American Phoenix currently under term contract with
Total Fleet
investment grade counter party through September of 2020 ~2.3 kbbl ~0.9 kbbl ~0.3 kbbl
Capacity
• Business operates with largely fixed costs and a high degree Capacity
23-39 kbbl 65-135 kbbl 330 kbbl
of operating leverage Range
• Potential increased demand driven by IMO 2020 and widening Push/Tug
33 9 -
Boats
spread between WTI & Brent crude oil
• Younger, more efficient fleet that is well positioned to benefit Barges 82 9 -
from likely retirement of a significant amount of market
capacity Product
- - 1
Tankers
Inland Tank Barges by Age(a) Offshore Barges by Age(b)
160
1200
959 123
120
823
800
>400 barges
572 30+ years old and 80
candidates for 14 barges
retirement 30+ years old and
372 48
400 38 candidates for
272 36
238 40 retirement
207
153 21
9 12
21 2
0 0
0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35 to 40 >40 0 to 5 5 to 10 10 to 15 15 to 20 20 to 25 25 to 30 30 to 35 35+
(a) Per industry research.
(b) Tank barges with 195,000 barrels capacity or less as of December 31, 2018.
20Appendix & Reconciliations
Corporate Information
Debt and Preferred Equity Profile & Corporate Structure
Balance Sheet Overview Corporate Structure(b)
• Committed to long-term leverage ratio of 4.00x(a) Series A
Class A Class B
Convertible
Common Units Common Units
Preferred Units
(122,539,221) (39,997)
• No near-term maturities (24,972,598)
• Self-funding expected 2019 growth capital ofBalance Sheet & Credit Profile
Leverage Ratio & Common Unit Distribution Coverage Ratio
($ in 000s) 3/31/2019
Senior secured credit facility $942,000
Senior Unsecured Notes 2,464,247
Less: Adjustment for short-term hedged inventory (23,600)
Less: Cash and cash equivalents (11,204)
Adjusted Debt(a) $3,371,443
Pro Forma LTM
3/31/2019
Consolidated EBITDA (b) $674,891
Bank EBITDA Adjustments (c) (10,753)
Adjusted Consolidated EBITDA(d) $664,138
Adjusted Debt / Adjusted Consolidated EBITDA 5.08x
1Q 2019
1Q 2019 Reported Available Cash Before Reserves $95,896
1Q 2019 Common Unit Distributions 67,419
Common Unit Distribution Coverage Ratio 1.42x
(a) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized premiums or discounts) less the amount outstanding under our inventory financing
sublimit, less cash and cash equivalents on hand at the end of the period.
(b) Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.
(c) This amount reflects the adjustment we are permitted to make under our senior secured credit facility for purposes of calculating compliance with our leverage ratio. It includes a pro rata portion of projected future annual EBITDA from
material projects (i.e. organic growth) and includes Adjusted EBITDA(using historical amounts and other permitted amounts) since the beginning of the calculation period attributable to each acquisition completed during such
calculation period, regardless of the date on which such acquisition was actually completed. This adjustment may not be indicative of future results.
(d) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility. 23Reconciliation
Segment Margin
($ in 000s) 3 months ended
LTM March 31,
3/31/2019 2019 2018 2017 2016
Net Income Attributable to Genesis Energy, LP $1,845 $15,954 ($6,075) $82,647 $113,249
Corporate general and administrative expenses 65,323 11,100 64,683 60,029 40,905
Depreciation, depletion, amortization and accretion 325,137 79,937 323,208 262,021 230,563
Impairment expense 120,260 - 120,260 - -
Interest expense, net 228,756 55,701 229,191 176,762 139,947
Tax expense (benefit) 1,525 402 1,498 (3,959) 3,342
Gain on sale of assets (42,264) - (42,264) (40,311) -
Equity compensation adjustments 29 65 (112) (940) (317)
Provision for leased items no longer in use (852) (190) (476) 12,589 -
Other - - - 2,962 -
Plus (minus) Select Items, net 16,323 10,595 22,845 42,743 41,882
Segment Margin(a) $716,082 $173,564 $712,758 $594,543 $569,571
(a) Revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation, depletion and amortization), and segment general and administrative expenses, plus our equity in distributable cash
generated by our equity investees.
(b) This amount reflects the adjustment we are permitted to make under our senior secured credit facility for purposes of calculating compliance with our leverage ratio. It includes a pro rata portion of projected future annual EBITDA from
material projects (i.e. organic growth) and includes Adjusted EBITDA (using historical amounts and other permitted amounts) since the beginning of the calculation period attributable to each acquisition completed during such
calculation period, regardless of the date on which such acquisition was actually completed. This adjustment may not be indicative of future results.
24Reconciliation
Available Cash Before Reserves
($ in 000s) 3 months ended
LTM March 31,
3/31/2019 2019 2018 2017 2016
Net income attributable to Genesis Energy, L.P. $1,845 $15,954 ($6,075) $82,647 $113,249
Interest expense, net 228,756 55,701 229,191 176,762 139,947
Income tax expense (benefit) 1,525 402 1,498 (3,959) 3,342
Impairment expense 120,260 - 120,260 - -
Depreciation, depletion, amortization, and accretion 325,137 79,937 323,208 262,021 230,563
EBITDA $677,523 $151,994 $668,082 $517,471 $487,101
Plus (minus) Select Items, net 40,368 12,016 47,949 59,295 45,128
Adjusted EBITDA, net $717,891 $164,010 $716,031 $576,766 $532,229
Maintenance capital utilized (21,780) (6,125) (19,955) (13,020) (7,696)
Interest expense, net (228,756) (55,701) (229,191) (176,762) (139,947)
Cash tax expense (835) (150) (835) (100) (1,200)
Cash distribution to preferred unitholders (6,138) (6,138) - - -
Other (6) - - 2,148 855
Available Cash before Reserves(a) $460,376 $95,896 $466,050 $389,032 $384,241
Less: One-time Gain on Sale of Assets (42,264) (42,264)
Adjusted Available Cash before Reserves $418,112 $ 423,786
Common Unit Distributions $265,998 $67,419 $262,320 $300,625 $321,717
Common Unit Distribution Coverage Ratio(b) 1.57x 1.42x 1.62x 1.29x 1.19x
(a) 2018 & LTM Available Cash before Reserves includes one-time gains on sale of assets of ~$42.3 million.
(b) Distribution Coverage Ratio calculation excludes one-time gains on sale of assets of ~$42.3 million.
25Reconciliation
Adjusted Debt & Adjusted Consolidated EBITDA
($ in 000s)
LTM
Long-term debt 3/31/2019 2018 2017 2016
Senior secured credit facility $942,000 $970,100 $1,099,200 $1,278,200
Senior Unsecured Notes 2,464,247 2,462,363 2,598,918 1,813,169
Less: Adjustment for short-term hedged inventory (23,600) (17,800) (29,000) (74,500)
Less: Cash and cash equivalents (11,204) (10,300) (9,041) (7,029)
(a)
Adjusted Debt $3,371,443 $3,404,363 $3,660,077 $3,009,840
Consolidated EBITDA(b) $674,891 $670,957 $561,961 $532,231
Bank EBITDA Adjustments (c) (10,753) (7,351) 123,815 44,008
Adjusted Consolidated EBITDA(d) $664,138 $663,606 $685,776 $576,239
Adjusted Debt / Adjusted Consolidated EBITDA 5.08x 5.13x 5.34x 5.22x
(a) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized premiums or discounts) less the amount outstanding under our inventory financing
sublimit, less cash and cash equivalents on hand at the end of the period.
(b) Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.
(c) This amount reflects the adjustment we are permitted to make under our senior secured credit facility for purposes of calculating compliance with our leverage ratio. It includes a pro rata portion of projected future annual EBITDA from
material projects (i.e. organic growth) and includes Adjusted EBITDA(using historical amounts and other permitted amounts) since the beginning of the calculation period attributable to each acquisition completed during such
calculation period, regardless of the date on which such acquisition was actually completed. This adjustment may not be indicative of future results.
(d) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility. 26Reconciliation
Select Items
($ in 000s) 3 months ended
LTM March 31,
3/31/2019 2019 2018 2017 2016
Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements (a) ($5,585) ($2,287) ($6,629) ($17,540) ($13,253)
Adjustment regarding direct financing leases (b) 7,822 2,028 7,633 6,921 6,277
Revaluation of certain liabilities and assets - - - - 6,044
Unrealized (gain) loss on derivative transactions excluding fair value hedges,
net of changes in inventory value (8,771) 3,865 (10,455) 9,942 1,790
Loss on debt extinguishment - - 3,339 6,242 -
Adjustment regarding equity investees (c) 23,859 4,828 28,088 31,852 39,276
Other (1,002) 2,161 869 5,326 1,748
Sub-total Select Items, net (Segment Margin)(d) $16,323 $10,595 $22,845 $42,743 $41,882
Applicable only to Adjusted EBITDA and Available Cash before Reserves
Certain transaction costs (e) 7,533 117 9,103 16,833 1,945
Equity compensation adjustments (188) (137) (207) (1,227) (763)
Other 16,700 1,441 16,208 946 2,064
Total Select Items, net(f) $40,368 $12,016 $47,949 $59,295 $45,128
(a) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts
in the period of payment and deduct them in the period in which GAAP recognizes them.
(b) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.
(c) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(d) Represents all Select Items applicable to Segment Margin, Adjusted EBITDA and Available Cash before Reserves.
(e) Represents transaction costs relating to certain merger, acquisition, transition and financing transactions incurred in acquisition activities.
(f) Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves. 27You can also read
