Delaware
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76-0513049
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units
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NYSE
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Large accelerated filer
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x
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Accelerated filer
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¨
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Non-accelerated filer
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o
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Smaller reporting company
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¨
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Page
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Item 1
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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•
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demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, caustic soda and CO
2
, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;
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throughput levels and rates;
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changes in, or challenges to, our tariff rates;
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our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
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service interruptions in our pipeline transportation systems, and processing operations;
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shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell such products;
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risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
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changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;
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the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and oil spill in the Gulf;
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planned capital expenditures and availability of capital resources to fund capital expenditures;
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our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;
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loss of key personnel;
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cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level or continue to increase quarterly cash distributions in the future;
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an increase in the competition that our operations encounter;
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cost and availability of insurance;
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hazards and operating risks that may not be covered fully by insurance;
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our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow;
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changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;
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natural disasters, accidents or terrorism;
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changes in the financial condition of customers or counterparties;
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adverse rulings, judgments, or settlements in litigation or other legal or tax matters;
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the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and
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the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.
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Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;
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Optimizing our existing assets and creating synergies through additional commercial and operating advancement;
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Leveraging customer relationships across business segments;
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Attracting new customers and expanding our scope of services offered to existing customers;
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Expanding the geographic reach of our businesses;
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Economically expanding our pipeline and terminal operations;
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Evaluating internal and third party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and
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Focusing on health, safety and environmental stewardship.
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Increase the relative contribution of recurring and throughput-based revenues, emphasizing longer-term contractual arrangements;
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Prudently manage our limited commodity price risks;
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Maintain a sound, disciplined capital structure; and
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Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.
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We have limited commodity price risk exposure.
The volumes of crude oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our exposure to movements in the price of the commodity, although we cannot completely eliminate commodity price exposure. Our risk management policy requires us to monitor the effectiveness of the hedges to maintain a value at risk of such hedged inventory not in excess of
$2.5 million
. In addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance between NaHS supply and demand.
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Our businesses encompass a balanced, diversified portfolio of customers, operations and assets
. We operate five business segments and own and operate assets that enable us to provide a number of services primarily to refiners, crude oil and natural gas producers, and industrial and commercial enterprises that use NaHS and caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to common customers across segments. Our businesses are primarily focused on providing (i) onshore-based refinery-centric crude oil and refined products transportation and handling services and (ii) offshore crude oil and natural gas pipeline transportation services in the Gulf of Mexico to mostly integrated and large independent energy companies. We are not dependent upon any one customer or principal location for our revenues.
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Some of our onshore and offshore pipeline transportation and related assets are strategically located.
Our pipelines are critical to the ongoing operations of our refiner and producer customers. In addition, a majority of our terminals are located in areas that can be accessed by truck, rail or barge.
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We believe we are one of the largest marketers of NaHS in North and South America.
We believe the scale of our well-established refinery services operations as well as our integrated suite of assets provides us with a unique cost advantage over some of our existing and potential competitors.
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Our supply and logistics business is operationally flexible.
Our portfolio of trucks, railcars, barges and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships.
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Our marine transportation assets provide waterborne transportation throughout North America.
Our fleet of barges and boats provide service to both inland and offshore customers within a large North American geographic footprint. There are a limited number of Jones Act qualified vessels participating in U.S. coastwise trade. All of our vessels operate under the U.S. flag and are qualified for U.S. coastwise trade under the Jones Act.
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Our businesses provide relatively consistent consolidated financial performance.
Our historically consistent and improving financial performance, combined with our goal of a conservative capital structure over the long term, has allowed us to increase our distribution for
forty-two
consecutive quarters as of our most recent distribution declaration. During this period,
thirty-seven
of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year, although as in the past, future increases (if any) in our quarterly distribution rate will depend on our ability to execute critical components of our business strategy.
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We are financially flexible and have significant liquidity.
As of
December 31, 2015
, we had
$374.3 million
available under our
$1.5 billion
credit agreement, including up to
$166.2 million
available under the
$200 million
petroleum products inventory loan sublimit, and
$89.4 million
available for letters of credit. Our inventory borrowing base was
$33.8 million
at
December 31, 2015
.
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Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services.
Our extensive understanding of the sulfur removal process and crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets.
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We have an experienced, knowledgeable and motivated executive management team with a proven track record.
Our executive management team has an average of more than 25 years of experience in the midstream sector. Its members have worked in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. Through their equity interest in us, our executive management team is incentivized to create value by increasing cash flows.
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Offshore crude oil pipelines
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Operator
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System Miles
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Design Capacity (Bbls/day)
(1)
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Interest Owned
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Throughput (Bbls/day) 100% basis
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Throughput (Bbls/day) net to ownership interest
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Main Lines
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CHOPS
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Genesis
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380
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500,000
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100
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%
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172,647
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124,928
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Poseidon
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Genesis
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367
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350,000
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64
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%
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259,568
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115,219
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Odyssey
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Shell Pipeline
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120
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200,000
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29
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%
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72,958
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21,158
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Eugene Island Pipeline and Other
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Genesis/Shell Pipeline
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184
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39,000
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23
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%
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13,038
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13,038
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Total
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1,051
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1,089,000
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518,211
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274,343
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Lateral Lines
(2)
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SEKCO
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Genesis
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149
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115,000
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100
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%
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Shenzi Crude Oil Pipeline
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Genesis
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83
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230,000
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100
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%
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Allegheny Crude Oil Pipeline
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Genesis
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40
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140,000
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100
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%
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Marco Polo Crude Oil Pipeline
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Genesis
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37
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120,000
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100
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%
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Constitution Crude Oil Pipeline
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Genesis
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67
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80,000
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100
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%
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Viosca Knoll Crude Oil Pipeline
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Genesis
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6
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5,000
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100
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%
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Tarantula
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Genesis
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4
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30,000
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100
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%
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(1)
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Capacity figures presented represent 100% of the design capacity; except for Eugene Island, which represents our net capacity in the undivided interest (23%) in that system. Ultimate capacities can vary primarily as a result of pressure requirements, installed pumps, related facilities and the viscosity of the crude oil actually moved.
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(2)
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Represents 100% owned lateral crude oil pipelines which, other than our Viosca Knoll Crude Oil Pipeline, ultimately flow into our other offshore crude oil pipelines (including CHOPS and Poseidon) and thus are excluded from main lines above.
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Prior to the July 2015 acquisition of Enterprise's offshore pipeline and services business, we owned 50%, 28%, and 50% of CHOPS, Poseidon, and SEKCO, respectively. After the acquisition, we now own 100%, 64% and 100% of CHOPS, Poseidon and SEKCO, respectively. As our SEKCO volumes ultimately flow into Poseidon and thus are included within our Poseidon volume statistics, we have excluded them from our total for Offshore crude oil pipelines.
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CHOPS.
CHOPS is comprised of
24
- to
30
-inch diameter pipelines designed to deliver crude oil from fields in the Gulf of Mexico to refining markets along the Texas Gulf Coast via interconnections with refineries located in Port Arthur and Texas City, Texas. CHOPS also includes
two
strategically located multi-purpose offshore platforms.
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Poseidon.
The Poseidon system is comprised of
16
- to
24
-inch diameter pipelines to deliver crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. An affiliate of Shell owns the remaining
36%
interest in Poseidon.
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Odyssey.
The Odyssey system is comprised of
12
- to
20
-inch diameter pipelines to deliver crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining
71%
interest in Odyssey.
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Eugene Island.
The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which is
20
inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon Mobil, Chevron, ConocoPhillips and Shell Oil Company.
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SEKCO Pipeline.
SEKCO is a deepwater pipeline serving the Lucius crude oil and natural gas field located in the southern Keathley Canyon area of the Gulf of Mexico that was completed in June 2014. SEKCO has crude oil transportation agreements with seven Gulf of Mexico producers, including Anadarko U.S. Offshore Corporation, Freeport McMoran, Exxon Mobil Corporation, Eni Petroleum US LLC, Petrobras America, Plains Offshore Operations, Inc and Inpex Corporation. Those producers have dedicated their production from Lucius to that pipeline for the life of the reserves. We expect the SEKCO pipeline to also provide capacity for additional projects in the deepwater Gulf of Mexico in the future. SEKCO’s customers commenced paying fees to SEKCO upon completion of its pipeline and commenced crude oil deliveries to the SEKCO pipeline in the first quarter of 2015.
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Shenzi Crude Oil.
The Shenzi Crude Oil Pipeline gathers crude oil production from the Shenzi production field located in the Green Canyon area of the Gulf of Mexico offshore Louisiana for delivery to both our CHOPS and Poseidon pipeline systems.
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Allegheny Crude Oil.
The Allegheny Crude Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with the CHOPS and Poseidon pipelines.
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Marco Polo Crude Oil.
The Marco Polo Crude Oil Pipeline transports crude oil from our Marco Polo crude oil platform to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164.
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Constitution Crude Oil.
The Constitution Crude Oil Pipeline gathers crude oil from the Constitution, Caesar Tonga and Ticonderoga production fields located in the Green Canyon area of the Gulf of Mexico for delivery to either the CHOPS or Poseidon pipelines.
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Offshore natural gas pipelines
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Operator
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System Miles
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Design Capacity (MMcf/day)
(1)
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Interest Owned
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Independence Trail
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Genesis
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135
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1,000
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100
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%
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Viosca Knoll Gathering System
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Genesis
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107
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600
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100
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%
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High Island Offshore System
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Genesis
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287
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500
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100
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%
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Matagorda Gathering System
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Genesis
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59
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450
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100
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%
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Falcon Natural Gas Pipeline
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Genesis
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14
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400
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100
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%
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Anaconda Gathering System
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Genesis
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183
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300
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100
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%
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Green Canyon Laterals
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Genesis
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34
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213
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Various
(2)
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Manta Ray Offshore Gathering System
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Enbridge
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237
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800
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25.7
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%
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Nautilus System
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Enbridge
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101
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600
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25.7
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%
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Total
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1,157
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4,863
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(1)
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Capacity figures presented represent 100% of the design capacity.
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(2)
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We proportionately consolidate our undivided interests, which range from 2.7% to 33.3%, in 28 miles of the Green Canyon Lateral pipelines. The remainder of the laterals are wholly owned.
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Independence Trail.
The Independence Trail pipeline transports natural gas from the Independence Hub platform and a pipeline interconnect downstream of the Independence Hub platform to the Tennessee Gas Pipeline at a pipeline interconnect on the West Delta 68 pipeline junction platform. Natural gas transported on the Independence Trail Pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico.
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Viosca Knoll Gathering System.
Viosca Knoll gathers natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico for delivery to several major interstate pipelines,
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High Island.
The High Island Offshore System (HIOS) transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of Mexico to interconnects with the TC Offshore system and Kinetica Energy Express. HIOS includes 201 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system included the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.
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Matagorda Gathering System.
Matagorda gathers natural gas from producing fields in the Matagorda Island area of the Gulf of Mexico for delivery to interconnecting onshore pipelines located in Matagorda and Calhoun counties in Texas. This system includes two pipeline junction platforms.
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Falcon.
The Falcon Natural Gas Pipeline transports natural gas processed at the Falcon Nest platform to a connection with the Central Texas Gathering System located at the Brazos Addition Block 133 platform. In November 2015, we received notice from producers regarding their intent to shut down the remaining producing wells as processed by the Falcon Nest Platform and shipped on the Falcon pipeline in 2016. Such pipeline and processing volumes have been historically insignificant to our offshore pipeline transportation segment.
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Anaconda.
The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area of the Gulf of Mexico for delivery to the Nautilus System.
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Green Canyon.
The Green Canyon Laterals represent a collection of small diameter pipelines that gather natural gas for delivery to HIOS and various other downstream pipelines.
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Manta Ray.
The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico for delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline junction platforms.
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Nautilus.
The Nautilus System connects the Anaconda Gathering system and Manta Ray Offshore Gathering System to the Neptune natural gas processing plant located in south Louisiana.
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Offshore hub platform
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Operator
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Water Depth (Feet)
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Natural Gas Capacity (MMcf/day)
(1)
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Crude Oil Capacity (Bbls/day)
(1)
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Interest Owned
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Independence Hub
(2)
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Anadarko
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8,000
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1,000
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N/A
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80
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%
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Marco Polo
(3)
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Anadarko
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4,300
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300
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120,000
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50
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%
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Viosca Knoll 817
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Genesis
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671
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145
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5,000
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100
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%
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Garden Banks 72
(4)
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Genesis
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518
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216
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36,000
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50
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%
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East Cameron 373
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Genesis
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441
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195
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3,000
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100
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%
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Falcon Nest
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Genesis
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389
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400
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3,000
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100
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%
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Total
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2,256
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167,000
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(1)
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Capacity figures presented represent 100% of the design capacity.
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(2)
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We own an 80% consolidated interest in the Independence Hub platform through its majority owned subsidiary, Independence Hub, LLC.
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(3)
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Our ownership interest in the Marco Polo platform is held indirectly through our equity method investment in Deepwater Gateway, LLC.
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(4)
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We proportionately consolidate our undivided interest in the Garden Banks 72 platform.
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Independence Hub.
The Independence Hub platform, which was acquired on July 24, 2015, is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. In December 2015 we were informed by producers that the remaining producing wells connected to the platform have ceased. These wells will be shut down and we expect no further processing volumes. Such processing volumes have historically been insignificant to our offshore pipeline transportation segment.
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Marco Polo.
The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of Mexico.
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•
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Viosca Knoll.
The Viosca Knoll 817 platform primarily serves as a base for gathering deepwater production in the Viosca Knoll area, including the Ram Powell development.
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•
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Garden Banks
. The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks area of the Gulf of Mexico. This platform also serves as a junction platform for the CHOPS and Poseidon pipeline systems.
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East Cameron.
The East Cameron 373 platform processes production from the Garden Banks and East Cameron areas of the Gulf of Mexico.
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Falcon Nest.
The falcon Nest platform, which is located in the Mustang Island East area of the Gulf of Mexico, processes natural gas from the Falcon field. In November 2015, we received notice from producers regarding their intent to shut down the remaining producing wells as processed by the Falcon Nest Platform and shipped on the Falcon pipeline in 2016. Such pipeline and processing volumes have been historically insignificant to our offshore pipeline transportation segment.
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Texas System
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Jay System
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Mississippi System
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Louisiana System
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Wyoming System
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Product
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Crude Oil
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Crude Oil
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Crude Oil
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Crude Oil
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Crude Oil
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Interest Owned
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100%
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|
100%
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|
100%
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|
100%
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|
100%
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Design Capacity (Bbls/day)
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Existing 8" - 60,000
Looped 18" - 275,000
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|
150,000
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45,000
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|
350,000
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|
30,000
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2015 Throughput (Bbls/day)
(1)
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71,906
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16,828
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15,472
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32,481
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|
7,397
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System Miles
|
109
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|
135
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|
235
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|
17
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|
60
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Approximate owned tankage storage capacity (Bbls)
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220,000
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|
230,000
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247,500
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350,000
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248,000
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Location
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West Columbia, TX to Webster, TX
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Southern AL/FL to Mobile, AL
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Soso, MS to Liberty, MS
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Port Hudson, LA to Baton Rouge, LA
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Campbell County, WY to Pronghorn Rail Facility
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Webster, TX to Texas City, TX
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Baton Rouge, LA to Port Allen, LA
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Webster, TX to Houston, TX
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Rate Regulated
|
TXRRC
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|
FERC
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|
FERC
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|
FERC
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|
FERC
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(1)
|
Our Wyoming pipeline system only had throughput for partial year during 2015, as it was placed into service in August 2015.
|
•
|
Texas System
. Our Texas System transports crude oil from West Columbia to several delivery points near Houston, Texas. We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point.
|
•
|
Jay System
. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile, Alabama. That system also includes gathering connections to approximately
49
wells, additional crude oil storage capacity of
20,000
barrels in the field, an interconnect with our Walnut Hill rail facility, a delivery connection to a refinery in Alabama and an interconnection to another common carrier pipeline that delivers crude oil into Mississippi.
|
•
|
Mississippi System.
Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminals and other crude oil infrastructure located in the Midwest. That system is adjacent to several crude oil fields that are in various phases of being produced through tertiary recovery strategy, including CO
2
|
•
|
Louisiana System
. Our Louisiana System transports crude oil from Port Hudson to the Baton Rouge Scenic Station and continues downstream to the Anchorage Tank Farm servicing Exxon Mobil Corporation's Baton Rouge refinery. This refinery is one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity.
|
•
|
Wyoming System.
Our Wyoming System transports crude oil from receipt point stations in Campbell County and Converse County, Wyoming to our Pronghorn Rail Facility. This crude oil pipeline has an initial capacity of approximately 30,000 barrels per day and is supplied by truck volumes and third party gathering infrastructure in the Powder River Basin. This pipeline system became operational in the third quarter of 2015. We have also completed construction of a new 75 mile pipeline from our Pronghorn Rail Facility to a delivery point at our new Guernsey Station in Platte County, Wyoming. This Pronghorn to Guernsey pipeline will have an initial capacity of approximately 45,000 barrels per day and will allow for connectivity to additional downstream pipeline markets at Guernsey, including regional refineries and Cushing, Oklahoma via the Pony Express Pipeline. This pipeline became operational in early 2016.
|
|
Free State Pipeline
|
Product
|
CO
2
|
Interest owned
|
100%
|
System miles
|
86
|
Pipeline diameter
|
20"
|
Location
|
Jackson Dome near Jackson, MS to East Mississippi
|
Rate Regulated
|
No
|
|
Inland
|
|
Offshore
|
|
American Phoenix
|
Aggregate Fleet Design Capacity (Bbls) (in thousands)
|
1,830
|
|
884
|
|
330
|
Individual Vessel Capacity Range (Bbls) (in thousands)
(1)
|
23-39
|
|
65-136
|
|
330
|
|
|
|
|
|
|
Number of:
|
|
|
|
|
|
Push/Tug Boats
|
30
|
|
9
|
|
—
|
Barges
|
66
|
|
9
|
|
—
|
Product Tankers
|
—
|
|
—
|
|
1
|
(1)
|
Represents capacity per barge ranges on our inland and offshore barge, as well as the capacity of our M/T American Phoenix.
|
•
|
incur additional indebtedness or liens;
|
•
|
make payments in respect of or redeem or acquire any debt or equity issued by us;
|
•
|
sell assets;
|
•
|
make loans or investments;
|
•
|
make guarantees;
|
•
|
enter into any hedging agreement for speculative purposes;
|
•
|
acquire or be acquired by other companies; and
|
•
|
amend some of our contracts.
|
•
|
increase our vulnerability to general adverse economic and industry conditions;
|
•
|
limit our ability to make distributions; to fund future working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction or development activities; access capital markets (debt and equity); or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness;
|
•
|
limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate; and
|
•
|
place us at a competitive disadvantage as compared to our competitors that have less debt.
|
•
|
difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
|
•
|
inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and
|
•
|
diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.
|
•
|
using cash from operations;
|
•
|
delaying other planned projects;
|
•
|
incurring additional indebtedness; or
|
•
|
issuing additional debt or equity.
|
•
|
the volumes and prices at which we purchase and sell crude oil, natural gas, refined products, and caustic soda;
|
•
|
the volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery services and the prices at which we sell NaHS;
|
•
|
the demand for our services;
|
•
|
the level of competition;
|
•
|
the level of our operating costs;
|
•
|
the effect of worldwide energy conservation measures;
|
•
|
governmental regulations and taxes;
|
•
|
the level of our general and administrative costs; and
|
•
|
prevailing economic conditions.
|
•
|
the level of capital expenditures we make, including the cost of acquisitions (if any);
|
•
|
our debt service requirements;
|
•
|
fluctuations in our working capital;
|
•
|
restrictions on distributions contained in our debt instruments;
|
•
|
our ability to borrow under our working capital facility to pay distributions; and
|
•
|
the amount of cash reserves required in the conduct of our business.
|
•
|
geographic proximity to the production and/or refineries;
|
•
|
costs of connection;
|
•
|
available capacity;
|
•
|
rates;
|
•
|
logistical efficiency in all of our operations;
|
•
|
operational efficiency in our sulfur removal business;
|
•
|
customer relationships; and
|
•
|
access to markets.
|
•
|
rate structures;
|
•
|
rates of return on equity;
|
•
|
recovery of costs;
|
•
|
the services that our regulated assets are permitted to perform;
|
•
|
the acquisition, construction and disposition of assets; and
|
•
|
to an extent, the level of competition in that regulated industry.
|
•
|
our general partner is allowed to take into account the interest of parties other than us, such as one or more of its affiliates, in resolving conflicts of interest;
|
•
|
our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;
|
•
|
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and its affiliates, retention of counsel, accountants and service providers and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders; and
|
•
|
our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to pay cash distributions to our unitholders.
|
•
|
our unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of cash available for distribution on each unit may decrease;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of our common units may decline.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
unitholders right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.
|
|
Price Range
|
|
Cash
Distributions
(1)
|
||||||||
|
High
|
|
Low
|
|
|||||||
2014
|
|
|
|
|
|
||||||
1st Quarter
|
$
|
56.80
|
|
|
$
|
51.08
|
|
|
$
|
0.5350
|
|
2nd Quarter
|
$
|
57.47
|
|
|
$
|
52.60
|
|
|
$
|
0.5500
|
|
3rd Quarter
|
$
|
56.32
|
|
|
$
|
50.38
|
|
|
$
|
0.5650
|
|
4th Quarter
|
$
|
49.92
|
|
|
$
|
34.57
|
|
|
$
|
0.5800
|
|
2015
|
|
|
|
|
|
||||||
1st Quarter
|
$
|
48.66
|
|
|
$
|
38.65
|
|
|
$
|
0.5950
|
|
2nd Quarter
|
$
|
50.04
|
|
|
$
|
43.44
|
|
|
$
|
0.6100
|
|
3rd Quarter
|
$
|
48.15
|
|
|
$
|
27.40
|
|
|
$
|
0.6250
|
|
4th Quarter
|
$
|
44.32
|
|
|
$
|
30.79
|
|
|
$
|
0.6400
|
|
(1)
|
Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2015
(1)
|
|
2014
(1)
|
|
2013
(1)
|
|
2012
(1)
|
|
2011
(1)
|
||||||||||
Income Statement Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
Offshore pipeline transportation
|
140,230
|
|
|
3,296
|
|
|
3,923
|
|
|
5,508
|
|
|
—
|
|
|||||
Onshore pipeline transportation
|
77,092
|
|
|
83,157
|
|
|
82,585
|
|
|
70,782
|
|
|
62,190
|
|
|||||
Refinery services
|
177,880
|
|
|
207,401
|
|
|
205,985
|
|
|
196,017
|
|
|
201,711
|
|
|||||
Marine transportation
|
238,757
|
|
|
229,282
|
|
|
152,542
|
|
|
118,204
|
|
|
72,688
|
|
|||||
Supply and logistics
|
1,612,570
|
|
|
3,323,028
|
|
|
3,689,795
|
|
|
2,976,850
|
|
|
2,101,208
|
|
|||||
Total revenues
|
$
|
2,246,529
|
|
|
$
|
3,846,164
|
|
|
$
|
4,134,830
|
|
|
$
|
3,367,361
|
|
|
$
|
2,437,797
|
|
Equity of earnings of equity investees
|
$
|
54,450
|
|
|
$
|
43,135
|
|
|
$
|
22,675
|
|
|
$
|
14,345
|
|
|
$
|
3,347
|
|
Income (loss) from continuing operations after income taxes
|
$
|
421,585
|
|
|
$
|
106,202
|
|
|
$
|
84,004
|
|
|
$
|
97,337
|
|
|
$
|
51,371
|
|
Income (loss) from continuing operations after income taxes attributable to Genesis Energy, L.P.
|
$
|
422,528
|
|
|
$
|
106,202
|
|
|
$
|
84,004
|
|
|
$
|
97,337
|
|
|
$
|
51,371
|
|
Income from continuing operations after income taxes available to Common Unitholders
|
$
|
422,528
|
|
|
$
|
106,202
|
|
|
$
|
84,004
|
|
|
$
|
97,337
|
|
|
$
|
51,371
|
|
Income (loss) from continuing operations attributable to Genesis Energy, L.P. per Common Unit: Basic and Diluted
|
$
|
4.10
|
|
|
$
|
1.18
|
|
|
$
|
1.00
|
|
|
$
|
1.24
|
|
|
$
|
0.76
|
|
Cash distributions declared per Common Unit
|
$
|
2.4700
|
|
|
$
|
2.2300
|
|
|
$
|
2.0150
|
|
|
$
|
1.8225
|
|
|
$
|
1.6500
|
|
Balance Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets
|
$
|
306,316
|
|
|
$
|
355,366
|
|
|
$
|
535,223
|
|
|
$
|
404,034
|
|
|
$
|
376,104
|
|
Total assets
(2)
|
$
|
5,459,599
|
|
|
$
|
3,210,624
|
|
|
$
|
2,848,528
|
|
|
$
|
2,101,902
|
|
|
$
|
1,724,625
|
|
Long-term liabilities
(2)
|
$
|
3,136,712
|
|
|
$
|
1,618,276
|
|
|
$
|
1,304,238
|
|
|
$
|
872,756
|
|
|
$
|
682,559
|
|
Partners' capital:
|
|
|
|
|
|
|
|
|
|
||||||||||
Common unitholders
|
2,029,101
|
|
|
1,229,203
|
|
|
1,097,737
|
|
|
916,495
|
|
|
792,638
|
|
|||||
Noncontrolling interests
|
(8,350
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total partners’ capital
|
$
|
2,020,751
|
|
|
$
|
1,229,203
|
|
|
$
|
1,097,737
|
|
|
$
|
916,495
|
|
|
$
|
792,638
|
|
Other Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Volumes—continuing operations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Offshore crude oil pipeline (barrels per day)
|
579,977
|
|
|
446,548
|
|
|
404,787
|
|
|
359,387
|
|
|
120,723
|
|
|||||
Onshore crude oil pipeline (barrels per day)
|
144,084
|
|
|
116,225
|
|
|
104,026
|
|
|
92,897
|
|
|
82,712
|
|
|||||
Natural gas transportation volumes (MMBtus/d)
|
708,556
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
CO
2
pipeline (Mcf per day)
|
161,409
|
|
|
173,770
|
|
|
190,274
|
|
|
186,479
|
|
|
169,962
|
|
|||||
NaHS sales (DST)
|
127,063
|
|
|
150,038
|
|
|
147,297
|
|
|
142,712
|
|
|
147,670
|
|
|||||
NaOH sales (DST)
|
86,914
|
|
|
94,693
|
|
|
87,463
|
|
|
77,492
|
|
|
99,702
|
|
|||||
Crude oil and petroleum products sales (barrels per day)
|
91,074
|
|
|
99,139
|
|
|
99,651
|
|
|
79,174
|
|
|
56,903
|
|
(1)
|
Our operating results and financial position have been affected by acquisitions. For additional information regarding our acquisitions and divestitures during
2015
,
2014
and
2013
, see
Note 3
to our Consolidated Financial Statements included in Item 8.
|
(2)
|
Our long-term liabilities and total assets for all years presented reflect changes in presentation of debt issuance costs as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. See
Note 10
to our Consolidated Financial Statements included in Item 8 for further discussion.
|
•
|
Overview of
2015
Results
|
•
|
Acquisitions, Divestitures and Growth Initiatives
|
•
|
Results of Operations
|
•
|
Other Consolidated Results
|
•
|
Financial Measures
|
•
|
Liquidity and Capital Resources
|
•
|
Commitments and Off-Balance Sheet Arrangements
|
•
|
Critical Accounting Policies and Estimates
|
•
|
Recent Accounting Pronouncements
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Offshore pipeline transportation
|
197,723
|
|
|
71,598
|
|
|
44,530
|
|
|||
Onshore pipeline transportation
|
58,919
|
|
|
61,231
|
|
|
64,349
|
|
|||
Refinery services
|
80,246
|
|
|
84,851
|
|
|
75,361
|
|
|||
Marine transportation
|
103,222
|
|
|
86,239
|
|
|
47,726
|
|
|||
Supply and logistics
|
36,475
|
|
|
43,345
|
|
|
48,394
|
|
|||
Total Segment Margin
|
$
|
476,585
|
|
|
$
|
347,264
|
|
|
$
|
280,360
|
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Offshore crude oil pipeline revenue
|
$
|
115,640
|
|
|
$
|
3,296
|
|
Offshore natural gas pipeline revenue
|
24,590
|
|
|
—
|
|
||
Offshore pipeline operating costs, excluding non-cash expenses
|
(39,685
|
)
|
|
(1,271
|
)
|
||
Distributions from equity investments
|
94,361
|
|
|
71,305
|
|
||
Other
|
2,817
|
|
|
(1,732
|
)
|
||
Offshore Pipeline Transportation Segment Margin
(1)
|
$
|
197,723
|
|
|
$
|
71,598
|
|
|
|
|
|
||||
Volumetric Data 100% basis:
|
|
|
|
||||
Crude oil pipelines (average barrels/day unless otherwise noted):
|
|
|
|
||||
CHOPS
|
172,647
|
|
|
183,726
|
|
||
Poseidon
|
259,568
|
|
|
209,647
|
|
||
Odyssey
|
72,958
|
|
|
46,717
|
|
||
GOPL
(2)
|
13,038
|
|
|
6,458
|
|
||
Total crude oil offshore pipelines
|
518,211
|
|
|
446,548
|
|
||
|
|
|
|
||||
SEKCO
(3)
|
61,766
|
|
|
—
|
|
||
Natural gas transportation volumes (MMBtus/d)
(4)
|
708,556
|
|
|
—
|
|
||
|
|
|
|
||||
Volumetric Data net to our ownership interest
(5)
:
|
|
|
|
||||
Crude oil pipelines (average barrels/day unless otherwise noted):
|
|
|
|
||||
CHOPS
|
124,928
|
|
|
91,863
|
|
||
Poseidon
|
115,219
|
|
|
58,701
|
|
||
Odyssey
|
21,158
|
|
|
13,548
|
|
||
GOPL
(2)
|
13,038
|
|
|
6,458
|
|
||
Total crude oil offshore pipelines
|
274,343
|
|
|
170,570
|
|
||
|
|
|
|
||||
SEKCO
(3)
|
47,705
|
|
|
—
|
|
||
Natural gas transportation volumes (MMBtus/d)
(4)
|
420,464
|
|
|
—
|
|
(1)
|
Offshore Pipeline Transportation segment margin includes approximately $94 million and $71 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2015 and 2014, respectively.
|
(2)
|
One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system.
|
(3)
|
Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO’s transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude until January 2015. As our SEKCO volumes ultimately flow into Poseidon and thus are included within our Poseidon volume statistics, we have excluded them from our total for Offshore crude oil pipelines.
|
(4)
|
Represents volumes per day from the period the pipelines and related assets were acquired in July 2015.
|
(5)
|
Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
|
$
|
44,096
|
|
|
$
|
42,347
|
|
CO
2
tariffs and revenues from direct financing leases of CO
2
pipelines
|
24,169
|
|
|
25,241
|
|
||
Sales of onshore crude oil pipeline loss allowance volumes
|
4,629
|
|
|
9,049
|
|
||
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
(20,795
|
)
|
|
(21,868
|
)
|
||
Payments received under direct financing leases not included in income
|
5,685
|
|
|
5,529
|
|
||
Other
|
1,135
|
|
|
933
|
|
||
Segment Margin
|
$
|
58,919
|
|
|
$
|
61,231
|
|
|
|
|
|
||||
Volumetric Data (average barrels/day unless otherwise noted):
|
|
|
|
||||
Onshore crude oil pipelines:
|
|
|
|
||||
Texas
|
71,906
|
|
|
58,829
|
|
||
Jay
|
16,828
|
|
|
24,131
|
|
||
Mississippi
|
15,472
|
|
|
14,829
|
|
||
Louisiana
(1)
|
32,481
|
|
|
18,436
|
|
||
Wyoming
(2)
|
7,397
|
|
|
—
|
|
||
Onshore crude oil pipelines total
|
144,084
|
|
|
116,225
|
|
||
|
|
|
|
||||
CO
2
pipeline (average Mcf/day):
|
|
|
|
||||
Free State
|
161,409
|
|
|
173,770
|
|
(1)
|
Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.
|
(2)
|
Represents volumes per day from the period the pipeline began operations in August of 2015.
|
•
|
Onshore crude oil pipeline loss allowance volumes, collected and sold, decreased Segment Margin by
$4.4 million
. This decrease is primarily due to the change in the market price of crude oil between the respective periods. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on that system.
|
•
|
With respect to our onshore crude oil pipelines, tariff revenues increased
$1.7 million
, or
4%
, principally due to a net increase in throughput volumes of
27,859
barrels per day, primarily from increases in volumes on our Texas and Louisiana pipeline systems as well as the addition of the Wyoming pipeline system. These increases were partially offset by volume variances on our other onshore pipeline systems. Due to a mix of tariff rates on our onshore
|
•
|
Volumes on our Free State CO
2
pipeline system decreased
12,361
Mcf per day, or
7%
. We provide transportation services on our Free State CO
2
pipeline system through an "incentive" tariff, which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a certain base level on our Free State CO
2
pipeline system have a limited impact on Segment Margin.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
Volumes sold (in Dry short tons "DST"):
|
|
|
|
||||
NaHS volumes
|
127,063
|
|
|
150,038
|
|
||
NaOH (caustic soda) volumes
|
86,914
|
|
|
94,693
|
|
||
Total
|
213,977
|
|
|
244,731
|
|
||
|
|
|
|
||||
Revenues (in thousands):
|
|
|
|
||||
NaHS revenues
|
$
|
137,825
|
|
|
$
|
161,962
|
|
NaOH (caustic soda) revenues
|
42,746
|
|
|
48,610
|
|
||
Other revenues
|
6,686
|
|
|
7,725
|
|
||
Total external segment revenues
|
$
|
187,257
|
|
|
$
|
218,297
|
|
|
|
|
|
||||
Segment Margin (in thousands)
|
$
|
80,246
|
|
|
$
|
84,851
|
|
|
|
|
|
||||
Average index price for NaOH per DST
(1)
|
$
|
581
|
|
|
$
|
589
|
|
Raw material and processing costs as % of segment revenues
|
39
|
%
|
|
43
|
%
|
(1)
|
Source: IHS Chemical
|
•
|
NaHS revenues decreased
15%
primarily due to a decrease in volumes. That decrease primarily resulted from lower total volumes than in 2014 attributable to the bankruptcy of one mining customer, reduced sales to a major customer as it works through an atypical ore seam as a result of a landslide, and increased prior year volumes generated from heavy turn around schedules at certain customers.
|
•
|
We were able to realize benefits from our favorable management of the purchasing (including economies of scale) and utilization of caustic soda in our (and our customers') operations and our logistics management capabilities, which somewhat offset the effects on Segment Margin of decreased NaHS sales volumes.
|
•
|
Caustic soda revenues
decreased
12%
due to a decrease in both caustic sales volumes and our sales price for caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities.
|
•
|
Average index prices for caustic soda
decreased
to
$581
per DST during
2015
compared to
$589
per DST during
2014
. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally changes in caustic soda index prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic on our operating costs.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
Revenues (in thousands):
|
|
|
|
||||
Inland freight revenues
|
$
|
95,588
|
|
|
$
|
92,311
|
|
Offshore freight revenues
|
102,281
|
|
|
82,732
|
|
||
Other rebill revenues
(1)
|
40,888
|
|
|
54,239
|
|
||
Total segment revenues
|
$
|
238,757
|
|
|
$
|
229,282
|
|
|
|
|
|
||||
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
$
|
135,535
|
|
|
$
|
143,043
|
|
|
|
|
|
||||
Segment Margin (in thousands)
|
$
|
103,222
|
|
|
$
|
86,239
|
|
|
|
|
|
||||
Fleet Utilization:
(2)
|
|
|
|
||||
Inland Barge Utilization
|
96.7
|
%
|
|
97.5
|
%
|
||
Offshore Barge Utilization
|
98.7
|
%
|
|
99.6
|
%
|
•
|
An increase in segment margin in
2015
due to a full year of operating results from the M/T American Phoenix (included as part of our offshore marine fleet), which we acquired in November 2014, and higher realized contract rates on several of our oceangoing barges.
|
•
|
The expansion of our inland marine fleet in
2015
, with "new builds" including the addition of
4
inland barges and
7
inland pushboat in
2015
.
|
•
|
utilizing the fleet of trucks, trailers and railcars owned or leased by our supply and logistics segment to transport products (primarily crude oil and petroleum products) for customers;
|
•
|
utilizing various modes of transportation owned by third parties and us to transport products (primarily crude oil and petroleum products) for our own account to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;
|
•
|
purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining;
|
•
|
supplying petroleum products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets;
|
•
|
purchasing products from refiners, transporting the products to one of our terminals and blending the products to a quality that meets the requirements of our customers and selling those products;
|
•
|
railcar loading and unloading activities at our crude-by-rail terminals; and
|
•
|
industrial gas activities, including wholesale marketing of CO
2
and processing of syngas through a joint venture.
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Supply and logistics revenue
|
$
|
1,612,570
|
|
|
$
|
3,323,028
|
|
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
|
(1,479,972
|
)
|
|
(3,167,749
|
)
|
||
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
(96,047
|
)
|
|
(111,548
|
)
|
||
Other
|
(76
|
)
|
|
(386
|
)
|
||
Segment Margin
|
$
|
36,475
|
|
|
$
|
43,345
|
|
|
|
|
|
||||
Volumetric Data (average barrels per day):
|
|
|
|
||||
Crude oil and petroleum products sales:
|
|
|
|
||||
Total crude oil and petroleum products sales
|
91,074
|
|
|
99,139
|
|
||
Rail load/unload volumes
(1)
|
27,044
|
|
|
32,559
|
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
General and administrative expenses not separately identified below:
|
|
|
|
||||
Corporate
|
$
|
37,922
|
|
|
$
|
39,445
|
|
Segment
|
3,608
|
|
|
3,606
|
|
||
Equity-based compensation plan expense
|
4,564
|
|
|
5,111
|
|
||
Third party costs related to business development activities and growth projects
|
18,901
|
|
|
2,530
|
|
||
Total general and administrative expenses
|
$
|
64,995
|
|
|
$
|
50,692
|
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Depreciation on fixed assets
|
$
|
124,207
|
|
|
$
|
73,230
|
|
Amortization of intangible assets
|
20,044
|
|
|
13,436
|
|
||
Amortization of CO
2
volumetric production payments
|
5,889
|
|
|
4,242
|
|
||
Total depreciation and amortization expense
|
$
|
150,140
|
|
|
$
|
90,908
|
|
|
Year Ended December 31,
|
||||||
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Interest expense, senior secured credit facility (including commitment fees)
|
$
|
23,072
|
|
|
$
|
15,592
|
|
Interest expense, senior unsecured notes
|
87,326
|
|
|
60,047
|
|
||
Amortization and write-off of debt issuance costs and premium
|
7,266
|
|
|
4,785
|
|
||
Capitalized interest
|
(17,068
|
)
|
|
(13,785
|
)
|
||
Net interest expense
|
$
|
100,596
|
|
|
$
|
66,639
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Offshore crude oil pipeline revenue
|
$
|
3,296
|
|
|
$
|
3,923
|
|
Offshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
(1,271
|
)
|
|
(1,234
|
)
|
||
Distributions from equity investments
|
71,305
|
|
|
43,670
|
|
||
Other
|
(1,732
|
)
|
|
(1,829
|
)
|
||
Segment Margin
(1)
|
$
|
71,598
|
|
|
$
|
44,530
|
|
|
|
|
|
||||
Volumetric Data 100% basis:
|
|
|
|
||||
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
|
|
|
|
||||
CHOPS
|
183,726
|
|
|
143,854
|
|
||
Poseidon
|
209,647
|
|
|
207,372
|
|
||
Odyssey
|
46,717
|
|
|
44,978
|
|
||
GOPL
|
6,458
|
|
|
8,583
|
|
||
Total crude oil offshore pipelines
|
446,548
|
|
|
404,787
|
|
||
|
|
|
|
||||
SEKCO
(2)
|
—
|
|
|
—
|
|
||
|
|
|
|
||||
Volumetric Data net to our ownership interest
(3)
:
|
|
|
|
||||
Offshore crude oil pipelines (average barrels/day unless otherwise noted):
|
|
|
|
||||
CHOPS
|
91,863
|
|
|
71,927
|
|
||
Poseidon
|
58,701
|
|
|
58,064
|
|
||
Odyssey
|
13,548
|
|
|
13,044
|
|
||
GOPL
|
6,458
|
|
|
8,583
|
|
||
Total crude oil offshore pipelines
|
170,570
|
|
|
151,618
|
|
||
|
|
|
|
||||
SEKCO
(2)
|
—
|
|
|
—
|
|
(1)
|
Offshore Pipeline Transportation segment margin includes approximately $71 million and $44 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2014 and 2013, respectively.
|
(2)
|
Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO's transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude until January 2015. As our SEKCO volumes ultimately flow into Poseidon and thus are included within our Poseidon volume statistics, we have excluded them from our total for Offshore crude oil pipelines.
|
(3)
|
Volumes are the product of our effective ownership interest throughout the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
|
$
|
42,347
|
|
|
$
|
39,627
|
|
CO
2
tariffs and revenues from direct financing leases of CO
2
pipelines
|
25,241
|
|
|
26,342
|
|
||
Sales of crude oil pipeline loss allowance volumes
|
9,049
|
|
|
11,526
|
|
||
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
(21,868
|
)
|
|
(19,217
|
)
|
||
Payments received under direct financing leases not included in income
|
5,529
|
|
|
5,110
|
|
||
Other
|
933
|
|
|
961
|
|
||
Segment Margin
|
$
|
61,231
|
|
|
$
|
64,349
|
|
|
|
|
|
||||
Volumetric Data (average barrels/day unless otherwise noted):
|
|
|
|
||||
Onshore crude oil pipelines:
|
|
|
|
||||
Texas
|
58,829
|
|
|
51,067
|
|
||
Jay
|
24,131
|
|
|
34,933
|
|
||
Mississippi
|
14,829
|
|
|
18,026
|
|
||
Louisiana
(1)
|
18,436
|
|
|
—
|
|
||
Onshore crude oil pipelines total
|
116,225
|
|
|
104,026
|
|
||
|
|
|
|
||||
CO
2
pipeline (average Mcf/day):
|
|
|
|
||||
Free State
|
173,770
|
|
|
190,274
|
|
(1)
|
Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.
|
•
|
Onshore crude oil pipeline loss allowance volumes, collected and sold, decreased Segment Margin by
$2.5 million
. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on this system.
|
•
|
With respect to our onshore crude oil pipelines, tariff revenues increased
$2.7 million
, or 7%, primarily due to a net increase in throughput volumes of
12,199
barrels per day, primarily from the addition of our Louisiana pipeline system and increases in volumes on our Texas pipeline system. Our Louisiana pipeline system is a 17-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm. This system was placed into service during the first quarter of 2014. These increases were partially offset by volume variances on our other onshore pipeline systems. Due to a mix of tariff rates on our onshore pipelines, the impact on onshore crude oil tariffs and revenues from these volume variances largely offset each other.
|
•
|
Onshore pipeline operating costs, excluding non-cash charges, increased
$2.7 million
, due to pipeline integrity maintenance expenditures on our onshore pipelines, employee compensation and related benefit costs and general increases in operating costs inclusive of safety program costs.
|
•
|
Volumes on our Free State CO
2
pipeline system decreased 16,504 Mcf per day, or 9% .We provide transportation services on our Free State CO
2
pipeline system through an "incentive" tariff, which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a certain base level on our Free State CO
2
pipeline system have a limited impact on Segment Margin.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
Volumes sold (in DST):
|
|
|
|
||||
NaHS volumes
|
150,038
|
|
|
147,297
|
|
||
NaOH (caustic soda) volumes
|
94,693
|
|
|
87,463
|
|
||
Total
|
244,731
|
|
|
234,760
|
|
||
|
|
|
|
||||
Revenues (in thousands):
|
|
|
|
||||
NaHS revenues
|
$
|
161,962
|
|
|
$
|
159,125
|
|
NaOH (caustic soda) revenues
|
48,610
|
|
|
50,748
|
|
||
Other revenues
|
7,725
|
|
|
6,987
|
|
||
Total external segment revenues
|
$
|
218,297
|
|
|
$
|
216,860
|
|
|
|
|
|
||||
Segment Margin (in thousands)
|
$
|
84,851
|
|
|
$
|
75,361
|
|
|
|
|
|
||||
Average index price for NaOH per DST
(1)
|
$
|
589
|
|
|
$
|
604
|
|
Raw material and processing costs as % of segment revenues
|
43
|
%
|
|
49
|
%
|
(1)
|
Source: IHS Chemical
|
•
|
NaHS revenues increased
2%
primarily due to a slight increase in volumes. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point.
|
•
|
Our raw material costs related to NaHS decreased correspondingly to the decrease in the average index price for caustic soda. We were able to realize benefits from operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition (including economies of scale) and utilization of caustic soda in our (and our customers') operations, and our logistics management capabilities.
|
•
|
Caustic soda revenues decreased
4%
, primarily due to a decrease in our sales price for caustic soda, which was partially offset by an increase in sales volumes. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.
|
•
|
Average index prices for caustic soda decreased to
$589
per DST during
2014
compared to
$604
per DST during
2013
. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally changes in caustic soda index prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic on our operating costs.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
Revenues (in thousands):
|
|
|
|
||||
Inland freight revenues
|
$
|
92,311
|
|
|
$
|
80,536
|
|
Offshore freight revenues
|
82,732
|
|
|
28,164
|
|
||
Other rebill revenues
(1)
|
54,239
|
|
|
43,842
|
|
||
Total segment revenues
|
$
|
229,282
|
|
|
$
|
152,542
|
|
|
|
|
|
||||
Operating Costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
$
|
143,043
|
|
|
$
|
104,816
|
|
|
|
|
|
||||
Segment Margin (in thousands)
|
$
|
86,239
|
|
|
$
|
47,726
|
|
|
|
|
|
||||
Fleet Utilization:
(2)
|
|
|
|
||||
Inland Barge Utilization
|
97.5
|
%
|
|
99.2
|
%
|
||
Offshore Barge Utilization
|
99.6
|
%
|
|
99.8
|
%
|
•
|
An increase in segment margin in
2014
due to a full year of operating results from our offshore marine transportation business, which we acquired in August
2013
.
|
•
|
The expansion of our inland marine fleet in
2014
, with "new builds" including the addition of
8
inland barges and
2
inland pushboat in
2014
.
|
•
|
The acquisition of the M/T American Phoenix in late
2014
, which became immediately accretive to Segment Margin at that time.
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Supply and logistics revenue
|
$
|
3,323,028
|
|
|
$
|
3,689,795
|
|
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
|
(3,167,749
|
)
|
|
(3,545,830
|
)
|
||
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
|
(111,548
|
)
|
|
(99,179
|
)
|
||
Segment Margin attributable to discontinued operations
|
—
|
|
|
2,378
|
|
||
Other
|
(386
|
)
|
|
1,230
|
|
||
Segment Margin
|
$
|
43,345
|
|
|
$
|
48,394
|
|
|
|
|
|
||||
Volumetric Data (average barrels per day):
|
|
|
|
||||
Crude oil and petroleum products:
|
|
|
|
||||
Continuing operations
|
99,139
|
|
|
99,651
|
|
||
Discontinued operations
|
—
|
|
|
13,110
|
|
||
Total crude oil and petroleum products
|
99,139
|
|
|
112,761
|
|
||
|
|
|
|
||||
Rail load/unload volumes
(1)
|
32,559
|
|
|
19,721
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
General and administrative expenses not separately identified below:
|
|
|
|
||||
Corporate
|
$
|
39,445
|
|
|
$
|
28,517
|
|
Segment
|
3,606
|
|
|
3,302
|
|
||
Equity-based compensation plan expense
|
5,111
|
|
|
9,180
|
|
||
Third party costs related to business development activities and growth projects
|
2,530
|
|
|
5,791
|
|
||
Total general and administrative expenses
|
$
|
50,692
|
|
|
$
|
46,790
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Depreciation on fixed assets
|
$
|
73,230
|
|
|
$
|
46,325
|
|
Amortization of intangible assets
|
13,436
|
|
|
14,560
|
|
||
Amortization of CO
2
volumetric production payments
|
4,242
|
|
|
3,899
|
|
||
Total depreciation and amortization expense
|
$
|
90,908
|
|
|
$
|
64,784
|
|
|
Year Ended December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in thousands)
|
||||||
Interest expense, senior secured credit facility (including commitment fees)
|
$
|
15,592
|
|
|
$
|
11,949
|
|
Interest expense, senior unsecured notes
|
60,047
|
|
|
45,619
|
|
||
Amortization and write-off of debt issuance costs and premium
|
4,785
|
|
|
4,339
|
|
||
Capitalized interest
|
(13,785
|
)
|
|
(13,324
|
)
|
||
Net interest expense
|
$
|
66,639
|
|
|
$
|
48,583
|
|
(1)
|
the financial performance of our assets;
|
(2)
|
our operating performance;
|
(3)
|
the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;
|
(4)
|
the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and
|
(5)
|
our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in thousands)
|
||||||||||
Net income attributable to Genesis Energy, L.P.
|
$
|
422,528
|
|
|
$
|
106,202
|
|
|
$
|
86,109
|
|
Depreciation and amortization
|
150,140
|
|
|
90,908
|
|
|
64,784
|
|
|||
Cash received from direct financing leases not included in income
|
5,685
|
|
|
5,529
|
|
|
5,110
|
|
|||
Cash effects of sales of certain assets and discontinued operations
|
2,811
|
|
|
272
|
|
|
1,910
|
|
|||
Effects of distributable cash generated by equity method investees not included in income
|
43,018
|
|
|
31,093
|
|
|
23,889
|
|
|||
Cash effects of legacy stock appreciation rights plan
|
(785
|
)
|
|
(1,381
|
)
|
|
(5,498
|
)
|
|||
Non-cash legacy stock appreciation rights plan expense (credit)
|
(797
|
)
|
|
(1,996
|
)
|
|
5,704
|
|
|||
Expenses related to acquiring or constructing growth capital assets
|
18,901
|
|
|
2,528
|
|
|
5,791
|
|
|||
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value
|
1,674
|
|
|
(1,413
|
)
|
|
1,313
|
|
|||
Maintenance capital expenditures
(1)
|
—
|
|
|
—
|
|
|
(3,569
|
)
|
|||
Maintenance capital utilized
(1)
|
(3,731
|
)
|
|
(922
|
)
|
|
—
|
|
|||
Non-cash tax expense (benefit)
|
2,787
|
|
|
1,745
|
|
|
(152
|
)
|
|||
Gain on step up of historical basis
|
(332,380
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on debt extinguishment
|
19,225
|
|
|
—
|
|
|
—
|
|
|||
Other items, net
|
2,345
|
|
|
62
|
|
|
674
|
|
|||
Available Cash before Reserves
|
$
|
331,421
|
|
|
$
|
232,627
|
|
|
$
|
186,065
|
|
(1)
|
In the first quarter of 2014, we changed our method of including maintenance capital in our calculation of Available Cash before Reserves to "maintenance capital utilized" rather than "maintenance capital expenditures." For a description of the term "maintenance capital utilized," please see the definition of the term "Available Cash Before Reserves" previously discussed. Maintenance capital expenditures in 2015 and 2014 were $45.2 million and $15.0 million, respectively.
|
•
|
Working capital, primarily inventories;
|
•
|
Routine operating expenses;
|
•
|
Capital growth and maintenance projects;
|
•
|
Acquisitions of assets or businesses;
|
•
|
Interest payments related to outstanding debt; and
|
•
|
Quarterly cash distributions to our unitholders.
|
•
|
The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus
0.5%
of
1%
and (iii) the LIBOR rate for a one-month maturity plus
1%
and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from
1.50%
to
2.50%
on Eurodollar borrowings and from
0.50%
to
1.50%
on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At
December 31, 2015
, the applicable margins on our borrowings were
1.50%
for alternate base rate borrowings and
2.50%
for Eurodollar rate borrowings.
|
•
|
Letter of credit fees range from
1.50%
to
2.50%
based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At
December 31, 2015
, our letter of credit rate was
2.50%
.
|
•
|
We pay a commitment fee on the unused portion of the
$1.5 billion
maximum facility amount. The commitment fee on the unused committed amount will range from
0.250%
to
0.375%
per annum depending on our leverage ratio (
0.375%
at
December 31, 2015
).
|
|
Years Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in thousands)
|
|
|
||||||
Capital expenditures for fixed and intangible assets:
|
|
|
|
|
|
||||||
Maintenance capital expenditures:
|
|
|
|
|
|
||||||
Offshore pipeline transportation assets
|
$
|
1,888
|
|
|
$
|
1,543
|
|
|
$
|
—
|
|
Onshore pipeline transportation assets
|
7,441
|
|
|
4,633
|
|
|
1,104
|
|
|||
Refinery services assets
|
1,555
|
|
|
1,963
|
|
|
608
|
|
|||
Marine transportation assets
|
26,124
|
|
|
5,539
|
|
|
954
|
|
|||
Supply and logistics assets
|
7,665
|
|
|
833
|
|
|
820
|
|
|||
Information technology systems
|
515
|
|
|
474
|
|
|
83
|
|
|||
Total maintenance capital expenditures
|
45,188
|
|
|
14,985
|
|
|
3,569
|
|
|||
Growth capital expenditures:
|
|
|
|
|
|
||||||
Offshore pipeline transportation assets
|
$
|
963
|
|
|
$
|
20
|
|
|
$
|
—
|
|
Onshore pipeline transportation assets
|
227,628
|
|
|
41,978
|
|
|
129,683
|
|
|||
Refinery services assets
|
40
|
|
|
422
|
|
|
2,650
|
|
|||
Marine transportation assets
|
42,885
|
|
|
70,186
|
|
|
28,902
|
|
|||
Supply and logistics
|
166,953
|
|
|
324,297
|
|
|
214,318
|
|
|||
Information technology systems
|
2,243
|
|
|
2,165
|
|
|
2,341
|
|
|||
Total growth capital expenditures
|
440,712
|
|
|
439,068
|
|
|
377,894
|
|
|||
Total capital expenditures for fixed and intangible assets
|
485,900
|
|
|
454,053
|
|
|
381,463
|
|
|||
Capital expenditures for business combinations, net of liabilities assumed:
|
|
|
|
|
|
||||||
Acquisition of American Phoenix
|
—
|
|
|
157,000
|
|
|
—
|
|
|||
Acquisition of offshore marine transportation assets
|
—
|
|
|
—
|
|
|
230,880
|
|
|||
Acquisition of offshore pipelines
(1)
|
1,521,569
|
|
|
—
|
|
|
—
|
|
|||
Total business combinations capital expenditures
|
1,521,569
|
|
|
157,000
|
|
|
230,880
|
|
|||
Capital expenditures related to equity investees
(2)
|
2,900
|
|
|
36,076
|
|
|
94,286
|
|
|||
Total capital expenditures
|
$
|
2,010,369
|
|
|
$
|
647,129
|
|
|
$
|
706,629
|
|
(1)
|
Amounts represent our purchase price (subject to adjustments) for our Enterprise acquisition.
|
(2)
|
Amount represents our investment in the SEKCO pipeline equity investee prior to our Enterprise acquisition (see below for more information).
|
Distribution For
|
|
Date Paid
|
|
Per Unit
Amount
|
|
Total
Amount
|
||||
2013
|
|
|
|
|
|
|
||||
4
th
Quarter
|
|
February 14, 2014
|
|
$
|
0.5350
|
|
|
$
|
47,453
|
|
2014
|
|
|
|
|
|
|
||||
1
st
Quarter
|
|
May 15, 2014
|
|
$
|
0.5500
|
|
|
$
|
48,783
|
|
2
nd
Quarter
|
|
August 14, 2014
|
|
$
|
0.5650
|
|
|
$
|
50,114
|
|
3
rd
Quarter
|
|
November 14, 2014
|
|
$
|
0.5800
|
|
|
$
|
54,112
|
|
4
th
Quarter
|
|
February 13, 2015
|
|
$
|
0.5950
|
|
|
$
|
56,542
|
|
2015
|
|
|
|
|
|
|
||||
1
st
Quarter
|
|
May 15, 2015
|
|
$
|
0.6100
|
|
|
$
|
60,774
|
|
2
nd
Quarter
|
|
August 14, 2015
|
|
$
|
0.6250
|
|
|
$
|
68,737
|
|
3
rd
Quarter
|
|
November 13, 2015
|
|
$
|
0.6400
|
|
|
$
|
70,387
|
|
4
th
Quarter
|
|
February 12, 2016
|
(1)
|
$
|
0.6550
|
|
|
$
|
72,036
|
|
(1)
|
This distribution was paid on
February 12, 2016
to unitholders of record as of
January 29, 2016
.
|
|
Payments Due by Period
|
||||||||||||||||||
Commercial Cash Obligations and
Commitments
|
Less than
one year
|
|
1 - 3 years
|
|
3 - 5 Years
|
|
More than
5 years
|
|
Total
|
||||||||||
|
(in thousands)
|
||||||||||||||||||
Contractual Obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,115,000
|
|
|
$
|
1,807,054
|
|
|
$
|
2,922,054
|
|
Estimated interest payable on long-term debt
(2)
|
114,493
|
|
|
228,987
|
|
|
228,907
|
|
|
207,898
|
|
|
780,285
|
|
|||||
Operating lease obligations
|
23,878
|
|
|
33,101
|
|
|
28,445
|
|
|
82,138
|
|
|
167,562
|
|
|||||
Unconditional purchase obligations
(3)
|
111,173
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111,173
|
|
|||||
Other Cash Commitments:
|
|
|
|
|
|
|
|
|
|
||||||||||
Asset retirement obligations
(4)
|
9,760
|
|
|
65,549
|
|
|
—
|
|
|
113,353
|
|
|
188,662
|
|
|||||
Total
|
$
|
259,304
|
|
|
$
|
327,637
|
|
|
$
|
1,372,352
|
|
|
$
|
2,210,443
|
|
|
$
|
4,169,736
|
|
(1)
|
Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of
July 28, 2019
. We have
$350 million
in aggregate principal amount of senior unsecured notes that mature on
February 15, 2021
(the "2021 Notes"),
$750 million
in aggregate principal amount of senior unsecured notes that mature on
August 1, 2022
(the "2022 Notes"),
$400 million
in aggregate principal amount of senior unsecured notes that mature on
May 15, 2023
(the "2023 Notes"), and
$350 million
in aggregate principal amount of senior unsecured notes that mature on
June 15, 2024
(the "2024 Notes").
|
(2)
|
Interest on our long-term debt under our credit facility is at market-based rates. The interest rates on our 2021, 2022, 2023 and 2024 Notes are
5.75%
,
6.75%
.
6.00%
and
5.625%
, respectively. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at
December 31, 2015
under our credit facility remained outstanding through the final maturity date of
July 28, 2019
and interest rates remained at the
December 31, 2015
market levels through the final maturity date. Also included is the interest on our senior unsecured notes through their respective maturity dates.
|
(3)
|
Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. Contracts to purchase crude oil and petroleum products are generally at market-based prices. For purposes of this table, estimated volumes and market prices at
December 31, 2015
were used to value those obligations. The actual physical volumes and settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.
|
(4)
|
Represents the estimated future asset retirement obligations on an undiscounted basis. The recorded asset retirement obligation on our balance sheet at
December 31, 2015
was
$188.7 million
and is further discussed in
Note 6
to our Consolidated Financial Statements.
|
|
Unit of
Measure
for Volume
|
|
Contract
Volumes
(in 000’s)
|
|
Unit of
Measure
for Price
|
|
Weighed
Average
Market
Price
|
|
Contract
Value
(in 000’s)
|
|
Mark-to
Market
Change
(in 000’s)
|
|
Settlement
Value
(in 000’s)
|
|||||||||
NYMEX Futures Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Sell (Short) Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude Oil
|
Bbl
|
|
491
|
|
|
Bbl
|
|
$
|
37.81
|
|
|
$
|
18,617
|
|
|
$
|
88
|
|
|
$
|
18,705
|
|
Crude Oil Swaps
|
Bbl
|
|
290
|
|
|
Bbl
|
|
$
|
1.28
|
|
|
$
|
372
|
|
|
$
|
(150
|
)
|
|
$
|
222
|
|
Diesel
|
Bbl
|
|
86
|
|
|
Gal
|
(1)
|
$
|
1.30
|
|
|
$
|
4,709
|
|
|
$
|
(563
|
)
|
|
$
|
4,146
|
|
#6 Fuel Oil
|
Bbl
|
|
165
|
|
|
Bbl
|
|
$
|
26.97
|
|
|
$
|
4,451
|
|
|
$
|
(766
|
)
|
|
$
|
3,685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Buy (Long) Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude Oil
|
Bbl
|
|
6
|
|
|
Bbl
|
|
$
|
36.48
|
|
|
$
|
219
|
|
|
$
|
4
|
|
|
$
|
223
|
|
Diesel
|
Bbl
|
|
6
|
|
|
Gal
|
(1)
|
$
|
1.15
|
|
|
$
|
290
|
|
|
$
|
(4
|
)
|
|
$
|
286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
NYMEX Option Contracts
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Written Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude Oil
|
Bbl
|
|
95
|
|
|
Bbl
|
|
$
|
1.50
|
|
|
$
|
142
|
|
|
$
|
(19
|
)
|
|
$
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Purchased Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude Oil
|
Bbl
|
|
35
|
|
|
Bbl
|
|
$
|
0.64
|
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
23
|
|
(1)
|
Prices and volumes as presented as quoted on the NYMEX. To calculate the total contract value the price per unit in gallons should be multiplied by 42 gallons to convert into a price per barrel.
|
(2)
|
Weighted average premium received/paid.
|
Name
|
|
Age
|
|
Position
|
Grant E. Sims
|
|
60
|
|
Director, Chairman of the Board, and Chief Executive Officer
|
Conrad P. Albert
|
|
69
|
|
Director
|
James E. Davison
|
|
78
|
|
Director
|
James E. Davison, Jr.
|
|
49
|
|
Director
|
Sharilyn S. Gasaway
|
|
47
|
|
Director
|
Kenneth M. Jastrow II
|
|
68
|
|
Director
|
Corbin J. Robertson III
|
|
45
|
|
Director
|
Jack T. Taylor
|
|
64
|
|
Director
|
Robert V. Deere
|
|
61
|
|
Chief Financial Officer
|
Paul A. Davis
|
|
52
|
|
Senior Vice President
|
Stephen M. Smith
|
|
39
|
|
Vice President
|
Richard R. Alexander
|
|
40
|
|
Vice President
|
Karen N. Pape
|
|
57
|
|
Senior Vice President and Controller
|
•
|
Grant E. Sims, Chief Executive Officer;
|
•
|
Robert V. Deere, Chief Financial Officer;
|
•
|
Paul A. Davis, Senior Vice President;
|
•
|
Stephen M. Smith, Vice President; and
|
•
|
Richard R. Alexander, Vice President.
|
•
|
encourage our executives to build and operate the partnership in a way that is aligned with our common unitholders’ interests, focusing on growing cash distributions and growing the asset base with an emphasis on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk taking;
|
•
|
offer near-term and long-term compensation opportunities that are consistent with industry norms; and
|
•
|
provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the successful execution of key growth initiatives and projects.
|
•
|
annual cash base salary
|
•
|
discretionary annual cash bonus awards
|
•
|
annual grants under long-term incentive arrangements
|
|
2015
|
Name
|
Bonus Target
(% of base salary)
|
Grant E. Sims
|
100%
|
Robert V. Deere
|
75%
|
Paul A. Davis
|
100%
|
Stephen M. Smith
|
100%
|
Richard R. Alexander
|
100%
|
|
2015
|
||
Name
|
Long-Term Incentive Target
Grant Value
|
||
Grant E. Sims
|
$
|
1,800,000
|
|
Robert V. Deere
|
$
|
900,000
|
|
Paul A. Davis
|
$
|
750,000
|
|
Stephen M. Smith
|
$
|
650,000
|
|
Richard R. Alexander
|
$
|
650,000
|
|
•
|
the company has strong internal financial controls;
|
•
|
base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security;
|
•
|
the determination of incentive awards is based on a review of a variety of indicators of performance as well as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with any single indicator of performance;
|
•
|
goals are appropriately set to avoid targets that, if not achieved, result in a large percentage loss of compensation;
|
•
|
incentive awards are capped by the G&C Committee;
|
•
|
compensation decisions include discretionary authority to adjust annual awards and payments, which further reduces any business risk associated with our plans; and
|
•
|
long-term incentive awards are designed to provide appropriate awards for dedication to a corporate strategy that delivers long-term returns to unitholders.
|
Name & Principal Position
|
Year
|
|
Salary ($)
|
|
Bonus ($) (1)
|
|
Stock
Awards ($) (2)
|
|
All Other
Compensation ($) (4)
|
|
Total ($)
|
||||||||||
Grant E. Sims
|
2015
|
|
$
|
576,923
|
|
|
$
|
—
|
|
|
$
|
1,755,771
|
|
|
$
|
190,851
|
|
|
$
|
2,523,545
|
|
Chief Executive Officer
|
2014
|
|
525,000
|
|
|
—
|
|
|
401,163
|
|
|
182,187
|
|
|
1,108,350
|
|
|||||
(Principal Executive Officer)
|
2013
|
|
517,308
|
|
|
—
|
|
|
1,248,181
|
|
|
196,119
|
|
|
1,961,608
|
|
|||||
Robert V. Deere
|
2015
|
|
450,000
|
|
|
—
|
|
|
658,448
|
|
|
108,449
|
|
|
1,216,897
|
|
|||||
Chief Financial Officer
|
2014
|
|
450,000
|
|
|
—
|
|
|
401,163
|
|
|
102,482
|
|
|
953,645
|
|
|||||
(Principal Financial Officer)
|
2013
|
|
446,923
|
|
|
—
|
|
|
499,291
|
|
|
104,808
|
|
|
1,051,022
|
|
|||||
Paul A. Davis
|
2015
|
|
375,000
|
|
|
243,750
|
|
|
585,287
|
|
|
101,761
|
|
|
1,305,798
|
|
|||||
Senior Vice President
|
2014
|
|
359,615
|
|
|
350,000
|
|
|
601,718
|
|
|
63,838
|
|
|
1,375,171
|
|
|||||
|
2013
|
|
311,154
|
|
|
250,000
|
|
|
424,374
|
|
|
33,843
|
|
|
1,019,371
|
|
|||||
Stephen M. Smith
|
2015
|
|
317,308
|
|
|
225,000
|
|
|
438,966
|
|
|
85,268
|
|
|
1,066,542
|
|
|||||
Vice President
|
2014
|
|
292,308
|
|
|
150,000
|
|
|
401,163
|
|
|
65,071
|
|
|
908,542
|
|
|||||
|
2013
|
|
267,308
|
|
|
—
|
|
|
324,563
|
|
|
59,079
|
|
|
650,950
|
|
|||||
Richard R. Alexander
(3)
|
2015
|
|
317,308
|
|
|
300,000
|
|
|
585,287
|
|
|
112,299
|
|
|
1,314,894
|
|
|||||
Vice President
|
2014
|
|
295,192
|
|
|
300,000
|
|
|
300,859
|
|
|
54,619
|
|
|
950,670
|
|
(1)
|
For 2015, Mr. Davis received a retention bonus of $150,000 and a bonus of
$93,750
, Mr. Smith received a retention bonus of $150,000 and a bonus of
$75,000
and Mr. Alexander received a retention bonus of $100,000 and a bonus of
$200,000
. The retention bonuses granted to these three NEO's were granted in March 2015 and were contingent upon continued employment through July and December 2015.
|
(2)
|
The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units granted under our 2010 Long-Term Incentive Plan. The grant date fair value of each award was determined in accordance with accounting guidance for equity-based compensation and is based on the probable outcome of any underlying performance conditions. Assumptions used in the calculation of these amounts are included in
Note 15
to our Consolidated Financial Statements in Item 8.
|
(3)
|
Mr. Alexander became an executive officer of our general partner in November 2014.
|
(4)
|
The following table presents the components of "All Other Compensation" for each NEO for the year ended
December 31, 2015
.
|
|
|
||||||||||||||
Name
|
401(k) Matching
and Profit
Sharing
Contributions (a)
|
|
Insurance
Premiums
(b)
|
|
Other
Compensation
(c)
|
|
Totals
|
||||||||
Grant E. Sims
|
$
|
10,600
|
|
|
$
|
1,458
|
|
|
$
|
178,793
|
|
|
$
|
190,851
|
|
Robert V. Deere
|
$
|
26,500
|
|
|
$
|
1,458
|
|
|
$
|
80,491
|
|
|
$
|
108,449
|
|
Paul A. Davis
|
$
|
26,500
|
|
|
$
|
1,458
|
|
|
$
|
73,803
|
|
|
$
|
101,761
|
|
Stephen M. Smith
|
$
|
24,100
|
|
|
$
|
1,458
|
|
|
$
|
59,710
|
|
|
$
|
85,268
|
|
Richard R. Alexander
|
$
|
26,500
|
|
|
$
|
1,458
|
|
|
$
|
84,341
|
|
|
$
|
112,299
|
|
(a)
|
Contributions by us to our 401(k) plan on each NEO’s behalf.
|
(b)
|
Term life insurance premiums paid by us on each NEO’s behalf.
|
(c)
|
This column includes cash distributions paid in connection with granted DERs.
|
|
|
|
|
Estimated Future Payouts Under
|
|
|
|
|
|||||||||||
|
|
|
|
Equity Incentive Plan Awards
(1)
|
|
|
|
|
|||||||||||
Name
|
|
Grant Date
|
|
Threshold
|
|
Target
|
|
Maximum
|
|
Market Price of Common Units on Award Date
(2)
|
|
Grant Date Fair Value of Stock and Option Awards
(3)
|
|||||||
Grant E. Sims
|
|
4/14/2015
|
|
19,235
|
|
|
38,470
|
|
|
57,705
|
|
|
$
|
46.79
|
|
|
$
|
1,755,771
|
|
Robert V. Deere
|
|
4/14/2015
|
|
7,214
|
|
|
14,427
|
|
|
21,641
|
|
|
$
|
46.79
|
|
|
$
|
658,448
|
|
Paul A. Davis
|
|
4/14/2015
|
|
6,412
|
|
|
12,824
|
|
|
19,236
|
|
|
$
|
46.79
|
|
|
$
|
585,287
|
|
Stephen M. Smith
|
|
4/14/2015
|
|
4,809
|
|
|
9,618
|
|
|
14,427
|
|
|
$
|
46.79
|
|
|
$
|
438,966
|
|
Richard R. Alexander
|
|
4/14/2015
|
|
6,412
|
|
|
12,824
|
|
|
7,222
|
|
|
$
|
46.79
|
|
|
$
|
585,287
|
|
(1)
|
Represents the number of phantom units that each NEO can earn of grant awarded on
April 14, 2015
, if the company meets certain performance conditions (threshold, target and maximum) during the
fourth quarter of 2017
. See additional discussion in "Long-Term Incentive Compensation" above.
|
(2)
|
Represents the closing market price of our common units on the date of the phantom unit award on
April 14, 2015
.
|
(3)
|
The amounts in this column for each NEO represent the fair value of the award on the date of the grant (as calculated in accordance with accounting guidance for equity-based compensation) using the twenty day average closing price of our common units through the date of grant (
$45.64
).
|
|
|
|
Stock Awards
|
||||
Name
|
Grant Date
|
|
Equity Incentive Plan Awards: Number of Unearned Phantom Units That Have Not Vested (#) (1)
|
Equity Incentive Plan Awards: Market Value of Unearned Phantom Units That Have Not Vested ($) (2)
|
|||
Grant E. Sims
|
4/14/2015
|
|
57,705
|
|
$
|
1,986,206
|
|
|
4/8/2014
|
|
11,111
|
|
$
|
382,441
|
|
|
4/9/2013
|
|
39,861
|
|
$
|
1,372,016
|
|
Robert V. Deere
|
4/14/2015
|
|
21,641
|
|
$
|
744,883
|
|
|
4/8/2014
|
|
11,111
|
|
$
|
382,441
|
|
|
4/9/2013
|
|
15,945
|
|
$
|
548,827
|
|
Paul A. Davis
|
4/14/2015
|
|
19,236
|
|
$
|
662,103
|
|
|
4/9/2014
|
|
16,665
|
|
$
|
573,609
|
|
|
4/9/2013
|
|
13,553
|
|
$
|
466,494
|
|
Stephen M. Smith
|
4/14/2015
|
|
14,427
|
|
$
|
496,577
|
|
|
4/8/2014
|
|
11,111
|
|
$
|
382,441
|
|
|
4/9/2013
|
|
10,365
|
|
$
|
356,763
|
|
Richard R. Alexander
(3)
|
4/14/2015
|
|
19,236
|
|
$
|
662,103
|
|
|
4/8/2014
|
|
7,222
|
|
$
|
248,581
|
|
|
4/9/2013
|
|
6,910
|
|
$
|
237,842
|
|
(1)
|
The number of performance units reflected in the table assumes a maximum performance payout based upon past achievement levels from the previous vesting period. For the service based units reflected in the table above, as only held by Mr. Alexander, the threshold, target, and maximum payouts are identical.
|
(2)
|
The amounts in this column were calculated by multiplying the closing market price of our units using the twenty day average at year-end by the number of applicable units outstanding.
|
(3)
|
Phantom units outstanding for Mr. Alexander include 2,222 and 2,126 service based units for 2014 and 2013, respectively. The remainder of the outstanding units held by Mr. Alexander and represented above are performance based units.
|
|
|
Phantom Unit Awards
|
|||||
Name
|
|
Number of Phantom Units Vested (#)
|
|
Value Realized on Vesting ($)
|
|||
Grant E. Sims
|
|
57,300
|
|
|
$
|
2,590,332
|
|
Robert V. Deere
|
|
22,410
|
|
|
$
|
1,013,078
|
|
Stephen M. Smith
|
|
15,917
|
|
|
$
|
719,529
|
|
Richard R. Alexander
|
|
11,035
|
|
|
$
|
498,831
|
|
Paul A. Davis
|
|
—
|
|
|
$
|
—
|
|
•
|
“Good cause” means, in general, if the executive commits willful theft, embezzlement, forgery; conviction of similar criminal activity; willful violation of our material policies; or substantial non-performance of duties.
|
•
|
“Change of control” means, in general, any sale or other transfer of substantially all of the assets of us or our general partner, other than to our affiliates, or any merger, consolidation, or other transaction pursuant to which more than 50% of our publicly-traded common units or more than 50% of our Class B Common Units ceases to be beneficially owned by the persons who owned such interests as of the date of the employment agreement.
|
•
|
“Good reason” means, in general, the diminution of the executive’s duties, title, reporting relationships, compensation, or benefits, or the relocation of our principal offices or the requirement that the executive be based anywhere other than the Houston, Texas area without his consent.
|
•
|
“Cause” means, in general, if the executive commits theft, embezzlement, forgery, any other act of dishonesty relating the executive’s employment or violates our policies or any law, rule, or regulation applicable to us, is convicted of a felony or lesser crime having as its predicate element fraud, dishonesty, or misappropriation, fails to perform his duties under the employment agreement or commits an act or intentionally fails to act, which act or failure to act amounts to gross negligence or willful misconduct.
|
•
|
“Good Reason” means, in general, following a change of control which results in a substantial diminution of the executive’s duties, compensation, or benefits; executive’s removal from position as Vice President (other than for cause, death or disability, or being offered an equivalent position); or our failure to make any payment to the executive required under the terms of his employment agreement.
|
•
|
“Change of control” means, in general, any sale of equity in us or our general partner or sale of substantially all of our assets; any merger, conversion or consolidation of us or our general partner; or any other event that, in each of the foregoing cases, results in any persons or entities having the ability to elect a majority of the members of our board of directors (other than one or more of our executive officers or affiliates).
|
•
|
“Renewal term” means, in general, each one-year term of employment beginning on July 18 of each year, absent either the Company or the executive giving the other party at least 90 days advance written notice of its intent not to renew the employment agreement between them.
|
|
Richard R. Alexander
|
||
Severance pursuant to employment agreement
|
$
|
325,000
|
|
Healthcare
|
22,607
|
|
|
Total
|
$
|
347,607
|
|
Grant E. Sims
|
$
|
2,493,763
|
|
Robert V. Deere
|
$
|
1,117,411
|
|
Paul A. Davis
|
$
|
1,134,793
|
|
Stephen A. Smith
|
$
|
823,843
|
|
Richard R. Alexander
|
$
|
815,547
|
|
|
Grant E.
Sims
|
|
Robert V.
Deere
|
|
Paul A. Davis
|
|
Stephen M. Smith
|
|
Richard R. Alexander
|
||||||||||
Severance pursuant to employment agreement
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,500,000
|
|
|
$
|
—
|
|
|
$
|
325,000
|
|
Healthcare
|
—
|
|
|
—
|
|
|
33,911
|
|
|
—
|
|
|
22,607
|
|
|||||
Cash payment for vested phantom units under 2010 LTIP
|
2,493,763
|
|
|
1,117,411
|
|
|
1,134,793
|
|
|
823,843
|
|
|
815,547
|
|
|||||
Total
|
$
|
2,493,763
|
|
|
$
|
1,117,411
|
|
|
$
|
2,668,704
|
|
|
$
|
823,843
|
|
|
$
|
1,163,154
|
|
Name
|
Fees Earned or Paid in Cash ($) (1)
|
|
Stock
Awards
($) (2) (3)
|
|
All Other
Compensation
($) (4)
|
|
Total
|
||||||||
James E. Davison
|
$
|
90,000
|
|
|
$
|
100,000
|
|
|
$
|
14,629
|
|
|
$
|
204,629
|
|
James E. Davison, Jr.
|
$
|
92,000
|
|
|
$
|
100,000
|
|
|
$
|
14,629
|
|
|
$
|
206,629
|
|
Sharilyn S. Gasaway
|
$
|
112,500
|
|
|
$
|
112,500
|
|
|
$
|
16,523
|
|
|
$
|
241,523
|
|
Kenneth M. Jastrow II
|
$
|
104,500
|
|
|
$
|
112,500
|
|
|
$
|
16,356
|
|
|
$
|
233,356
|
|
Corbin J. Robertson III
|
$
|
90,000
|
|
|
$
|
100,000
|
|
|
$
|
14,736
|
|
|
$
|
204,736
|
|
Conrad P. Albert
|
$
|
104,500
|
|
|
$
|
102,500
|
|
|
$
|
10,457
|
|
|
$
|
217,457
|
|
Jack T. Taylor
|
$
|
104,500
|
|
|
$
|
102,500
|
|
|
$
|
10,457
|
|
|
$
|
217,457
|
|
(1)
|
Amounts include annual retainer fees and fees for attending meetings.
|
(2)
|
Amounts in this column represent the fair value of the awards of phantom units under our 2010 LTIP on the date of grant, as calculated in accordance with accounting guidance for equity-based compensation.
|
(3)
|
Outstanding awards to directors at
December 31, 2015
consist of phantom units granted under our 2010 LTIP and stock appreciation rights pursuant to our Stock Appreciation Rights Plan. Messrs. James Davison and James Davison, Jr. each hold
5,922
outstanding phantom units and
1,000
stock appreciation rights. Messrs. Jastrow, Robertson, Albert, Taylor and Ms. Gasaway hold
6,658
,
5,952
,
5,126
,
5,126
and
6,681
outstanding phantom units, respectively.
|
(4)
|
Amounts in this column represent the amounts paid for tandem DERs related to outstanding phantom units granted under our 2010 LTIP.
|
|
Number of securities
remaining available for
future issuance under
equity compensation plans
|
Equity Compensation plans approved by security holders:
|
|
2007 Long-term Incentive Plan (2007 LTIP)
|
832,928
|
|
|
Class A Common Units
|
|
Class B Common Units
|
||||||||
Name and Address of Beneficial Owner
|
|
Amount and Nature of Beneficial Ownership
|
(1)
|
Percent of Class
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
||||
Conrad P. Albert
|
|
5,000
|
|
|
*
|
|
|
—
|
|
|
—
|
|
James E. Davison
|
|
3,376,282
|
|
(2)
|
3.1
|
%
|
|
9,453
|
|
|
23.6
|
%
|
James E. Davison, Jr.
|
|
5,323,932
|
|
(3)
|
4.8
|
%
|
|
13,648
|
|
|
34.1
|
%
|
Sharilyn S. Gasaway
|
|
269,445
|
|
|
*
|
|
|
1,081
|
|
|
2.7
|
%
|
Kenneth M. Jastrow II
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Corbin J. Robertson III
|
|
1,811,567
|
|
(4)
|
1.6
|
%
|
|
—
|
|
|
—
|
|
Jack T. Taylor
|
|
2,865
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Grant E. Sims
|
|
2,956,737
|
|
(5)
|
2.7
|
%
|
|
7,087
|
|
|
17.7
|
%
|
Robert V. Deere
|
|
750,987
|
|
|
*
|
|
|
1,052
|
|
|
2.6
|
%
|
Paul A. Davis
|
|
15,152
|
|
|
*
|
|
|
—
|
|
|
—
|
|
Stephen M. Smith
|
|
416,144
|
|
(6)
|
*
|
|
|
—
|
|
|
—
|
|
Richard R. Alexander
|
|
10,000
|
|
(7)
|
*
|
|
|
—
|
|
|
—
|
|
Karen N. Pape
|
|
152,131
|
|
|
*
|
|
|
—
|
|
|
—
|
|
All directors and executive officers as a group (13 in total)
|
|
15,090,242
|
|
|
13.7
|
%
|
|
32,321
|
|
|
80.8
|
%
|
|
|
|
|
|
|
|
|
|
||||
Steven K. Davison
|
|
2,392,839
|
|
(8)
|
2.2
|
%
|
|
7,676
|
|
|
19.2
|
%
|
Tortoise Capital Advisors, L.L.C
|
|
6,050,317
|
|
|
5.5
|
%
|
|
—
|
|
|
|
|
Goldman Sachs Asset Management
|
|
6,613,810
|
|
|
6.0
|
%
|
|
—
|
|
|
—
|
|
OppenheimerFunds, Inc.
|
|
6,078,047
|
|
|
5.5
|
%
|
|
—
|
|
|
—
|
|
Alerian MLP ETF
|
|
7,377,877
|
|
|
6.7
|
%
|
|
—
|
|
|
—
|
|
*
|
Less than 1%
|
(1)
|
The Class B Common Units, which also are included in the Class A Common Unit total, are identical in most respects to the Class A Common Units and have voting and distribution rights equivalent to those of the Class A Common Units. In addition, the Class B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain circumstances, subject to certain exceptions.
|
(2)
|
Mr. Davison pledged 1,049,406 of these Class A Common Units as collateral for a loan from a bank. In addition to his direct ownership interests, Mr. Davison is the sole stockholder of Davison Terminal Service, Inc., which owns
1,010,835
Class A Common Units.
|
(3)
|
Mr. Davison, Jr. pledged 1,164,370 of these Class A Common Units as collateral for a loan from a bank.
1,339,383
of these Class A Common Units are held by trusts for Mr. Davison's children.
187,856
of these Class A Common Units are held by the James E. and Margaret A. B. Davison Special Trust.
|
(4)
|
Mr. Robertson pledged 1,590,039 of these Class A Common Units as collateral for margin accounts. Includes
198,785
Class A Common Units held by The Corbin J. Robertson III 2009 Family Trust and
5,743
Class A Common Units held by Corby & Brooke Robertson 2006 Family Trust. Also included are
20,000
Class A Common Units held by BHJ Investments, LP, whose members include Mr. Robertson, the Corby and Brooke Robertson 2014 Children's Trust, and Brooke Robertson as Mr. Robertson's wife.
|
(5)
|
Mr. Sims pledged 1,450,000 of these Class A Common Units as collateral for loans from a bank. Includes
1,000
Class A Common Units held by Mr. Sims’ father, of which Mr. Sims disclaims beneficial ownership.
|
(6)
|
Mr. Smith pledged 350,000 Class A Common Units as collateral for margin brokerage accounts.
|
(7)
|
Mr. Alexander pledged these 10,000 Class A Common Units as collateral for margin brokerage accounts.
|
(8)
|
Includes
147,941
Class A Common units held by the Steven Davison Family Trust.
|
|
2015
|
|
2014
|
||||
|
(in thousands)
|
||||||
Audit Fees
(1)
|
$
|
3,496
|
|
|
$
|
2,489
|
|
Tax Fees
(2)
|
739
|
|
|
839
|
|
||
All Other Fees
(3)
|
8
|
|
|
8
|
|
||
Total
|
$
|
4,243
|
|
|
$
|
3,336
|
|
(1)
|
Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC registration statements and accounting and financial reporting consultations and research work regarding Generally Accepted Accounting Principles.
|
(2)
|
Includes fees for tax return preparation and tax consultations.
|
(3)
|
Includes fees associated with licenses for accounting research software.
|
|
2.1
|
|
Purchase and Sale Agreement, dated July 16, 2015, by and between Genesis Energy L.P. and Enterprise Products Operating, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K/A dated July 16 2015, File No. 001-12295).
|
|
3.1
|
|
Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 of the Registration Statement on Form S-1, File No. 333-11545).
|
|
3.2
|
|
Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).
|
|
3.3
|
|
Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
|
|
3.4
|
|
Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295).
|
|
3.5
|
|
Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009, File No. 001-12295).
|
|
3.6
|
|
Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295).
|
|
3.7
|
|
Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006 (incorporated by reference to Exhibit 3.7 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
|
|
3.8
|
|
Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
|
|
4.1
|
|
Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
|
|
4.2
|
|
Form of Common Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K filed on March 17, 2008, File No. 001-12295).
|
|
4.3
|
|
Davison Unitholder Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K dated July 31, 2007, File No. 001-12295).
|
|
4.4
|
|
Amendment No. 1 to the Davison Unitholder Rights Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K dated October 19, 2007, File No. 001-12295).
|
|
4.5
|
|
Amendment No. 2 to the Davison Unitholder Rights Agreement dated December 28, 2010 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
|
|
4.6
|
|
Davison Registration Rights Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K dated July 31, 2007, File No. 001-12295).
|
|
4.7
|
|
Amendment No. 1 to the Davison Registration Rights Agreement, dated October 15, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated October 19, 2007, File No. 001-12295).
|
|
4.8
|
|
Amendment No. 2 to the Davison Registration Rights Agreement, dated December 6, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated December 11, 2007, File No. 001-12295).
|
|
4.9
|
|
Amendment No. 3 to the Davison Registration Rights Agreement, dated as of December 28, 2010 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
|
|
4.10
|
|
Registration Rights Agreement, dated as of December 28, 2010, by and among Genesis Energy, L.P. and the former unitholders of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-k dated January 3, 2011, File No. 001-12295).
|
|
4.11
|
|
Indenture for 7.875% Senior Subordinated Notes due 2018, dated November 18, 2010 among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated November 23, 2010, File No. 001-12295).
|
|
4.12
|
|
Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of November 24, 2010, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.13
|
|
Second Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of December 27, 2010, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.14
|
|
Third Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of February 28, 2011, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.15
|
|
Fourth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of June 30, 2011, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.16
|
|
Fifth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of September 13, 2011, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.17
|
|
Sixth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of September 22, 2011, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Company’s Registration Statement on Form S-4 dated September 26, 2011, File No. 333-177012).
|
|
4.18
|
|
Seventh Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of December 5, 2011, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.9 to Form 10-K filed on February 29, 2012, File No. 001-12295).
|
|
4.19
|
|
Eighth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 3, 2012, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.10 to Form 10-K filed on February 29, 2012, File No. 001-12295).
|
|
4.20
|
|
Ninth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 27, 2012, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.11 to Form 10-K filed on February 29, 2012, File No. 001-12295).
|
|
4.21
|
|
Tenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of December 6, 2012, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.12 to Form 10-K filed on February 26, 2013, File No. 001-12295).
|
|
4.22
|
|
Eleventh Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 28, 2013, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.13 to Form 10-K filed on February 26, 2013, File No. 001-12295).
|
|
4.23
|
|
Twelfth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of February 19, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.14 to Form 10-K filed on February 27, 2014, File No. 001-12295).
|
|
4.24
|
|
Thirteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of May 7, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.19 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.25
|
|
Fourteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of October 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.20 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.26
|
|
Fifteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of December 17, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.21 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.27
|
|
Sixteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of January 22, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.22 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.28
|
|
Seventeenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.23 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.29
|
|
Eighteenth Supplemental Indenture for 7.875% Senior Subordinated Notes due 2018, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.24 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.30
|
|
Indenture for 5.75% Senior Subordinated Notes due 2021, dated February 8, 2013 among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated February 11, 2013, File No. 001-12295).
|
|
4.31
|
|
First Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of February 19, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.14 to Form 10-K filed on February 27, 2014, File No. 001-12295).
|
|
4.32
|
|
Second Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of May 7, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.27 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.33
|
|
Third Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of October 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.28 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.34
|
|
Fourth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of December 17, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.29 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.35
|
|
Fifth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of January 22, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.30 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.36
|
|
Sixth Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.31 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.37
|
|
Seventh Supplemental Indenture for 5.75% Senior Subordinated Notes due 2021, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.32 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.38
|
|
Eighth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.8 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
|
|
4.39
|
|
Ninth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.9 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
|
|
4.40
|
|
Tenth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
|
*
|
4.41
|
|
Eleventh Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National association, as trustee.
|
|
4.42
|
|
Indenture for 5.625% Senior Notes due 2024, dated May 15, 2014, among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated May 15, 2014, File No. 001-12295).
|
|
4.43
|
|
Supplemental Indenture for the Issuer's 5.625% Senior Notes due 2024, dated as of May 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 10-K filed on May 15, 2014, File No. 001-12295).
|
|
4.44
|
|
Second Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of October 15, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.35 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.45
|
|
Third Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 17, 2014, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.36 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.46
|
|
Fourth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of January 22, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.37 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.47
|
|
Fifth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.38 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.48
|
|
Sixth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of February 19, 2015, by and among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.39 to Form 10-K filed on February 27, 2015, File No. 001-12295).
|
|
4.49
|
|
Seventh Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
|
|
4.50
|
|
Eighth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
|
|
4.51
|
|
Ninth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
|
*
|
4.52
|
|
Tenth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
|
|
4.53
|
|
Indenture, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated May 21, 2015, File No. 001-12295).
|
|
4.54
|
|
Supplemental Indenture for the Issuers' 6.000% Senior Notes due 2023, dated May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (including the form of the Notes) (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated May 21, 2015, File No. 001-12295).
|
|
4.55
|
|
Second Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of June 26, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
|
|
4.56
|
|
Third Supplemental Indenture for 6.000% Senior Notes due 2023, dated as of July 15, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 001-12295).
|
|
4.57
|
|
Fourth Supplemental Indenture for 6.75% Senior Notes due 2022, dated as of July 23, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee to the Indenture dated as of May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated July 28, 2015, File No. 001-12295).
|
|
4.58
|
|
Fifth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 001-12295).
|
*
|
4.59
|
|
Sixth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.75% Senior Notes due 2022, dated as of December 11, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
|
|
10.1
|
|
Fourth Amended and Restated Credit Agreement, dated as of June 30, 2014, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 3, 2014, File No. 001-12295).
|
|
10.2
|
|
First Amendment to Fourth Amended and Restated Credit Agreement, dated August 25, 2014, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K dated August 29, 2014, File No. 001-12295).
|
*
|
10.3
|
|
Second Amendment to Fourth Amended and Restated Credit Agreement and Joinder Agreement, dated as of July 17, 2015, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto.
|
|
10.4
|
|
Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 17, 2015, among Genesis Energy, L.P. as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K dated September 23, 2015, File No. 001-12295).
|
|
10.5
|
|
Pipeline Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC, as Lessor and Denbury Onshore, LLC, as Lessee for the North East Jackson Dome Pipeline dated May 30, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K dated June 5, 2008, File No. 001-12295).
|
|
10.6
|
|
Transportation Services Agreement between Genesis Free State Pipeline, LLC, as Lessor and Denbury Onshore, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K dated June 5, 2008, File No. 001-12295).
|
|
10.7
|
|
Form of Indemnity Agreement, among Genesis Energy, L.P., Genesis Energy, LLC and each of the Directors of Genesis Energy, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 5, 2010, File No. 001-12295).
|
|
10.8
|
+
|
Genesis Energy, LLC First Amended and Restated Stock Appreciation Rights Plan (incorporated by reference to Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-12295).
|
|
10.9
|
+
|
Form of Stock Appreciation Rights Plan Grant Notice (incorporated by reference to Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-12295).
|
|
10.10
|
+
|
Genesis Energy, Inc. 2007 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
|
|
10.11
|
+
|
Genesis Energy, L.P. 2010 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 001-12295).
|
|
10.12
|
+
|
Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Directors Phantom Unit with DERs Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 001-12295).
|
|
10.13
|
+
|
Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Executive Phantom Unit with DERs Award – Officers (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-12295).
|
|
10.14
|
+
|
Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Employee Phantom Unit with DERs Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, File No. 001-12295).
|
|
10.15
|
+
|
Form of 2007 Phantom Unit Grant Agreement (3-Year Graded) (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
|
|
10.16
|
+
|
Form of 2007 Phantom Unit Grant Agreement (3-Year Cliff) (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated December 21, 2007, File No. 001-12295).
|
|
10.17
|
+
|
Employment Agreement by and between Genesis Energy, LLC and Paul A. Davis, dated March 5, 2012 (incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K dated February 26, 2013, File No. 001-12295).
|
|
10.18
|
+
|
Employment Agreement by and between DG Marine Transportation, LLC and Richard Alexander dated July 18, 2008 ((incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form 10-K dated February 27, 2015, File No. 001-12295).
|
|
11.1
|
|
|
*
|
21.1
|
|
Subsidiaries of the Registrant.
|
*
|
23.1
|
|
Consent of Deloitte & Touche LLP.
|
*
|
31.1
|
|
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
|
*
|
31.2
|
|
Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
|
*
|
32.1
|
|
Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
*
|
32.2
|
|
Certification by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
*
|
101.INS
|
|
XBRL Instance Document.
|
*
|
101.SCH
|
|
XBRL Schema Document.
|
*
|
101.CAL
|
|
XBRL Calculation Linkbase Document.
|
*
|
101.LAB
|
|
XBRL Label Linkbase Document.
|
*
|
101.PRE
|
|
XBRL Presentation Linkbase Document.
|
*
|
101.DEF
|
|
XBRL Definition Linkbase Document.
|
*
|
Filed herewith
|
+
|
A management contract or compensation plan or arrangement.
|
|
|
|
|
|
GENESIS ENERGY, L.P.
|
|
|
|
|
|
(A Delaware Limited Partnership)
|
|
|
|
|
|
|
|
|
|
By:
|
|
GENESIS ENERGY, LLC,
|
|
|
|
|
|
as General Partner
|
|
|
|
|
|
|
Date:
|
February 26, 2016
|
|
By:
|
|
/s/ GRANT E. SIMS
|
|
|
|
|
|
Grant E. Sims
|
|
|
|
|
|
Chief Executive Officer
|
NAME
|
TITLE
|
DATE
|
|
(OF GENESIS ENERGY, LLC)*
|
|
/s/ GRANT E. SIMS
Grant E. Sims
|
Chairman of the Board, Director and Chief Executive Officer
(Principal Executive Officer)
|
February 26, 2016
|
/s/ ROBERT V. DEERE
Robert V. Deere
|
Chief Financial Officer,
(Principal Financial Officer)
|
February 26, 2016
|
/s/ KAREN N. PAPE
Karen N. Pape
|
Senior Vice President and Controller
(Principal Accounting Officer)
|
February 26, 2016
|
/s/ CONRAD P. ALBERT
Conrad P. Albert
|
Director
|
February 26, 2016
|
/s/ JAMES E. DAVISON
James E. Davison
|
Director
|
February 26, 2016
|
/s/ JAMES E. DAVISON, JR.
James E. Davison, Jr.
|
Director
|
February 26, 2016
|
/s/ SHARILYN S. GASAWAY
Sharilyn S. Gasaway
|
Director
|
February 26, 2016
|
/s/ KENNETH M. JASTROW, II
Kenneth M. Jastrow, II
|
Director
|
February 26, 2016
|
/s/ CORBIN J. ROBERTSON, III
Corbin J. Robertson, III
|
Director
|
February 26, 2016
|
/s/ JACK T. TAYLOR
Jack T. Taylor
|
Director
|
February 26, 2016
|
*
|
Genesis Energy, LLC is our general partner.
|
|
Page
|
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||
ASSETS
|
|
|
|
||||
CURRENT ASSETS:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
10,895
|
|
|
$
|
9,462
|
|
Accounts receivable—trade, net
|
219,532
|
|
|
271,529
|
|
||
Inventories
|
43,775
|
|
|
46,829
|
|
||
Other
|
32,114
|
|
|
27,546
|
|
||
Total current assets
|
306,316
|
|
|
355,366
|
|
||
FIXED ASSETS, at cost
|
4,310,226
|
|
|
1,899,058
|
|
||
Less: Accumulated depreciation
|
(378,247
|
)
|
|
(268,057
|
)
|
||
Net fixed assets
|
3,931,979
|
|
|
1,631,001
|
|
||
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
|
139,728
|
|
|
145,959
|
|
||
EQUITY INVESTEES
|
474,392
|
|
|
628,780
|
|
||
INTANGIBLE ASSETS, net of amortization
|
223,446
|
|
|
82,931
|
|
||
GOODWILL
|
325,046
|
|
|
325,046
|
|
||
OTHER ASSETS, net of amortization
|
58,692
|
|
|
41,541
|
|
||
TOTAL ASSETS
|
$
|
5,459,599
|
|
|
$
|
3,210,624
|
|
LIABILITIES AND PARTNERS’ CAPITAL
|
|
|
|
||||
CURRENT LIABILITIES:
|
|
|
|
||||
Accounts payable—trade
|
$
|
140,726
|
|
|
$
|
245,405
|
|
Accrued liabilities
|
161,410
|
|
|
117,740
|
|
||
Total current liabilities
|
302,136
|
|
|
363,145
|
|
||
SENIOR SECURED CREDIT FACILITY
|
1,115,000
|
|
|
550,400
|
|
||
SENIOR UNSECURED NOTES, net of debt issuance costs
|
1,807,054
|
|
|
1,030,889
|
|
||
DEFERRED TAX LIABILITIES
|
22,586
|
|
|
18,754
|
|
||
OTHER LONG-TERM LIABILITIES
|
192,072
|
|
|
18,233
|
|
||
COMMITMENTS AND CONTINGENCIES (
Note 19
)
|
|
|
|
||||
PARTNERS’ CAPITAL:
|
|
|
|
||||
Common unitholders, 109,979,218 and 95,029,218 units issued and outstanding at December 31, 2015 and 2014, respectively
|
2,029,101
|
|
|
1,229,203
|
|
||
Noncontrolling interests
|
(8,350
|
)
|
|
—
|
|
||
Total partners' capital
|
2,020,751
|
|
|
1,229,203
|
|
||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL
|
$
|
5,459,599
|
|
|
$
|
3,210,624
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
REVENUES:
|
|
|
|
|
|
||||||
Offshore pipeline transportation services
|
$
|
140,230
|
|
|
$
|
3,296
|
|
|
$
|
3,923
|
|
Onshore pipeline transportation services
|
77,092
|
|
|
83,157
|
|
|
82,585
|
|
|||
Refinery services
|
177,880
|
|
|
207,401
|
|
|
205,985
|
|
|||
Marine transportation
|
238,757
|
|
|
229,282
|
|
|
152,542
|
|
|||
Supply and logistics
|
1,612,570
|
|
|
3,323,028
|
|
|
3,689,795
|
|
|||
Total revenues
|
2,246,529
|
|
|
3,846,164
|
|
|
4,134,830
|
|
|||
COSTS AND EXPENSES:
|
|
|
|
|
|
||||||
Supply and logistics product costs
|
1,481,619
|
|
|
3,166,336
|
|
|
3,547,141
|
|
|||
Supply and logistics operating costs
|
95,878
|
|
|
110,716
|
|
|
102,187
|
|
|||
Marine transportation operating costs
|
135,200
|
|
|
142,793
|
|
|
104,676
|
|
|||
Refinery services operating costs
|
96,806
|
|
|
121,401
|
|
|
131,289
|
|
|||
Offshore pipeline transportation operating costs
|
39,713
|
|
|
1,271
|
|
|
1,234
|
|
|||
Onshore pipeline transportation operating costs
|
25,311
|
|
|
29,496
|
|
|
25,972
|
|
|||
General and administrative
|
64,995
|
|
|
50,692
|
|
|
46,790
|
|
|||
Depreciation and amortization
|
150,140
|
|
|
90,908
|
|
|
64,784
|
|
|||
Total costs and expenses
|
2,089,662
|
|
|
3,713,613
|
|
|
4,024,073
|
|
|||
OPERATING INCOME
|
156,867
|
|
|
132,551
|
|
|
110,757
|
|
|||
Equity in earnings of equity investees
|
54,450
|
|
|
43,135
|
|
|
22,675
|
|
|||
Interest expense
|
(100,596
|
)
|
|
(66,639
|
)
|
|
(48,583
|
)
|
|||
Gain on basis step up on historical interest
|
332,380
|
|
|
—
|
|
|
—
|
|
|||
Other income/(expense), net
|
(17,529
|
)
|
|
—
|
|
|
—
|
|
|||
Income from continuing operations before income taxes
|
425,572
|
|
|
109,047
|
|
|
84,849
|
|
|||
Income tax expense
|
(3,987
|
)
|
|
(2,845
|
)
|
|
(845
|
)
|
|||
Income from continuing operations
|
421,585
|
|
|
106,202
|
|
|
84,004
|
|
|||
Income from discontinued operations
|
—
|
|
|
—
|
|
|
2,105
|
|
|||
NET INCOME
|
421,585
|
|
|
106,202
|
|
|
86,109
|
|
|||
Net loss attributable to noncontrolling interests
|
943
|
|
|
—
|
|
|
—
|
|
|||
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
|
$
|
422,528
|
|
|
$
|
106,202
|
|
|
$
|
86,109
|
|
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
|
|
|
|
|
|
||||||
Continuing operations
|
$
|
4.09
|
|
|
$
|
1.18
|
|
|
$
|
1.00
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
0.03
|
|
|||
Net income per common unit
|
$
|
4.09
|
|
|
$
|
1.18
|
|
|
$
|
1.03
|
|
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
|
|
|
|
|
|
||||||
Basic and Diluted
|
103,004
|
|
|
90,060
|
|
|
83,957
|
|
|
Number of
Common
Units
|
|
Partners' Capital
|
|
Noncontrolling Interest
|
|
Total
|
|||||||
December 31, 2012
|
81,203
|
|
|
$
|
916,495
|
|
|
$
|
—
|
|
|
$
|
916,495
|
|
Net income
|
—
|
|
|
86,109
|
|
|
—
|
|
|
86,109
|
|
|||
Cash distributions to partners, net
|
—
|
|
|
(168,441
|
)
|
|
—
|
|
|
(168,441
|
)
|
|||
Issuance of units for cash, net
(Note 11)
|
5,750
|
|
|
263,574
|
|
|
—
|
|
|
263,574
|
|
|||
Conversion of waiver units
|
1,738
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
December 31, 2013
|
88,691
|
|
|
1,097,737
|
|
|
—
|
|
|
1,097,737
|
|
|||
Net income
|
—
|
|
|
106,202
|
|
|
—
|
|
|
106,202
|
|
|||
Cash distributions to partners, net
|
—
|
|
|
(200,461
|
)
|
|
—
|
|
|
(200,461
|
)
|
|||
Issuance of units for cash, net
(Note 11)
|
4,600
|
|
|
225,725
|
|
|
—
|
|
|
225,725
|
|
|||
Conversion of waiver units
|
1,738
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
December 31, 2014
|
95,029
|
|
|
1,229,203
|
|
|
—
|
|
|
1,229,203
|
|
|||
Net income (loss)
|
—
|
|
|
422,528
|
|
|
(943
|
)
|
|
421,585
|
|
|||
Noncontrolling interest from acquisition
|
—
|
|
|
—
|
|
|
(6,447
|
)
|
|
(6,447
|
)
|
|||
Cash distributions to partners, net
|
—
|
|
|
(256,389
|
)
|
|
—
|
|
|
(256,389
|
)
|
|||
Cash distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
(960
|
)
|
|
(960
|
)
|
|||
Issuance of common units for cash, net
(Note 11)
|
14,950
|
|
|
633,759
|
|
|
—
|
|
|
633,759
|
|
|||
December 31, 2015
|
109,979
|
|
|
$
|
2,029,101
|
|
|
$
|
(8,350
|
)
|
|
$
|
2,020,751
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
||||||
Net income
|
$
|
421,585
|
|
|
$
|
106,202
|
|
|
$
|
86,109
|
|
Adjustments to reconcile net income to net cash provided by
operating activities -
|
|
|
|
|
|
||||||
Depreciation and amortization
|
150,140
|
|
|
90,908
|
|
|
64,796
|
|
|||
Gain on basis step up on historical interest
|
(332,380
|
)
|
|
—
|
|
|
—
|
|
|||
Amortization and write-off of debt issuance costs and premium
|
10,881
|
|
|
4,785
|
|
|
4,339
|
|
|||
Amortization of unearned income and initial direct costs on direct financing leases
|
(14,979
|
)
|
|
(15,706
|
)
|
|
(16,152
|
)
|
|||
Payments received under direct financing leases
|
20,664
|
|
|
21,235
|
|
|
21,262
|
|
|||
Equity in earnings of investments in equity investees
|
(54,450
|
)
|
|
(43,135
|
)
|
|
(22,675
|
)
|
|||
Cash distributions of earnings of equity investees
|
71,823
|
|
|
57,165
|
|
|
34,132
|
|
|||
Non-cash effect of equity-based compensation plans
|
5,014
|
|
|
4,494
|
|
|
12,473
|
|
|||
Deferred and other tax benefits
|
2,960
|
|
|
1,745
|
|
|
(152
|
)
|
|||
Unrealized (gains) losses on derivative transactions
|
(1,009
|
)
|
|
(17,984
|
)
|
|
1,313
|
|
|||
Other, net
|
3,915
|
|
|
3,391
|
|
|
(873
|
)
|
|||
Net changes in components of operating assets and liabilities, net of acquisitions (See
Note 14
)
|
5,372
|
|
|
77,954
|
|
|
(46,186
|
)
|
|||
Net cash provided by operating activities
|
289,536
|
|
|
291,054
|
|
|
138,386
|
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
||||||
Payments to acquire fixed and intangible assets
|
(495,774
|
)
|
|
(443,482
|
)
|
|
(343,119
|
)
|
|||
Cash distributions received from equity investees—return of investment
|
25,645
|
|
|
18,363
|
|
|
12,432
|
|
|||
Investments in equity investees
|
(3,045
|
)
|
|
(40,926
|
)
|
|
(94,551
|
)
|
|||
Acquisitions
|
(1,520,299
|
)
|
|
(157,000
|
)
|
|
(230,880
|
)
|
|||
Contributions in aid of construction costs
|
3,179
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from asset sales and discontinued operations
|
2,811
|
|
|
272
|
|
|
1,910
|
|
|||
Other, net
|
(1,976
|
)
|
|
(1,214
|
)
|
|
(1,622
|
)
|
|||
Net cash used in investing activities
|
(1,989,459
|
)
|
|
(623,987
|
)
|
|
(655,830
|
)
|
|||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
||||||
Borrowings on senior secured credit facility
|
1,525,050
|
|
|
1,839,900
|
|
|
1,593,300
|
|
|||
Repayments on senior secured credit facility
|
(960,450
|
)
|
|
(1,872,300
|
)
|
|
(1,510,500
|
)
|
|||
Proceeds from issuance of senior unsecured notes, including premium
|
1,139,718
|
|
|
350,000
|
|
|
350,000
|
|
|||
Repayment of senior unsecured notes
|
(350,000
|
)
|
|
—
|
|
|
—
|
|
|||
Debt issuance costs
|
(28,901
|
)
|
|
(11,896
|
)
|
|
(8,157
|
)
|
|||
Issuance of common units for cash, net
|
633,759
|
|
|
225,725
|
|
|
263,574
|
|
|||
Distributions to noncontrolling interests
|
(960
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to common unitholders
|
(256,389
|
)
|
|
(200,461
|
)
|
|
(168,441
|
)
|
|||
Other, net
|
(471
|
)
|
|
2,561
|
|
|
(4,748
|
)
|
|||
Net cash provided by financing activities
|
1,701,356
|
|
|
333,529
|
|
|
515,028
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
1,433
|
|
|
596
|
|
|
(2,416
|
)
|
|||
Cash and cash equivalents at beginning of period
|
9,462
|
|
|
8,866
|
|
|
11,282
|
|
|||
Cash and cash equivalents at end of period
|
$
|
10,895
|
|
|
$
|
9,462
|
|
|
$
|
8,866
|
|
•
|
Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;
|
•
|
Onshore pipeline transportation of crude oil and, to a lesser extent, carbon dioxide (or “CO2”);
|
•
|
Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS”, commonly pronounced "nash");
|
•
|
Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; and
|
•
|
Supply and logistics services, which include terminaling, blending, storing, marketing, and transporting crude oil and petroleum products and, on a smaller scale, CO2.
|
Cash
|
$
|
1,270
|
|
Accounts receivable
|
29,768
|
|
|
Inventories
|
600
|
|
|
Other current assets
|
10,432
|
|
|
Fixed assets
|
1,225,685
|
|
|
Intangible assets
|
79,050
|
|
|
Equity investees
|
352,535
|
|
|
Other assets
|
1,966
|
|
|
Accounts payable
|
(6,110
|
)
|
|
Accrued liabilities
|
(18,662
|
)
|
|
Other long-term liabilities
|
(161,412
|
)
|
|
Noncontrolling interest
|
6,447
|
|
|
Total purchase price
|
$
|
1,521,569
|
|
|
Year Ended
December 31, |
||
|
2015
|
||
Revenues
|
$
|
101,444
|
|
Net income
|
$
|
58,805
|
|
|
Year Ended
December 31, |
||||||||||
Pro forma consolidated financial operating results:
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues
|
$
|
2,421,989
|
|
|
$
|
4,135,964
|
|
|
$
|
4,372,827
|
|
Net Income Attributable to Genesis Energy L.P.
|
$
|
425,363
|
|
|
$
|
132,682
|
|
|
$
|
81,287
|
|
Basic and diluted earnings per unit:
|
|
|
|
|
|
||||||
As reported net income per unit
|
$
|
4.09
|
|
|
$
|
1.18
|
|
|
$
|
1.00
|
|
Pro forma net income per unit
|
$
|
3.91
|
|
|
$
|
1.32
|
|
|
$
|
0.86
|
|
Property and equipment
|
$
|
125,000
|
|
Intangible assets
|
32,000
|
|
|
Total purchase price
|
$
|
157,000
|
|
|
Year Ended
December 31, |
||
|
2014
|
||
Revenues
|
$
|
3,038
|
|
Net income
|
$
|
454
|
|
|
Year Ended
December 31, |
||||||
|
2014
|
|
2013
|
||||
Pro forma earnings data:
|
|
|
|
||||
Revenues from continuing operations
|
$
|
3,863,745
|
|
|
$
|
4,153,443
|
|
Net income
|
$
|
111,132
|
|
|
$
|
90,829
|
|
|
Year Ended
December 31, |
||
|
2013
|
||
Revenues
|
$
|
30,424
|
|
Net income
|
$
|
7,348
|
|
|
Year Ended
December 31, |
||
|
2013
|
||
Pro forma earnings data:
|
|
||
Revenues from continuing operations
|
$
|
4,177,715
|
|
Net Income
|
$
|
98,846
|
|
|
Year Ended
December 31, |
||
|
2013
|
||
Revenues
|
$
|
593,733
|
|
Cost and expenses
|
592,505
|
|
|
Operating income
|
1,228
|
|
|
Interest income
|
2
|
|
|
Income before income taxes
|
1,230
|
|
|
Gain on sale of discontinued operations
|
875
|
|
|
Income from discontinued operations
|
$
|
2,105
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
Accounts receivable - trade
|
$
|
220,978
|
|
|
$
|
274,502
|
|
Allowance for doubtful accounts
|
(1,446
|
)
|
|
(2,973
|
)
|
||
Accounts receivable - trade, net
|
$
|
219,532
|
|
|
$
|
271,529
|
|
|
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at beginning of period
|
$
|
2,973
|
|
|
$
|
1,526
|
|
|
$
|
2,372
|
|
(Credited) charged to costs and expenses
|
1,242
|
|
|
1,447
|
|
|
(86
|
)
|
|||
Amounts written off
|
(2,769
|
)
|
|
—
|
|
|
(760
|
)
|
|||
Balance at end of period
|
$
|
1,446
|
|
|
$
|
2,973
|
|
|
$
|
1,526
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
Crude oil pipelines and natural gas pipelines and related assets
|
$
|
2,501,821
|
|
|
$
|
466,613
|
|
Machinery and equipment
|
414,100
|
|
|
376,672
|
|
||
Transportation equipment
|
19,025
|
|
|
18,479
|
|
||
Marine vessels
|
794,508
|
|
|
731,016
|
|
||
Land, buildings and improvements
|
41,202
|
|
|
38,037
|
|
||
Office equipment, furniture and fixtures
|
7,540
|
|
|
6,696
|
|
||
Construction in progress
|
485,575
|
|
|
222,233
|
|
||
Other
|
46,455
|
|
|
39,312
|
|
||
Fixed assets, at cost
|
4,310,226
|
|
|
1,899,058
|
|
||
Less: Accumulated depreciation
|
(378,247
|
)
|
|
(268,057
|
)
|
||
Net fixed assets
|
$
|
3,931,979
|
|
|
$
|
1,631,001
|
|
December 31, 2013
|
$
|
14,332
|
|
Liabilities incurred
|
—
|
|
|
Accretion expense
|
458
|
|
|
December 31, 2014
|
14,790
|
|
|
AROs arising from our Enterprise acquisition
|
158,230
|
|
|
AROs from the consolidation of historical interests in CHOPS and SEKCO
|
1,988
|
|
|
Accretion expense
|
4,941
|
|
|
Revisions in timing of expected settlement
|
9,986
|
|
|
Settlements
|
(1,273
|
)
|
|
December 31, 2015
|
$
|
188,662
|
|
2016
|
$
|
7,743
|
|
2017
|
$
|
6,722
|
|
2018
|
$
|
5,141
|
|
2019
|
$
|
5,518
|
|
2020
|
$
|
5,924
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
Total minimum lease payments to be received
|
$
|
257,111
|
|
|
$
|
277,732
|
|
Estimated residual values of leased property (unguaranteed)
|
—
|
|
|
292
|
|
||
Unamortized initial direct costs
|
1,272
|
|
|
1,444
|
|
||
Less unearned income
|
(112,378
|
)
|
|
(127,531
|
)
|
||
Net investment in direct financing leases
|
146,005
|
|
|
151,937
|
|
||
Less current portion (included in other current assets)
|
(6,277
|
)
|
|
(5,978
|
)
|
||
Long-term portion of net investment in direct financing leases
|
$
|
139,728
|
|
|
$
|
145,959
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Genesis’ share of operating earnings
|
$
|
17,157
|
|
|
$
|
53,783
|
|
|
$
|
33,152
|
|
Amortization of differences attributable to Genesis' carrying value of equity investments
|
37,293
|
|
|
(10,648
|
)
|
|
(10,477
|
)
|
|||
Net equity in earnings
|
$
|
54,450
|
|
|
$
|
43,135
|
|
|
$
|
22,675
|
|
Distributions received
|
$
|
97,468
|
|
|
$
|
75,528
|
|
|
$
|
46,564
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
BALANCE SHEET DATA:
|
|
|
|
||||
Assets
|
|
|
|
||||
Current assets
|
$
|
38,871
|
|
|
$
|
42,135
|
|
Fixed assets, net
|
450,108
|
|
|
1,015,305
|
|
||
Other assets
|
2,040
|
|
|
4,369
|
|
||
Total assets
|
$
|
491,019
|
|
|
$
|
1,061,809
|
|
Liabilities and equity
|
|
|
|
||||
Current liabilities
|
$
|
25,308
|
|
|
$
|
25,369
|
|
Other liabilities
|
231,032
|
|
|
202,613
|
|
||
Equity
|
234,679
|
|
|
833,827
|
|
||
Total liabilities and equity
|
$
|
491,019
|
|
|
$
|
1,061,809
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
INCOME STATEMENT DATA:
|
|
|
|
|
|
||||||
Revenues
|
$
|
189,941
|
|
|
$
|
246,265
|
|
|
$
|
183,533
|
|
Operating Income
|
$
|
26,101
|
|
|
$
|
146,760
|
|
|
$
|
102,107
|
|
Net Income
|
$
|
7,810
|
|
|
$
|
142,754
|
|
|
$
|
99,357
|
|
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||||||||||
|
Weighted
Amortization
Period in Years
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Carrying
Value
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Carrying
Value
|
||||||||||||
Refinery Services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Customer relationships
|
5
|
|
$
|
94,654
|
|
|
$
|
86,285
|
|
|
$
|
8,369
|
|
|
$
|
94,654
|
|
|
$
|
81,880
|
|
|
$
|
12,774
|
|
Licensing agreements
|
6
|
|
38,678
|
|
|
31,694
|
|
|
6,984
|
|
|
38,678
|
|
|
28,983
|
|
|
9,695
|
|
||||||
Segment total
|
|
|
133,332
|
|
|
117,979
|
|
|
15,353
|
|
|
133,332
|
|
|
110,863
|
|
|
22,469
|
|
||||||
Supply & Logistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Customer relationships
|
5
|
|
35,430
|
|
|
32,044
|
|
|
3,386
|
|
|
35,430
|
|
|
30,228
|
|
|
5,202
|
|
||||||
Intangibles associated with lease
|
15
|
|
13,260
|
|
|
3,986
|
|
|
9,274
|
|
|
13,260
|
|
|
3,512
|
|
|
9,748
|
|
||||||
Segment total
|
|
|
48,690
|
|
|
36,030
|
|
|
12,660
|
|
|
48,690
|
|
|
33,740
|
|
|
14,950
|
|
||||||
Marine contract intangibles
|
5
|
|
27,000
|
|
|
900
|
|
|
26,100
|
|
|
32,000
|
|
|
833
|
|
|
31,167
|
|
||||||
Offshore pipeline contract intangibles
|
19
|
|
158,101
|
|
|
3,467
|
|
|
154,634
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Other
|
5
|
|
22,819
|
|
|
8,120
|
|
|
14,699
|
|
|
22,797
|
|
|
8,452
|
|
|
14,345
|
|
||||||
Total
|
|
|
$
|
389,942
|
|
|
$
|
166,496
|
|
|
$
|
223,446
|
|
|
$
|
236,819
|
|
|
$
|
153,888
|
|
|
$
|
82,931
|
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
||||||||||
Refinery Services:
|
|
|
|
|
|
|
|
|
|
||||||||||
Customer relationships
|
$
|
3,471
|
|
|
$
|
2,737
|
|
|
$
|
2,161
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Licensing agreements
|
2,510
|
|
|
2,324
|
|
|
2,150
|
|
|
—
|
|
|
—
|
|
|||||
Supply and Logistics:
|
|
|
|
|
|
|
|
|
|
||||||||||
Customer relationships
|
1,631
|
|
|
1,407
|
|
|
41
|
|
|
40
|
|
|
38
|
|
|||||
Intangibles associated with lease
|
474
|
|
|
474
|
|
|
474
|
|
|
474
|
|
|
474
|
|
|||||
Marine contract intangibles
|
5,400
|
|
|
5,400
|
|
|
5,400
|
|
|
5,400
|
|
|
4,500
|
|
|||||
Offshore pipeline contract intangibles
|
8,321
|
|
|
8,321
|
|
|
8,321
|
|
|
8,321
|
|
|
8,321
|
|
|||||
Other
|
2,270
|
|
|
2,252
|
|
|
2,252
|
|
|
2,252
|
|
|
2,252
|
|
|||||
Total
|
$
|
24,077
|
|
|
$
|
22,915
|
|
|
$
|
20,799
|
|
|
$
|
16,487
|
|
|
$
|
15,585
|
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
CO
2
volumetric production payments, net of amortization
|
$
|
7,413
|
|
|
$
|
9,395
|
|
Deferred marine charges
(1)
|
29,871
|
|
|
13,042
|
|
||
Other deferred costs and deposits
(2)
|
21,408
|
|
|
19,104
|
|
||
Other assets, net of amortization
|
$
|
58,692
|
|
|
$
|
41,541
|
|
(1)
|
See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (
Note 2
)
|
(2)
|
There has been a change in presentation relating to 2014 due to the adoption of guidance issued by the FASB that requires the presentation of debt issuance costs in financial statements as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. Previously debt issuance costs were reported as part of deferred charges. Genesis adopted this guidance in Q4 2015 and retrospectively adjusted the presentation of related costs as needed. For more information please refer to the discussion of recently issued accounting pronouncements in the Summary of Accounting Policies (
Note 2
).
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||||||||||
|
Principal
|
|
Unamortized Discount and Debt Issuance Costs
(1)
|
|
Net Value
|
|
Principal
|
|
Unamortized Discount and Debt Issuance Costs
(1)
|
|
Net Value
|
||||||||||||
Senior secured credit facility
|
$
|
1,115,000
|
|
|
$
|
—
|
|
|
$
|
1,115,000
|
|
|
$
|
550,400
|
|
|
$
|
—
|
|
|
550,400
|
|
|
7.875% senior unsecured notes
(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
350,000
|
|
|
4,502
|
|
|
345,498
|
|
||||||
6.000% senior unsecured notes
|
400,000
|
|
|
7,825
|
|
|
392,175
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
5.750% senior unsecured notes
|
350,000
|
|
|
5,183
|
|
|
344,817
|
|
|
350,000
|
|
|
6,202
|
|
|
343,798
|
|
||||||
5.625% senior unsecured notes
|
350,000
|
|
|
7,510
|
|
|
342,490
|
|
|
350,000
|
|
|
8,407
|
|
|
341,593
|
|
||||||
6.750% senior unsecured notes
|
750,000
|
|
|
22,428
|
|
|
727,572
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total long-term debt
|
$
|
2,965,000
|
|
|
$
|
42,946
|
|
|
$
|
2,922,054
|
|
|
$
|
1,600,400
|
|
|
$
|
19,111
|
|
|
$
|
1,581,289
|
|
(1)
|
In April 2015, the FASB issued guidance that requires the presentation of debt issuance costs in financial statements as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. Under current U.S. GAAP standards, debt issuance costs are reported as deferred charges (i.e., as an asset). This guidance is effective for annual periods, and interim periods within those fiscal years, beginning after December 15, 2015 and is to be applied retrospectively upon adoption. Early adoption is permitted, including adoption in an interim period for financial statements that have not been previously issued. Genesis adopted this guidance in the fourth quarter of 2015.
|
(2)
|
Net of unamortized premium of $639 in 2014.
|
•
|
The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus
0.5%
of
1%
and (iii) the LIBOR rate for a one-month maturity plus
1%
and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from
1.50%
to
2.50%
on Eurodollar borrowings and from
0.50%
to
1.50%
on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At
December 31, 2015
, the applicable margins on our borrowings were
1.50%
for alternate base rate borrowings and
2.50%
for Eurodollar rate borrowings.
|
•
|
Letter of credit fees range from
1.50%
to
2.50%
based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At
December 31, 2015
, our letter of credit rate was
2.50%
.
|
•
|
We pay a commitment fee on the unused portion of the
$1.5 billion
maximum facility amount. The commitment fee on the unused committed amount will range from
0.250%
to
0.375%
per annum depending on our leverage ratio (
0.375%
at
December 31, 2015
).
|
•
|
incur indebtedness if certain financial ratios are not maintained;
|
•
|
grant liens;
|
•
|
engage in sale-leaseback transactions; and
|
•
|
sell substantially all of our assets or enter into a merger or consolidation.
|
Distribution For
|
Date Paid
|
|
Per Unit Amount
|
|
Total Amount
|
||||
2013
|
|
|
|
|
|
||||
4th Quarter
|
February 14, 2014
|
|
$
|
0.5350
|
|
|
$
|
47,453
|
|
2014
|
|
|
|
|
|
||||
1st Quarter
|
May 15, 2014
|
|
$
|
0.5500
|
|
|
$
|
48,783
|
|
2nd Quarter
|
August 14, 2014
|
|
$
|
0.5650
|
|
|
$
|
50,114
|
|
3rd Quarter
|
November 14, 2014
|
|
$
|
0.5800
|
|
|
$
|
54,112
|
|
4th Quarter
|
February 13, 2015
|
|
$
|
0.5950
|
|
|
$
|
56,542
|
|
2015
|
|
|
|
|
|
||||
1st Quarter
|
May 15, 2015
|
|
$
|
0.6100
|
|
|
$
|
60,774
|
|
2nd Quarter
|
August 14, 2015
|
|
$
|
0.6250
|
|
|
$
|
68,737
|
|
3rd Quarter
|
November 13, 2015
|
|
$
|
0.6400
|
|
|
$
|
70,387
|
|
4th Quarter
|
February 12, 2016
|
|
$
|
0.6550
|
|
|
$
|
72,036
|
|
•
|
Offshore Pipeline Transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico;
|
•
|
Onshore Pipeline Transportation –transportation of crude oil, and to a lesser extent, CO
2
;
|
•
|
Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and selling the related by-product, NaHS;
|
•
|
Marine Transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America and;
|
•
|
Supply and Logistics – terminaling, blending, storing, marketing, and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and, on a smaller scale, CO
2
.
|
|
Offshore Pipeline Transportation
|
|
Onshore Pipeline
Transportation
|
|
Refinery
Services
|
|
Marine Transportation
|
|
Supply &
Logistics
(a)
|
|
Total
|
||||||||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Segment Margin
(b)
|
$
|
197,723
|
|
|
$
|
58,919
|
|
|
$
|
80,246
|
|
|
$
|
103,222
|
|
|
$
|
36,475
|
|
|
$
|
476,585
|
|
Capital expenditures
(c)
|
$
|
1,527,320
|
|
|
$
|
235,069
|
|
|
$
|
1,595
|
|
|
$
|
69,009
|
|
|
$
|
174,618
|
|
|
$
|
2,007,611
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
External customers
|
$
|
140,230
|
|
|
$
|
64,524
|
|
|
$
|
187,257
|
|
|
$
|
230,192
|
|
|
$
|
1,624,326
|
|
|
$
|
2,246,529
|
|
Intersegment
(d)
|
—
|
|
|
12,568
|
|
|
(9,377
|
)
|
|
8,565
|
|
|
(11,756
|
)
|
|
$
|
—
|
|
|||||
Total revenues of reportable segments
|
$
|
140,230
|
|
|
$
|
77,092
|
|
|
$
|
177,880
|
|
|
$
|
238,757
|
|
|
$
|
1,612,570
|
|
|
$
|
2,246,529
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Segment Margin
(b)
|
$
|
71,598
|
|
|
$
|
61,231
|
|
|
$
|
84,851
|
|
|
$
|
86,239
|
|
|
$
|
43,345
|
|
|
$
|
347,264
|
|
Capital expenditures
(c)
|
$
|
37,639
|
|
|
$
|
46,611
|
|
|
$
|
2,385
|
|
|
$
|
232,783
|
|
|
$
|
325,130
|
|
|
$
|
644,548
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
External customers
|
$
|
3,296
|
|
|
$
|
66,760
|
|
|
$
|
218,297
|
|
|
$
|
214,039
|
|
|
$
|
3,343,772
|
|
|
$
|
3,846,164
|
|
Intersegment
(d)
|
—
|
|
|
16,397
|
|
|
(10,896
|
)
|
|
15,243
|
|
|
(20,744
|
)
|
|
$
|
—
|
|
|||||
Total revenues of reportable segments
|
$
|
3,296
|
|
|
$
|
83,157
|
|
|
$
|
207,401
|
|
|
$
|
229,282
|
|
|
$
|
3,323,028
|
|
|
$
|
3,846,164
|
|
Year Ended December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Segment Margin
(b)
|
$
|
44,530
|
|
|
$
|
64,349
|
|
|
$
|
75,361
|
|
|
$
|
47,726
|
|
|
$
|
48,394
|
|
|
$
|
280,360
|
|
Capital expenditures
(c)
|
$
|
94,286
|
|
|
$
|
130,787
|
|
|
$
|
3,258
|
|
|
$
|
260,736
|
|
|
$
|
215,138
|
|
|
$
|
704,205
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
External customers
|
$
|
3,923
|
|
|
$
|
65,452
|
|
|
$
|
216,860
|
|
|
$
|
131,049
|
|
|
$
|
3,717,546
|
|
|
$
|
4,134,830
|
|
Intersegment
(d)
|
—
|
|
|
17,133
|
|
|
(10,875
|
)
|
|
21,493
|
|
|
(27,751
|
)
|
|
$
|
—
|
|
|||||
Total revenues of reportable segments
|
$
|
3,923
|
|
|
$
|
82,585
|
|
|
$
|
205,985
|
|
|
$
|
152,542
|
|
|
$
|
3,689,795
|
|
|
$
|
4,134,830
|
|
|
December 31, 2015
|
|
December 31, 2014
|
|
December 31, 2013
|
||||||
Offshore pipeline transportation
|
2,623,478
|
|
|
645,668
|
|
|
637,323
|
|
|||
Onshore pipeline transportation
|
614,484
|
|
|
460,012
|
|
|
437,912
|
|
|||
Refinery services
|
394,626
|
|
|
403,703
|
|
|
417,121
|
|
|||
Marine transportation
|
777,952
|
|
|
745,128
|
|
|
529,914
|
|
|||
Supply and logistics
|
1,000,851
|
|
|
907,189
|
|
|
782,547
|
|
|||
Other assets
|
48,208
|
|
|
48,924
|
|
|
43,711
|
|
|||
Total consolidated assets
|
$
|
5,459,599
|
|
|
$
|
3,210,624
|
|
|
$
|
2,848,528
|
|
(a)
|
Discontinued operations are included in Segment Margin but excluded from revenues for all periods presented.
|
(b)
|
A reconciliation of Segment Margin to net income attributable to Genesis Energy, L.P. for each year is presented below.
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Segment Margin
|
$
|
476,585
|
|
|
$
|
347,264
|
|
|
$
|
280,360
|
|
Corporate general and administrative expenses
|
(61,370
|
)
|
|
(47,065
|
)
|
|
(43,353
|
)
|
|||
Depreciation and amortization
|
(150,140
|
)
|
|
(90,908
|
)
|
|
(64,784
|
)
|
|||
Interest expense
|
(100,596
|
)
|
|
(66,639
|
)
|
|
(48,583
|
)
|
|||
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income
(1)
|
(43,018
|
)
|
|
(31,093
|
)
|
|
(23,889
|
)
|
|||
Non-cash items not included in Segment Margin
|
4,227
|
|
|
3,017
|
|
|
(7,551
|
)
|
|||
Cash payments from direct financing leases in excess of earnings
|
(5,685
|
)
|
|
(5,529
|
)
|
|
(5,110
|
)
|
|||
Gain on step up of historical basis
|
332,380
|
|
|
—
|
|
|
—
|
|
|||
Loss on debt extinguishment
|
(19,225
|
)
|
|
—
|
|
|
—
|
|
|||
Other, net
|
(6,643
|
)
|
|
—
|
|
|
2,105
|
|
|||
Income tax expense
|
(3,987
|
)
|
|
(2,845
|
)
|
|
(845
|
)
|
|||
Discontinued operations
|
—
|
|
|
—
|
|
|
(2,241
|
)
|
|||
Net income attributable to Genesis Energy, L.P.
|
$
|
422,528
|
|
|
$
|
106,202
|
|
|
$
|
86,109
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues:
|
|
|
|
|
|
||||||
Sales of CO
2
to Sandhill Group, LLC
(1)
|
$
|
3,259
|
|
|
$
|
3,060
|
|
|
$
|
3,076
|
|
Revenues from services to Poseidon Oil Pipeline Company, LLC
(2)
|
3,941
|
|
|
—
|
|
|
—
|
|
|||
Revenues from services to Deepwater Gateway, LLC
(3)
|
56
|
|
|
—
|
|
|
—
|
|
|||
Petroleum products sales to Davison family businesses
(4)
|
—
|
|
|
—
|
|
|
1,293
|
|
|||
Expenses:
|
|
|
|
|
|
||||||
Amounts paid to our CEO in connection with the use of his aircraft
|
$
|
690
|
|
|
$
|
630
|
|
|
$
|
600
|
|
Charges for products purchased from Poseidon Oil Pipeline Company, LLC
(2)
|
464
|
|
|
—
|
|
|
—
|
|
(1)
|
We own a
50%
interest in Sandhill Group, LLC.
|
(2)
|
We own a
64%
interest in Poseidon Oil Pipeline Company, LLC.
|
(3)
|
We own a
50%
interest in Deepwater Gateway, LLC.
|
(4)
|
Amounts included in discontinued operations for all periods presented.
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
(Increase) decrease in:
|
|
|
|
|
|
||||||
Accounts receivable
|
$
|
99,384
|
|
|
$
|
95,014
|
|
|
$
|
(96,300
|
)
|
Inventories
|
3,811
|
|
|
38,501
|
|
|
1,720
|
|
|||
Deferred charges
|
(11,916
|
)
|
|
(8,935
|
)
|
|
—
|
|
|||
Other current assets
|
6,417
|
|
|
62,305
|
|
|
(39,170
|
)
|
|||
Increase (decrease) in:
|
|
|
|
|
|
||||||
Accounts payable
|
(101,581
|
)
|
|
(73,307
|
)
|
|
41,718
|
|
|||
Accrued liabilities
|
9,257
|
|
|
(35,624
|
)
|
|
45,846
|
|
|||
Net changes in components of operating assets and liabilities
|
$
|
5,372
|
|
|
$
|
77,954
|
|
|
$
|
(46,186
|
)
|
|
Service-Based Awards
|
|
Performance-Based Awards
|
||||||||||||||||||
|
Number of
Phantom
Units
|
|
Average
Grant
Date Fair
Value
|
|
Total
Value
(in thousands)
|
|
Number of
Phantom
Units
|
|
Average
Grant
Date Fair
Value
|
|
Total
Value
(in thousands)
|
||||||||||
Unvested at December 31, 2014
|
112,823
|
|
|
$
|
44.53
|
|
|
$
|
5,024
|
|
|
313,845
|
|
|
$
|
42.82
|
|
|
$
|
13,439
|
|
Granted
|
58,192
|
|
|
$
|
44.40
|
|
|
2,584
|
|
|
154,633
|
|
|
$
|
45.15
|
|
|
6,982
|
|
||
Forfeited
|
(2,856
|
)
|
|
$
|
47.26
|
|
|
(135
|
)
|
|
(4,201
|
)
|
|
$
|
46.00
|
|
|
(193
|
)
|
||
Settled
|
(35,483
|
)
|
|
$
|
30.79
|
|
|
(1,093
|
)
|
|
(120,069
|
)
|
|
$
|
31.50
|
|
|
(3,782
|
)
|
||
Unvested at December 31, 2015
|
132,676
|
|
|
$
|
48.09
|
|
|
$
|
6,380
|
|
|
344,208
|
|
|
$
|
47.78
|
|
|
$
|
16,446
|
|
|
Assumptions Used for Fair Value of Rights
|
||||||||||
|
December 31, 2015
|
|
December 31, 2014
|
|
December 31, 2013
|
||||||
Expected life of rights (in years)
|
Less than 1
|
|
Less than 1
|
|
Less than 1
|
||||||
Risk-free interest rate
|
—%
|
-
|
0.07%
|
|
—%
|
-
|
0.07%
|
|
—%
|
-
|
0.07%
|
Expected unit price volatility
|
39.3%
|
|
39.3%
|
|
39.3%
|
||||||
Expected future distribution yield
|
5.00%
|
|
5.00%
|
|
5.00%
|
|
Stock Appreciation Rights
|
|
Weighted
Average
Strike Price
|
|
Weighted
Average
Contractual
Remaining
Term (Yrs)
|
|
Aggregate
Intrinsic
Value
|
|||||
Outstanding at December 31, 2014
|
160,855
|
|
|
$
|
18.08
|
|
|
|
|
|
||
Exercised during 2015
|
(30,607
|
)
|
|
$
|
41.69
|
|
|
|
|
|
||
Forfeited or expired during 2015
|
(571
|
)
|
|
$
|
20.92
|
|
|
|
|
|
||
Outstanding at December 31, 2015
|
129,677
|
|
|
$
|
18.55
|
|
|
2.14
|
|
$
|
2,350
|
|
Exercisable at December 31, 2015
|
129,677
|
|
|
$
|
18.55
|
|
|
2.14
|
|
$
|
2,350
|
|
|
|
Expense Related to Equity-Based Compensation Plans
|
||||||||||
Consolidated Statement of Operations
|
|
2015
|
|
2014
|
|
2013
|
||||||
Supply and logistics operating costs
|
|
$
|
1,201
|
|
|
$
|
485
|
|
|
$
|
4,524
|
|
Marine transportation operating costs
|
|
851
|
|
|
626
|
|
|
586
|
|
|||
Refinery services operating costs
|
|
227
|
|
|
(62
|
)
|
|
1,978
|
|
|||
Offshore pipeline operating costs
|
|
94
|
|
|
—
|
|
|
—
|
|
|||
Onshore pipeline operating costs
|
|
(16
|
)
|
|
(52
|
)
|
|
510
|
|
|||
General and administrative expenses
|
|
4,565
|
|
|
5,824
|
|
|
11,073
|
|
|||
Total
|
|
$
|
6,922
|
|
|
$
|
6,821
|
|
|
$
|
18,671
|
|
|
Sell (Short)
Contracts
|
|
Buy (Long)
Contracts
|
||||
Designated as hedges under accounting rules:
|
|
|
|
||||
Crude oil futures:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
47
|
|
|
—
|
|
||
Weighted average contract price per bbl
|
$
|
37.68
|
|
|
—
|
|
|
Not qualifying or not designated as hedges under accounting rules:
|
|
|
|
||||
Crude oil futures:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
444
|
|
|
6
|
|
||
Weighted average contract price per bbl
|
$
|
37.94
|
|
|
$
|
36.48
|
|
Crude oil swaps:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
290
|
|
|
—
|
|
||
Weighted average contract price per bbl
|
$
|
1.28
|
|
|
—
|
|
|
Diesel futures:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
86
|
|
|
6
|
|
||
Weighted average contract price per gal
|
$
|
1.30
|
|
|
$
|
1.15
|
|
#6 Fuel oil futures:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
165
|
|
|
—
|
|
||
Weighted average contract price per bbl
|
$
|
26.97
|
|
|
$
|
—
|
|
Crude oil options:
|
|
|
|
||||
Contract volumes (1,000 bbls)
|
95
|
|
|
35
|
|
||
Weighted average premium received
|
$
|
1.50
|
|
|
$
|
0.64
|
|
Derivative Instrument
|
|
Hedged Risk
|
|
Impact of Unrealized Gains and Losses
|
||
|
|
Consolidated
Balance Sheets
|
|
Consolidated
Statements of Operations
|
||
Designated as hedges under accounting guidance:
|
||||||
Crude oil futures contracts (fair value hedge)
|
|
Volatility in crude oil prices - effect on market value of inventory
|
|
Derivative is recorded in Other current assets (offset against margin deposits and offsetting change in fair value of inventory is recorded in Inventories
|
|
Excess, if any, over effective portion of hedge is recorded in Supply and logistics costs - product costs
Effective portion is offset in cost of sales against change in value of inventory being hedged
|
Not qualifying or not designated as hedges under accounting guidance:
|
||||||
Commodity hedges consisting of crude oil, heating oil and natural gas futures and forward contracts and call options
|
|
Volatility in crude oil and petroleum products prices - effect on market value of inventory or purchase commitments
|
|
Derivative is recorded in Other current assets (offset against margin deposits) or Accrued liabilities
|
|
Entire amount of change in fair value of derivative is recorded in Supply and logistics costs - product costs
|
|
|
|
Fair Value
|
||||||||
|
Consolidated
Balance Sheets Location
|
|
December 31, 2015
|
|
|
|
December 31, 2014
|
||||
Asset Derivatives:
|
|
|
|
|
|
|
|
||||
Commodity derivatives—futures and call options (undesignated hedges):
|
|
|
|
|
|
|
|
||||
Gross amount of recognized assets
|
Current Assets - Other
|
|
$
|
1,703
|
|
|
|
|
$
|
16,383
|
|
Gross amount offset in the Consolidated Balance Sheets
|
Current Assets - Other
|
|
(388
|
)
|
|
|
|
(2,310
|
)
|
||
Net amount of assets presented in the Consolidated Balance Sheets
|
|
|
$
|
1,315
|
|
|
|
|
$
|
14,073
|
|
Liability Derivatives:
|
|
|
|
|
|
|
|
||||
Commodity derivatives—futures and call options (undesignated hedges):
|
|
|
|
|
|
|
|
||||
Gross amount of recognized liabilities
|
Current Assets - Other
(1)
|
|
$
|
(388
|
)
|
|
|
|
$
|
(2,310
|
)
|
Gross amount offset in the Consolidated Balance Sheets
|
Current Assets - Other
(1)
|
|
388
|
|
|
|
|
2,310
|
|
||
Net amount of liabilities presented in the Consolidated Balance Sheets
|
|
|
$
|
—
|
|
|
|
|
$
|
—
|
|
Commodity derivatives—futures and call options (designated hedges):
|
|
|
|
|
|
|
|
||||
Gross amount of recognized liabilities
|
Current Assets - Other
(1)
|
|
$
|
(23
|
)
|
|
|
|
$
|
—
|
|
Gross amount offset in the Consolidated Balance Sheets
|
Current Assets - Other
(1)
|
|
23
|
|
|
|
|
—
|
|
||
Net amount of liabilities presented in the Consolidated Balance Sheets
|
|
|
$
|
—
|
|
|
|
|
$
|
—
|
|
(1)
|
These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other.
|
|
Amount of Gain (Loss) Recognized in Income
|
||||||||||
|
Supply & Logistics Product Costs
|
||||||||||
|
Year Ended
December 31, |
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Commodity derivatives—futures and call options:
|
|
|
|
|
|
||||||
Contracts designated as hedges under accounting guidance
|
$
|
(1,101
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Contracts not considered hedges under accounting guidance
|
16,026
|
|
|
35,468
|
|
|
(3,268
|
)
|
|||
Total derivatives
|
$
|
14,925
|
|
|
$
|
35,468
|
|
|
$
|
(3,268
|
)
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||||||||||
Recurring Fair Value Measures
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
||||||||||||
Commodity derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
$
|
1,703
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
16,383
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Liabilities
|
$
|
(411
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,310
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Office
Space
|
|
Transportation
Equipment
|
|
Terminals and
Tanks
|
|
Total
|
||||||||
2016
|
$
|
2,203
|
|
|
$
|
13,569
|
|
|
$
|
8,106
|
|
|
$
|
23,878
|
|
2017
|
2,099
|
|
|
11,595
|
|
|
3,571
|
|
|
17,265
|
|
||||
2018
|
2,117
|
|
|
10,109
|
|
|
3,610
|
|
|
15,836
|
|
||||
2019
|
2,065
|
|
|
9,535
|
|
|
3,665
|
|
|
15,265
|
|
||||
2020
|
2,056
|
|
|
7,514
|
|
|
3,610
|
|
|
13,180
|
|
||||
2021 and thereafter
|
4,325
|
|
|
18,037
|
|
|
59,776
|
|
|
82,138
|
|
||||
Total minimum lease obligations
|
$
|
14,865
|
|
|
$
|
70,359
|
|
|
$
|
82,338
|
|
|
$
|
167,562
|
|
Year Ended December 31, 2015
|
$
|
36,833
|
|
Year Ended December 31, 2014
|
$
|
37,941
|
|
Year Ended December 31, 2013
|
$
|
27,674
|
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
345
|
|
State
|
1,200
|
|
|
1,100
|
|
|
650
|
|
|||
Total current income tax expense (benefit)
|
$
|
1,200
|
|
|
$
|
1,100
|
|
|
$
|
995
|
|
Deferred:
|
|
|
|
|
|
||||||
Federal
|
$
|
2,478
|
|
|
$
|
1,508
|
|
|
$
|
(248
|
)
|
State
|
309
|
|
|
237
|
|
|
98
|
|
|||
Total deferred income tax expense (benefit)
|
$
|
2,787
|
|
|
$
|
1,745
|
|
|
$
|
(150
|
)
|
Total income tax expense from continuing operations
(1)
|
$
|
3,987
|
|
|
$
|
2,845
|
|
|
$
|
845
|
|
(1)
|
Our discontinued operations had no income tax benefit or expense in any period presented.
|
|
December 31,
|
||||||
|
2015
|
|
2014
|
||||
Deferred tax assets:
|
|
|
|
||||
Current:
|
|
|
|
||||
Other current assets
|
$
|
—
|
|
|
$
|
262
|
|
Other
|
—
|
|
|
8
|
|
||
Total current deferred tax asset
|
—
|
|
|
270
|
|
||
Net operating loss carryforwards
|
9,542
|
|
|
9,048
|
|
||
Total long-term deferred tax asset
|
9,542
|
|
|
9,048
|
|
||
Valuation allowances
|
(787
|
)
|
|
(737
|
)
|
||
Total deferred tax assets
|
$
|
8,755
|
|
|
$
|
8,581
|
|
Deferred tax liabilities:
|
|
|
|
||||
Current:
|
|
|
|
||||
Other
|
$
|
—
|
|
|
$
|
(871
|
)
|
Long-term:
|
|
|
|
||||
Fixed assets
|
(4,384
|
)
|
|
(4,335
|
)
|
||
Intangible assets
|
(17,473
|
)
|
|
(14,419
|
)
|
||
Other
|
(729
|
)
|
|
—
|
|
||
Total long-term liability
|
(22,586
|
)
|
|
(18,754
|
)
|
||
Total deferred tax liabilities
|
$
|
(22,586
|
)
|
|
$
|
(19,625
|
)
|
Total net deferred tax liability
|
$
|
(13,831
|
)
|
|
$
|
(11,044
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Income from continuing operations before income taxes
|
$
|
425,572
|
|
|
$
|
109,047
|
|
|
$
|
84,849
|
|
Partnership income not subject to tax
|
(418,500
|
)
|
|
(104,751
|
)
|
|
(85,567
|
)
|
|||
Income (loss) subject to income taxes
|
$
|
7,072
|
|
|
$
|
4,296
|
|
|
$
|
(718
|
)
|
Tax expense (benefit) at federal statutory rate
|
$
|
2,475
|
|
|
$
|
1,504
|
|
|
$
|
(251
|
)
|
State income taxes, net of federal tax
|
928
|
|
|
992
|
|
|
660
|
|
|||
Effects of unrecognized tax positions, federal and state
|
—
|
|
|
—
|
|
|
—
|
|
|||
Return to provision, federal and state
|
(193
|
)
|
|
(232
|
)
|
|
88
|
|
|||
Other
|
777
|
|
|
581
|
|
|
348
|
|
|||
Income tax expense (benefit)
|
$
|
3,987
|
|
|
$
|
2,845
|
|
|
$
|
845
|
|
Effective tax rate on income from continuing operations before income taxes
|
1
|
%
|
|
3
|
%
|
|
1
|
%
|
|
2015 Quarters
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
Revenues from continuing operations
|
$
|
526,857
|
|
|
$
|
656,327
|
|
|
$
|
572,334
|
|
|
$
|
491,011
|
|
Operating income
|
$
|
24,819
|
|
|
$
|
29,380
|
|
|
$
|
44,798
|
|
|
$
|
57,870
|
|
Income from continuing operations
|
$
|
20,215
|
|
|
$
|
11,665
|
|
|
$
|
363,409
|
|
|
$
|
26,296
|
|
Net loss (income) attributable to noncontrolling interest
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(195
|
)
|
|
$
|
1,138
|
|
Net income attributable to Genesis Energy, L.P.
|
$
|
20,215
|
|
|
$
|
11,665
|
|
|
$
|
363,214
|
|
|
$
|
27,434
|
|
Basic and diluted net income per common unit:
|
|
|
|
|
|
|
|
||||||||
Continuing operations
|
$
|
0.21
|
|
|
$
|
0.12
|
|
|
$
|
3.38
|
|
|
$
|
0.24
|
|
Net income per common unit
|
$
|
0.21
|
|
|
$
|
0.12
|
|
|
$
|
3.38
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
||||||||
Cash distributions per common unit
(1)
|
$
|
0.5950
|
|
|
$
|
0.6100
|
|
|
$
|
0.6250
|
|
|
$
|
0.6400
|
|
|
2014 Quarters
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
Revenues from continuing operations
|
$
|
1,019,719
|
|
|
$
|
1,015,049
|
|
|
$
|
964,114
|
|
|
$
|
847,282
|
|
Operating income
|
$
|
35,402
|
|
|
$
|
31,257
|
|
|
$
|
35,268
|
|
|
$
|
30,624
|
|
Income from continuing operations
|
$
|
29,775
|
|
|
$
|
21,148
|
|
|
$
|
29,113
|
|
|
$
|
26,166
|
|
Net income
|
$
|
29,775
|
|
|
$
|
21,148
|
|
|
$
|
29,113
|
|
|
$
|
26,166
|
|
Basic and diluted net income per common unit:
|
|
|
|
|
|
|
|
||||||||
Continuing operations
|
$
|
0.34
|
|
|
$
|
0.24
|
|
|
$
|
0.33
|
|
|
$
|
0.28
|
|
Net income per common unit
|
$
|
0.34
|
|
|
$
|
0.24
|
|
|
$
|
0.33
|
|
|
$
|
0.28
|
|
|
|
|
|
|
|
|
|
||||||||
Cash distributions per common unit
(1)
|
$
|
0.5350
|
|
|
$
|
0.5500
|
|
|
$
|
0.5650
|
|
|
$
|
0.5800
|
|
(1)
|
Represents cash distributions declared and paid in the applicable period.
|
Condensed Consolidating Balance Sheet
|
|||||||||||||||||||||||
December 31, 2015
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and cash equivalents
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
8,288
|
|
|
$
|
2,601
|
|
|
$
|
—
|
|
|
$
|
10,895
|
|
Other current assets
|
50
|
|
|
—
|
|
|
285,313
|
|
|
10,422
|
|
|
(364
|
)
|
|
295,421
|
|
||||||
Total current assets
|
56
|
|
|
—
|
|
|
293,601
|
|
|
13,023
|
|
|
(364
|
)
|
|
306,316
|
|
||||||
Fixed Assets, at cost
|
—
|
|
|
—
|
|
|
4,232,641
|
|
|
77,585
|
|
|
—
|
|
|
4,310,226
|
|
||||||
Less: Accumulated depreciation
|
—
|
|
|
—
|
|
|
(356,530
|
)
|
|
(21,717
|
)
|
|
—
|
|
|
(378,247
|
)
|
||||||
Net fixed assets
|
—
|
|
|
—
|
|
|
3,876,111
|
|
|
55,868
|
|
|
—
|
|
|
3,931,979
|
|
||||||
Goodwill
|
—
|
|
|
—
|
|
|
325,046
|
|
|
—
|
|
|
—
|
|
|
325,046
|
|
||||||
Other assets, net
|
13,140
|
|
|
—
|
|
|
394,294
|
|
|
140,409
|
|
|
(125,977
|
)
|
|
421,866
|
|
||||||
Advances to affiliates
|
2,619,493
|
|
|
—
|
|
|
—
|
|
|
47,034
|
|
|
(2,666,527
|
)
|
|
—
|
|
||||||
Equity investees and other investments
|
—
|
|
|
—
|
|
|
474,392
|
|
|
—
|
|
|
—
|
|
|
474,392
|
|
||||||
Investments in subsidiaries
|
2,353,804
|
|
|
—
|
|
|
90,741
|
|
|
—
|
|
|
(2,444,545
|
)
|
|
—
|
|
||||||
Total assets
|
$
|
4,986,493
|
|
|
$
|
—
|
|
|
$
|
5,454,185
|
|
|
$
|
256,334
|
|
|
$
|
(5,237,413
|
)
|
|
$
|
5,459,599
|
|
LIABILITIES AND PARTNERS’ CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current liabilities
|
$
|
35,338
|
|
|
$
|
—
|
|
|
$
|
267,294
|
|
|
$
|
—
|
|
|
$
|
(496
|
)
|
|
$
|
302,136
|
|
Senior secured credit facilities
|
1,115,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,115,000
|
|
||||||
Senior unsecured notes
|
1,807,054
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,807,054
|
|
||||||
Deferred tax liabilities
|
—
|
|
|
—
|
|
|
22,586
|
|
|
—
|
|
|
—
|
|
|
22,586
|
|
||||||
Advances from affiliates
|
—
|
|
|
—
|
|
|
2,666,527
|
|
|
—
|
|
|
(2,666,527
|
)
|
|
—
|
|
||||||
Other liabilities
|
—
|
|
|
—
|
|
|
150,877
|
|
|
167,006
|
|
|
(125,811
|
)
|
|
192,072
|
|
||||||
Total liabilities
|
2,957,392
|
|
|
—
|
|
|
3,107,284
|
|
|
167,006
|
|
|
(2,792,834
|
)
|
|
3,438,848
|
|
||||||
Partners’ capital, common units
|
2,029,101
|
|
|
—
|
|
|
2,346,901
|
|
|
97,678
|
|
|
(2,444,579
|
)
|
|
2,029,101
|
|
||||||
Noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,350
|
)
|
|
—
|
|
|
(8,350
|
)
|
||||||
Total liabilities and partners’ capital
|
$
|
4,986,493
|
|
|
$
|
—
|
|
|
$
|
5,454,185
|
|
|
$
|
256,334
|
|
|
$
|
(5,237,413
|
)
|
|
$
|
5,459,599
|
|
Condensed Consolidating Balance Sheet
|
|||||||||||||||||||||||
December 31, 2014
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and cash equivalents
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
8,310
|
|
|
$
|
1,143
|
|
|
$
|
—
|
|
|
$
|
9,462
|
|
Other current assets
|
53
|
|
|
—
|
|
|
333,385
|
|
|
12,474
|
|
|
(8
|
)
|
|
345,904
|
|
||||||
Total current assets
|
62
|
|
|
—
|
|
|
341,695
|
|
|
13,617
|
|
|
(8
|
)
|
|
355,366
|
|
||||||
Fixed Assets, at cost
|
—
|
|
|
—
|
|
|
1,823,556
|
|
|
75,502
|
|
|
—
|
|
|
1,899,058
|
|
||||||
Less: Accumulated depreciation
|
—
|
|
|
—
|
|
|
(251,171
|
)
|
|
(16,886
|
)
|
|
—
|
|
|
(268,057
|
)
|
||||||
Net fixed assets
|
—
|
|
|
—
|
|
|
1,572,385
|
|
|
58,616
|
|
|
—
|
|
|
1,631,001
|
|
||||||
Goodwill
|
—
|
|
|
—
|
|
|
325,046
|
|
|
—
|
|
|
—
|
|
|
325,046
|
|
||||||
Other assets, net
|
8,671
|
|
|
—
|
|
|
269,252
|
|
|
146,700
|
|
|
(154,192
|
)
|
|
270,431
|
|
||||||
Advances to affiliates
|
1,378,520
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,378,520
|
)
|
|
—
|
|
||||||
Equity investees and other investments
|
—
|
|
|
—
|
|
|
628,780
|
|
|
—
|
|
|
—
|
|
|
628,780
|
|
||||||
Investments in subsidiaries
|
1,434,255
|
|
|
—
|
|
|
97,195
|
|
|
—
|
|
|
(1,531,450
|
)
|
|
—
|
|
||||||
Total assets
|
$
|
2,821,508
|
|
|
$
|
—
|
|
|
$
|
3,234,353
|
|
|
$
|
218,933
|
|
|
$
|
(3,064,170
|
)
|
|
$
|
3,210,624
|
|
LIABILITIES AND PARTNERS’ CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current liabilities
|
$
|
11,016
|
|
|
$
|
—
|
|
|
$
|
395,159
|
|
|
$
|
499
|
|
|
$
|
(43,529
|
)
|
|
$
|
363,145
|
|
Senior secured credit facilities
|
550,400
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
550,400
|
|
||||||
Senior unsecured notes
|
1,030,889
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,030,889
|
|
||||||
Deferred tax liabilities
|
—
|
|
|
—
|
|
|
18,754
|
|
|
—
|
|
|
—
|
|
|
18,754
|
|
||||||
Advances from affiliates
|
—
|
|
|
—
|
|
|
1,366,697
|
|
|
11,823
|
|
|
(1,378,520
|
)
|
|
—
|
|
||||||
Other liabilities
|
—
|
|
|
—
|
|
|
18,233
|
|
|
110,663
|
|
|
(110,663
|
)
|
|
18,233
|
|
||||||
Total liabilities
|
1,592,305
|
|
|
—
|
|
|
1,798,843
|
|
|
122,985
|
|
|
(1,532,712
|
)
|
|
1,981,421
|
|
||||||
Partners' capital
|
1,229,203
|
|
|
—
|
|
|
1,435,510
|
|
|
95,948
|
|
|
(1,531,458
|
)
|
|
1,229,203
|
|
||||||
Total liabilities and partners’ capital
|
$
|
2,821,508
|
|
|
$
|
—
|
|
|
$
|
3,234,353
|
|
|
$
|
218,933
|
|
|
$
|
(3,064,170
|
)
|
|
$
|
3,210,624
|
|
Condensed Consolidating Statement of Operations
|
|||||||||||||||||||||||
Year Ended December 31, 2015
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Offshore pipeline transportation services
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
137,681
|
|
|
$
|
2,549
|
|
|
$
|
—
|
|
|
$
|
140,230
|
|
Onshore pipeline transportation services
|
—
|
|
|
—
|
|
|
53,347
|
|
|
23,745
|
|
|
—
|
|
|
77,092
|
|
||||||
Refinery services
|
—
|
|
|
—
|
|
|
175,132
|
|
|
11,942
|
|
|
(9,194
|
)
|
|
177,880
|
|
||||||
Marine transportation
|
—
|
|
|
—
|
|
|
238,757
|
|
|
—
|
|
|
—
|
|
|
238,757
|
|
||||||
Supply and logistics
|
—
|
|
|
—
|
|
|
1,612,570
|
|
|
—
|
|
|
—
|
|
|
1,612,570
|
|
||||||
Total revenues
|
—
|
|
|
—
|
|
|
2,217,487
|
|
|
38,236
|
|
|
(9,194
|
)
|
|
2,246,529
|
|
||||||
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Supply and logistics costs
|
—
|
|
|
—
|
|
|
1,577,497
|
|
|
—
|
|
|
—
|
|
|
1,577,497
|
|
||||||
Marine transportation costs
|
—
|
|
|
—
|
|
|
135,200
|
|
|
—
|
|
|
—
|
|
|
135,200
|
|
||||||
Refinery services operating costs
|
—
|
|
|
—
|
|
|
94,241
|
|
|
11,759
|
|
|
(9,194
|
)
|
|
96,806
|
|
||||||
Offshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
38,459
|
|
|
1,254
|
|
|
—
|
|
|
39,713
|
|
||||||
Onshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
24,475
|
|
|
836
|
|
|
—
|
|
|
25,311
|
|
||||||
General and administrative
|
—
|
|
|
—
|
|
|
64,995
|
|
|
—
|
|
|
—
|
|
|
64,995
|
|
||||||
Depreciation and amortization
|
—
|
|
|
—
|
|
|
141,785
|
|
|
8,355
|
|
|
—
|
|
|
150,140
|
|
||||||
Total costs and expenses
|
—
|
|
|
—
|
|
|
2,076,652
|
|
|
22,204
|
|
|
(9,194
|
)
|
|
2,089,662
|
|
||||||
OPERATING INCOME
|
—
|
|
|
—
|
|
|
140,835
|
|
|
16,032
|
|
|
—
|
|
|
156,867
|
|
||||||
Equity in earnings of equity investees
|
—
|
|
|
—
|
|
|
54,450
|
|
|
—
|
|
|
—
|
|
|
54,450
|
|
||||||
Equity in earnings of subsidiaries
|
542,226
|
|
|
—
|
|
|
2,053
|
|
|
—
|
|
|
(544,279
|
)
|
|
—
|
|
||||||
Interest (expense) income, net
|
(100,494
|
)
|
|
—
|
|
|
15,042
|
|
|
(15,144
|
)
|
|
—
|
|
|
(100,596
|
)
|
||||||
Gain on basis step up on historical interest
|
—
|
|
|
—
|
|
|
332,380
|
|
|
—
|
|
|
—
|
|
|
332,380
|
|
||||||
Other income/(expense), net
|
(19,204
|
)
|
|
—
|
|
|
1,675
|
|
|
—
|
|
|
—
|
|
|
(17,529
|
)
|
||||||
Income before income taxes
|
422,528
|
|
|
—
|
|
|
546,435
|
|
|
888
|
|
|
(544,279
|
)
|
|
425,572
|
|
||||||
Income tax benefit (expense)
|
—
|
|
|
—
|
|
|
(4,036
|
)
|
|
49
|
|
|
—
|
|
|
(3,987
|
)
|
||||||
NET INCOME
|
422,528
|
|
|
—
|
|
|
542,399
|
|
|
937
|
|
|
(544,279
|
)
|
|
421,585
|
|
||||||
Net loss attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
943
|
|
|
—
|
|
|
943
|
|
||||||
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
|
$
|
422,528
|
|
|
$
|
—
|
|
|
$
|
542,399
|
|
|
$
|
1,880
|
|
|
$
|
(544,279
|
)
|
|
$
|
422,528
|
|
Condensed Consolidating Statement of Operations
|
|||||||||||||||||||||||
Year Ended December 31, 2014
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Offshore pipeline transportation services
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,296
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,296
|
|
Onshore pipeline transportation services
|
—
|
|
|
—
|
|
|
58,391
|
|
|
24,766
|
|
|
—
|
|
|
83,157
|
|
||||||
Refinery services
|
—
|
|
|
—
|
|
|
202,250
|
|
|
18,289
|
|
|
(13,138
|
)
|
|
207,401
|
|
||||||
Marine transportation
|
—
|
|
|
—
|
|
|
229,282
|
|
|
—
|
|
|
—
|
|
|
229,282
|
|
||||||
Supply and logistics
|
—
|
|
|
—
|
|
|
3,323,028
|
|
|
—
|
|
|
—
|
|
|
3,323,028
|
|
||||||
Total revenues
|
—
|
|
|
—
|
|
|
3,816,247
|
|
|
43,055
|
|
|
(13,138
|
)
|
|
3,846,164
|
|
||||||
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Supply and logistics costs
|
—
|
|
|
—
|
|
|
3,277,052
|
|
|
—
|
|
|
—
|
|
|
3,277,052
|
|
||||||
Marine transportation costs
|
—
|
|
|
—
|
|
|
142,793
|
|
|
—
|
|
|
—
|
|
|
142,793
|
|
||||||
Refinery services operating costs
|
—
|
|
|
—
|
|
|
117,788
|
|
|
17,393
|
|
|
(13,780
|
)
|
|
121,401
|
|
||||||
Offshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
1,271
|
|
|
—
|
|
|
—
|
|
|
1,271
|
|
||||||
Onshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
28,639
|
|
|
857
|
|
|
—
|
|
|
29,496
|
|
||||||
General and administrative
|
—
|
|
|
—
|
|
|
50,692
|
|
|
—
|
|
|
—
|
|
|
50,692
|
|
||||||
Depreciation and amortization
|
—
|
|
|
—
|
|
|
88,368
|
|
|
2,540
|
|
|
—
|
|
|
90,908
|
|
||||||
Total costs and expenses
|
—
|
|
|
—
|
|
|
3,706,603
|
|
|
20,790
|
|
|
(13,780
|
)
|
|
3,713,613
|
|
||||||
OPERATING INCOME
|
—
|
|
|
—
|
|
|
109,644
|
|
|
22,265
|
|
|
642
|
|
|
132,551
|
|
||||||
Equity in earnings of equity investees
|
—
|
|
|
—
|
|
|
43,135
|
|
|
—
|
|
|
—
|
|
|
43,135
|
|
||||||
Equity in earnings of subsidiaries
|
172,828
|
|
|
—
|
|
|
6,952
|
|
|
—
|
|
|
(179,780
|
)
|
|
—
|
|
||||||
Interest (expense) income, net
|
(66,626
|
)
|
|
—
|
|
|
15,662
|
|
|
(15,675
|
)
|
|
—
|
|
|
(66,639
|
)
|
||||||
Income before income taxes
|
106,202
|
|
|
—
|
|
|
175,393
|
|
|
6,590
|
|
|
(179,138
|
)
|
|
109,047
|
|
||||||
Income tax benefit (expense)
|
—
|
|
|
—
|
|
|
(3,030
|
)
|
|
185
|
|
|
—
|
|
|
(2,845
|
)
|
||||||
NET INCOME
|
$
|
106,202
|
|
|
$
|
—
|
|
|
$
|
172,363
|
|
|
$
|
6,775
|
|
|
$
|
(179,138
|
)
|
|
$
|
106,202
|
|
Condensed Consolidating Statement of Operations
|
|||||||||||||||||||||||
Year Ended December 31, 2013
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Offshore pipeline transportation services
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,923
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,923
|
|
Onshore pipeline transportation services
|
—
|
|
|
—
|
|
|
56,784
|
|
|
25,801
|
|
|
—
|
|
|
82,585
|
|
||||||
Refinery services
|
—
|
|
|
—
|
|
|
203,021
|
|
|
17,835
|
|
|
(14,871
|
)
|
|
205,985
|
|
||||||
Marine transportation
|
—
|
|
|
—
|
|
|
152,542
|
|
|
—
|
|
|
—
|
|
|
152,542
|
|
||||||
Supply and logistics
|
—
|
|
|
—
|
|
|
3,689,795
|
|
|
—
|
|
|
—
|
|
|
3,689,795
|
|
||||||
Total revenues
|
—
|
|
|
—
|
|
|
4,106,065
|
|
|
43,636
|
|
|
(14,871
|
)
|
|
4,134,830
|
|
||||||
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Supply and logistics costs
|
—
|
|
|
—
|
|
|
3,649,328
|
|
|
—
|
|
|
—
|
|
|
3,649,328
|
|
||||||
Marine transportation costs
|
—
|
|
|
—
|
|
|
104,676
|
|
|
—
|
|
|
—
|
|
|
104,676
|
|
||||||
Refinery services operating costs
|
—
|
|
|
—
|
|
|
128,814
|
|
|
16,873
|
|
|
(14,398
|
)
|
|
131,289
|
|
||||||
Offshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
1,234
|
|
|
—
|
|
|
—
|
|
|
1,234
|
|
||||||
Onshore pipeline transportation operating costs
|
—
|
|
|
—
|
|
|
24,853
|
|
|
1,119
|
|
|
—
|
|
|
25,972
|
|
||||||
General and administrative
|
—
|
|
|
—
|
|
|
46,790
|
|
|
—
|
|
|
—
|
|
|
46,790
|
|
||||||
Depreciation and amortization
|
—
|
|
|
—
|
|
|
62,194
|
|
|
2,590
|
|
|
—
|
|
|
64,784
|
|
||||||
Total costs and expenses
|
—
|
|
|
—
|
|
|
4,017,889
|
|
|
20,582
|
|
|
(14,398
|
)
|
|
4,024,073
|
|
||||||
OPERATING INCOME
|
—
|
|
|
—
|
|
|
88,176
|
|
|
23,054
|
|
|
(473
|
)
|
|
110,757
|
|
||||||
Equity in earnings of equity investees
|
—
|
|
|
—
|
|
|
22,675
|
|
|
—
|
|
|
—
|
|
|
22,675
|
|
||||||
Equity in earnings of subsidiaries
|
134,616
|
|
|
—
|
|
|
6,913
|
|
|
—
|
|
|
(141,529
|
)
|
|
—
|
|
||||||
Interest (expense) income, net
|
(48,507
|
)
|
|
—
|
|
|
16,080
|
|
|
(16,156
|
)
|
|
—
|
|
|
(48,583
|
)
|
||||||
Income before income taxes
|
86,109
|
|
|
—
|
|
|
133,844
|
|
|
6,898
|
|
|
(142,002
|
)
|
|
84,849
|
|
||||||
Income tax expense
|
—
|
|
|
—
|
|
|
(676
|
)
|
|
(169
|
)
|
|
—
|
|
|
(845
|
)
|
||||||
Income from continuing operations
|
86,109
|
|
|
—
|
|
|
133,168
|
|
|
6,729
|
|
|
(142,002
|
)
|
|
84,004
|
|
||||||
Loss from discontinued operations
|
—
|
|
|
—
|
|
|
2,105
|
|
|
—
|
|
|
—
|
|
|
2,105
|
|
||||||
NET INCOME
|
$
|
86,109
|
|
|
$
|
—
|
|
|
$
|
135,273
|
|
|
$
|
6,729
|
|
|
$
|
(142,002
|
)
|
|
$
|
86,109
|
|
Condensed Consolidating Statement of Cash Flows
|
|||||||||||||||||||||||
Year Ended December 31, 2015
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
Net cash (used in) provided by operating activities
|
$
|
(14,082
|
)
|
|
$
|
—
|
|
|
$
|
308,144
|
|
|
$
|
45,125
|
|
|
$
|
(49,651
|
)
|
|
$
|
289,536
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Payments to acquire fixed and intangible assets
|
—
|
|
|
—
|
|
|
(495,774
|
)
|
|
—
|
|
|
—
|
|
|
(495,774
|
)
|
||||||
Cash distributions received from equity investees - return of investment
|
186,026
|
|
|
—
|
|
|
25,645
|
|
|
—
|
|
|
(186,026
|
)
|
|
25,645
|
|
||||||
Investments in equity investees
|
(633,761
|
)
|
|
—
|
|
|
(3,045
|
)
|
|
—
|
|
|
633,761
|
|
|
(3,045
|
)
|
||||||
Acquisitions
|
—
|
|
|
—
|
|
|
(1,520,299
|
)
|
|
—
|
|
|
—
|
|
|
(1,520,299
|
)
|
||||||
Intercompany transfers
|
(1,240,973
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,240,973
|
|
|
—
|
|
||||||
Repayments on loan to non-guarantor subsidiary
|
—
|
|
|
—
|
|
|
5,524
|
|
|
—
|
|
|
(5,524
|
)
|
|
—
|
|
||||||
Contributions in aid of construction costs
|
—
|
|
|
—
|
|
|
3,179
|
|
|
—
|
|
|
—
|
|
|
3,179
|
|
||||||
Proceeds from asset sales
|
—
|
|
|
—
|
|
|
2,811
|
|
|
—
|
|
|
—
|
|
|
2,811
|
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
(1,976
|
)
|
|
—
|
|
|
—
|
|
|
(1,976
|
)
|
||||||
Net cash used in investing activities
|
(1,688,708
|
)
|
|
—
|
|
|
(1,983,935
|
)
|
|
—
|
|
|
1,683,184
|
|
|
(1,989,459
|
)
|
||||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Borrowings on senior secured credit facility
|
1,525,050
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,525,050
|
|
||||||
Repayments on senior secured credit facility
|
(960,450
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(960,450
|
)
|
||||||
Proceeds from issuance of senior unsecured notes, including premium
|
1,139,718
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,139,718
|
|
||||||
Repayment of senior unsecured notes
|
(350,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(350,000
|
)
|
||||||
Debt issuance costs
|
(28,901
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28,901
|
)
|
||||||
Intercompany transfers
|
—
|
|
|
—
|
|
|
1,299,830
|
|
|
(58,857
|
)
|
|
(1,240,973
|
)
|
|
—
|
|
||||||
Issuance of common units for cash, net
|
633,759
|
|
|
—
|
|
|
633,759
|
|
|
—
|
|
|
(633,759
|
)
|
|
633,759
|
|
||||||
Distributions to partners/owners
|
(256,389
|
)
|
|
—
|
|
|
(256,389
|
)
|
|
—
|
|
|
256,389
|
|
|
(256,389
|
)
|
||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
(960
|
)
|
|
—
|
|
|
—
|
|
|
(960
|
)
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
(471
|
)
|
|
15,190
|
|
|
(15,190
|
)
|
|
(471
|
)
|
||||||
Net cash provided by financing activities
|
1,702,787
|
|
|
—
|
|
|
1,675,769
|
|
|
(43,667
|
)
|
|
(1,633,533
|
)
|
|
1,701,356
|
|
||||||
Net increase (decrease) in cash and cash equivalents
|
(3
|
)
|
|
—
|
|
|
(22
|
)
|
|
1,458
|
|
|
—
|
|
|
1,433
|
|
||||||
Cash and cash equivalents at beginning of period
|
9
|
|
|
—
|
|
|
8,310
|
|
|
1,143
|
|
|
—
|
|
|
9,462
|
|
||||||
Cash and cash equivalents at end of period
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
8,288
|
|
|
$
|
2,601
|
|
|
$
|
—
|
|
|
$
|
10,895
|
|
Condensed Consolidating Statement of Cash Flows
|
|||||||||||||||||||||||
Year Ended December 31, 2014
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
Net cash (used in) provided by operating activities
|
$
|
96,868
|
|
|
$
|
—
|
|
|
$
|
317,520
|
|
|
$
|
34,331
|
|
|
$
|
(157,665
|
)
|
|
$
|
291,054
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Payments to acquire fixed and intangible assets
|
—
|
|
|
—
|
|
|
(443,482
|
)
|
|
—
|
|
|
—
|
|
|
(443,482
|
)
|
||||||
Cash distributions received from equity investees - return of investment
|
42,755
|
|
|
—
|
|
|
18,363
|
|
|
—
|
|
|
(42,755
|
)
|
|
18,363
|
|
||||||
Investments in equity investees
|
(225,725
|
)
|
|
—
|
|
|
(40,926
|
)
|
|
—
|
|
|
225,725
|
|
|
(40,926
|
)
|
||||||
Acquisitions
|
—
|
|
|
—
|
|
|
(157,000
|
)
|
|
—
|
|
|
—
|
|
|
(157,000
|
)
|
||||||
Intercompany transfers
|
(244,876
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
244,876
|
|
|
—
|
|
||||||
Repayments on loan to non-guarantor subsidiary
|
—
|
|
|
—
|
|
|
4,993
|
|
|
—
|
|
|
(4,993
|
)
|
|
—
|
|
||||||
Proceeds from assets sales
|
—
|
|
|
—
|
|
|
272
|
|
|
—
|
|
|
—
|
|
|
272
|
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
(1,214
|
)
|
|
—
|
|
|
—
|
|
|
(1,214
|
)
|
||||||
Net cash used in investing activities
|
(427,846
|
)
|
|
—
|
|
|
(618,994
|
)
|
|
—
|
|
|
422,853
|
|
|
(623,987
|
)
|
||||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Borrowings on senior secured credit facility
|
1,839,900
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,839,900
|
|
||||||
Repayments on senior secured credit facility
|
(1,872,300
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,872,300
|
)
|
||||||
Proceeds from issuance of senior unsecured notes, including premium
|
350,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
350,000
|
|
||||||
Debt issuance costs
|
(11,896
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,896
|
)
|
||||||
Intercompany transfers
|
—
|
|
|
—
|
|
|
273,911
|
|
|
(29,035
|
)
|
|
(244,876
|
)
|
|
—
|
|
||||||
Issuance of ownership interests to partners for cash
|
225,725
|
|
|
—
|
|
|
225,725
|
|
|
—
|
|
|
(225,725
|
)
|
|
225,725
|
|
||||||
Distributions to partners/owners
|
(200,462
|
)
|
|
—
|
|
|
(200,462
|
)
|
|
—
|
|
|
200,463
|
|
|
(200,461
|
)
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
2,560
|
|
|
(4,949
|
)
|
|
4,950
|
|
|
2,561
|
|
||||||
Net cash provided by (used in) financing activities
|
330,967
|
|
|
—
|
|
|
301,734
|
|
|
(33,984
|
)
|
|
(265,188
|
)
|
|
333,529
|
|
||||||
Net increase (decrease) in cash and cash equivalents
|
(11
|
)
|
|
—
|
|
|
260
|
|
|
347
|
|
|
—
|
|
|
596
|
|
||||||
Cash and cash equivalents at beginning of period
|
20
|
|
|
—
|
|
|
8,050
|
|
|
796
|
|
|
—
|
|
|
8,866
|
|
||||||
Cash and cash equivalents at end of period
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
8,310
|
|
|
$
|
1,143
|
|
|
$
|
—
|
|
|
$
|
9,462
|
|
Condensed Consolidating Statement of Cash Flows
|
|||||||||||||||||||||||
Year Ended December 31, 2013
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
|
|
Genesis
Energy Finance
Corporation
(Co-Issuer)
|
|
Guarantor
Subsidiaries
|
|
Non-Guarantor
Subsidiaries
|
|
Eliminations
|
|
Genesis
Energy, L.P.
Consolidated
|
||||||||||||
Net cash (used in) provided by operating activities
|
$
|
107,951
|
|
|
$
|
—
|
|
|
$
|
139,027
|
|
|
$
|
35,847
|
|
|
$
|
(144,439
|
)
|
|
$
|
138,386
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Payments to acquire fixed and intangible assets
|
—
|
|
|
—
|
|
|
(343,119
|
)
|
|
—
|
|
|
—
|
|
|
(343,119
|
)
|
||||||
Cash distributions received from equity investees - return of investment
|
23,963
|
|
|
—
|
|
|
12,432
|
|
|
—
|
|
|
(23,963
|
)
|
|
12,432
|
|
||||||
Investments in equity investees
|
(263,574
|
)
|
|
—
|
|
|
(94,551
|
)
|
|
—
|
|
|
263,574
|
|
|
(94,551
|
)
|
||||||
Acquisitions
|
—
|
|
|
—
|
|
|
(230,880
|
)
|
|
—
|
|
|
—
|
|
|
(230,880
|
)
|
||||||
Intercompany transfers
|
(388,106
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
388,106
|
|
|
—
|
|
||||||
Repayments on loan to non-guarantor subsidiary
|
—
|
|
|
—
|
|
|
4,512
|
|
|
—
|
|
|
(4,512
|
)
|
|
—
|
|
||||||
Proceeds from asset sales
|
—
|
|
|
—
|
|
|
1,910
|
|
|
—
|
|
|
—
|
|
|
1,910
|
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
(1,622
|
)
|
|
—
|
|
|
—
|
|
|
(1,622
|
)
|
||||||
Net cash used in investing activities
|
(627,717
|
)
|
|
—
|
|
|
(651,318
|
)
|
|
—
|
|
|
623,205
|
|
|
(655,830
|
)
|
||||||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Borrowings on senior secured credit facility
|
1,593,300
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,593,300
|
|
||||||
Repayments on senior secured credit facility
|
(1,510,500
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,510,500
|
)
|
||||||
Proceeds from issuance of senior unsecured notes
|
350,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
350,000
|
|
||||||
Debt issuance costs
|
(8,157
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,157
|
)
|
||||||
Intercompany transfers
|
—
|
|
|
—
|
|
|
418,852
|
|
|
(30,746
|
)
|
|
(388,106
|
)
|
|
—
|
|
||||||
Issuance of ownership interests to partners for cash
|
263,574
|
|
|
—
|
|
|
263,574
|
|
|
—
|
|
|
(263,574
|
)
|
|
263,574
|
|
||||||
Distributions to partners/owners
|
(168,441
|
)
|
|
—
|
|
|
(168,441
|
)
|
|
—
|
|
|
168,441
|
|
|
(168,441
|
)
|
||||||
Other, net
|
—
|
|
|
—
|
|
|
(4,748
|
)
|
|
(4,473
|
)
|
|
4,473
|
|
|
(4,748
|
)
|
||||||
Net cash provided by (used in) financing activities
|
519,776
|
|
|
—
|
|
|
509,237
|
|
|
(35,219
|
)
|
|
(478,766
|
)
|
|
515,028
|
|
||||||
Net increase (decrease) in cash and cash equivalents
|
10
|
|
|
—
|
|
|
(3,054
|
)
|
|
628
|
|
|
—
|
|
|
(2,416
|
)
|
||||||
Cash and cash equivalents at beginning of period
|
10
|
|
|
—
|
|
|
11,104
|
|
|
168
|
|
|
—
|
|
|
11,282
|
|
||||||
Cash and cash equivalents at end of period
|
$
|
20
|
|
|
$
|
—
|
|
|
$
|
8,050
|
|
|
$
|
796
|
|
|
$
|
—
|
|
|
$
|
8,866
|
|
Balance Sheet Restatements
|
|
As Previously Reported
|
|
Adjustment
|
|
As Revised
|
|||
December 31, 2014
|
|
|
|
|
|
|
|||
Parent Column
|
|
|
|
|
|
|
|||
Other current assets
|
|
1,378,573
|
|
|
(1,378,520
|
)
|
|
53
|
|
Total current assets
|
|
1,378,582
|
|
|
(1,378,520
|
)
|
|
62
|
|
Advances to affiliates
|
|
—
|
|
|
1,378,520
|
|
|
1,378,520
|
|
Guarantor Column
|
|
|
|
|
|
|
|||
Current liabilities
|
|
1,761,856
|
|
|
(1,366,697
|
)
|
|
395,159
|
|
Advances from affiliates
|
|
—
|
|
|
1,366,697
|
|
|
1,366,697
|
|
Non Guarantor Column
|
|
|
|
|
|
|
|||
Other current assets
|
|
46,215
|
|
|
(33,741
|
)
|
|
12,474
|
|
Total current assets
|
|
47,358
|
|
|
(33,741
|
)
|
|
13,617
|
|
Total assets
|
|
252,674
|
|
|
(33,741
|
)
|
|
218,933
|
|
Current liabilities
|
|
2,705
|
|
|
(2,206
|
)
|
|
499
|
|
Advances from affiliates
|
|
—
|
|
|
11,823
|
|
|
11,823
|
|
Other liabilities
|
|
154,021
|
|
|
(43,358
|
)
|
|
110,663
|
|
Total liabilities
|
|
156,726
|
|
|
(33,741
|
)
|
|
122,985
|
|
Total liabilities and partners' capital
|
|
252,674
|
|
|
(33,741
|
)
|
|
218,933
|
|
Eliminations Column
|
|
|
|
|
|
|
|||
Other current assets
|
|
(1,412,269
|
)
|
|
1,412,261
|
|
|
(8
|
)
|
Total current assets
|
|
(1,412,269
|
)
|
|
1,412,261
|
|
|
(8
|
)
|
Advances to affiliates
|
|
—
|
|
|
(1,378,520
|
)
|
|
(1,378,520
|
)
|
Total assets
|
|
(3,097,911
|
)
|
|
33,741
|
|
|
(3,064,170
|
)
|
Current liabilities
|
|
(1,412,432
|
)
|
|
1,368,903
|
|
|
(43,529
|
)
|
Advances from affiliates
|
|
—
|
|
|
(1,378,520
|
)
|
|
(1,378,520
|
)
|
Other liabilities
|
|
(154,021
|
)
|
|
43,358
|
|
|
(110,663
|
)
|
Total liabilities
|
|
(1,566,453
|
)
|
|
33,741
|
|
|
(1,532,712
|
)
|
Total liabilities and partners' capital
|
|
(3,097,911
|
)
|
|
33,741
|
|
|
(3,064,170
|
)
|
Cash Flow Restatements
|
|
As Previously Reported
|
|
Adjustment
|
|
As Revised
|
|||
December 31, 2014
|
|
|
|
|
|
|
|||
Parent Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
(148,008
|
)
|
|
244,876
|
|
|
96,868
|
|
Intercompany transfers (investing)
|
|
—
|
|
|
(244,876
|
)
|
|
(244,876
|
)
|
Net cash used in investing activities
|
|
(182,970
|
)
|
|
(244,876
|
)
|
|
(427,846
|
)
|
Guarantor Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
591,431
|
|
|
(273,911
|
)
|
|
317,520
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
273,911
|
|
|
273,911
|
|
Net cash provided by (used in) financing activities
|
|
27,824
|
|
|
273,910
|
|
|
301,734
|
|
Non Guarantor Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
5,296
|
|
|
29,035
|
|
|
34,331
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
(29,035
|
)
|
|
(29,035
|
)
|
Net cash provided by (used in) financing activities
|
|
(4,950
|
)
|
|
(29,034
|
)
|
|
(33,984
|
)
|
Eliminations Column
|
|
|
|
|
|
|
|||
Intercompany transfers (investing)
|
|
—
|
|
|
244,876
|
|
|
244,876
|
|
Net cash used in investing activities
|
|
177,977
|
|
|
244,876
|
|
|
422,853
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
(244,876
|
)
|
|
(244,876
|
)
|
Net cash provided by (used in) financing activities
|
|
(20,312
|
)
|
|
(244,876
|
)
|
|
(265,188
|
)
|
Cash Flow Restatements
|
|
As Previously Reported
|
|
Adjustment
|
|
As Revised
|
|||
December 31, 2013
|
|
|
|
|
|
|
|||
Parent Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
(280,155
|
)
|
|
388,106
|
|
|
107,951
|
|
Intercompany transfers (investing)
|
|
—
|
|
|
(388,106
|
)
|
|
(388,106
|
)
|
Net cash used in investing activities
|
|
(239,611
|
)
|
|
(388,106
|
)
|
|
(627,717
|
)
|
Guarantor Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
557,879
|
|
|
(418,852
|
)
|
|
139,027
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
418,852
|
|
|
418,852
|
|
Net cash provided by (used in) financing activities
|
|
90,385
|
|
|
418,852
|
|
|
509,237
|
|
Non Guarantor Column
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
|
5,101
|
|
|
30,746
|
|
|
35,847
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
(30,746
|
)
|
|
(30,746
|
)
|
Net cash provided by (used in) financing activities
|
|
(4,473
|
)
|
|
(30,746
|
)
|
|
(35,219
|
)
|
Eliminations Column
|
|
|
|
|
|
|
|||
Intercompany transfers (investing)
|
|
—
|
|
|
388,106
|
|
|
388,106
|
|
Net cash used in investing activities
|
|
235,099
|
|
|
388,106
|
|
|
623,205
|
|
Intercompany transfers (financing)
|
|
—
|
|
|
(388,106
|
)
|
|
(388,106
|
)
|
Net cash provided by (used in) financing activities
|
|
(90,660
|
)
|
|
(388,106
|
)
|
|
(478,766
|
)
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
GENESIS PIPELINE ALABAMA, LLC
GENESIS DAVISON, LLC
DAVISON PETROLEUM SUPPLY, LLC
DAVISON TRANSPORTATION SERVICES, LLC
RED RIVER TERMINALS, L.L.C. [LA]
TEXAS CITY CRUDE OIL TERMINAL, LLC
TDC, L.L.C.
GENESIS NEJD HOLDINGS, LLC
GENESIS FREE STATE HOLDINGS, LLC
DAVISON TRANSPORTATION SERVICES, INC.
TDC SERVICES, LLC
GENESIS CHOPS I, LLC
GENESIS CHOPS II, LLC
GEL CHOPS GP, LLC
GENESIS ENERGY, LLC
GENESIS MARINE, LLC
MILAM SERVICES, INC.
GEL TEX MARKETING, LLC
GEL LOUISIANA FUELS, LLC
GEL WYOMING, LLC
GENESIS SEKCO, LLC
GEL SEKCO, LLC
GENESIS RAIL SERVICES, LLC
GEL OFFSHORE PIPELINE, LLC
GENESIS OFFSHORE, LLC
GEL OFFSHORE, LLC
GENESIS ODYSSEY, LLC
GEL ODYSSEY, LLC
GENESIS POSEIDON, LLC
GEL POSEIDON, LLC
PRONGHORN RAIL SERVICES, LLC
GENESIS BR, LLC
BR PORT SERVICES, LLC
CASPER EXPRESS PIPELINE, LLC
|
AP MARINE, LLC
TBP2, LLC
GEL PRCS, LLC
POWDER RIVER EXPRESS, LLC
POWDER RIVER OPERATING, LLC
GEL TEXAS PIPELINE, LLC
THUNDER BASIN HOLDINGS, LLC
THUNDER BASIN PIPELINE, LLC
ANTELOPE REFINING, LLC
POWDER RIVER CRUDE SERVICES, LLC
GENESIS OFFSHORE HOLDINGS, LLC
GENESIS SAILFISH HOLDINGS, LLC
GENESIS POSEIDON HOLDINGS, LLC
CAMERON HIGHWAY OIL PIPELINE COMPANY, LLC
CAMERON HIGHWAY PIPELINE GP, L.L.C.
FLEXTREND DEVELOPMENT COMPANY, L.L.C.
GEL DEEPWATER, LLC
GEL IHUB, LLC
GENESIS DEEPWATER HOLDINGS, LLC
GENESIS GTM OFFSHORE OPERATING COMPANY, LLC
GENESIS IHUB HOLDINGS, LLC
GENESIS SMR HOLDINGS, LLC
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
MANTA RAY GATHERING COMPANY, L.L.C.
MATAGORDA OFFSHORE, LLC
POSEIDON PIPELINE COMPANY, L.L.C.
SAILFISH PIPELINE COMPANY, L.L.C.
SEAHAWK SHORELINE SYSTEM, LLC
SOUTHEAST KEATHLEY CANYON PIPELINE COMPANY, L.L.C.
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Steven A. Finklea
|
|
|
Name:
|
Steven A. Finklea, CCTS
|
|
|
Title:
|
Vice President
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
GENESIS PIPELINE ALABAMA, LLC
GENESIS DAVISON, LLC
DAVISON PETROLEUM SUPPLY, LLC
DAVISON TRANSPORTATION SERVICES, LLC
RED RIVER TERMINALS, L.L.C. [LA]
TEXAS CITY CRUDE OIL TERMINAL, LLC
TDC, L.L.C.
GENESIS NEJD HOLDINGS, LLC
GENESIS FREE STATE HOLDINGS, LLC
DAVISON TRANSPORTATION SERVICES, INC.
TDC SERVICES, LLC
GENESIS CHOPS I, LLC
GENESIS CHOPS II, LLC
GEL CHOPS GP, LLC
GENESIS ENERGY, LLC
GENESIS MARINE, LLC
MILAM SERVICES, INC.
GEL TEX MARKETING, LLC
GEL LOUISIANA FUELS, LLC
GEL WYOMING, LLC
GENESIS SEKCO, LLC
GEL SEKCO, LLC
GENESIS RAIL SERVICES, LLC
GEL OFFSHORE PIPELINE, LLC
GENESIS OFFSHORE, LLC
GEL OFFSHORE, LLC
GENESIS ODYSSEY, LLC
GEL ODYSSEY, LLC
GENESIS POSEIDON, LLC
GEL POSEIDON, LLC
PRONGHORN RAIL SERVICES, LLC
GENESIS BR, LLC
BR PORT SERVICES, LLC
CASPER EXPRESS PIPELINE, LLC
|
AP MARINE, LLC
TBP2, LLC
GEL PRCS, LLC
POWDER RIVER EXPRESS, LLC
POWDER RIVER OPERATING, LLC
GEL TEXAS PIPELINE, LLC
THUNDER BASIN HOLDINGS, LLC
THUNDER BASIN PIPELINE, LLC
ANTELOPE REFINING, LLC
POWDER RIVER CRUDE SERVICES, LLC
GENESIS OFFSHORE HOLDINGS, LLC
GENESIS SAILFISH HOLDINGS, LLC
GENESIS POSEIDON HOLDINGS, LLC
CAMERON HIGHWAY OIL PIPELINE COMPANY, LLC
CAMERON HIGHWAY PIPELINE GP, L.L.C.
FLEXTREND DEVELOPMENT COMPANY, L.L.C.
GEL DEEPWATER, LLC
GEL IHUB, LLC
GENESIS DEEPWATER HOLDINGS, LLC
GENESIS GTM OFFSHORE OPERATING COMPANY, LLC
GENESIS IHUB HOLDINGS, LLC
GENESIS SMR HOLDINGS, LLC
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
MANTA RAY GATHERING COMPANY, L.L.C.
MATAGORDA OFFSHORE, LLC
POSEIDON PIPELINE COMPANY, L.L.C.
SAILFISH PIPELINE COMPANY, L.L.C.
SEAHAWK SHORELINE SYSTEM, LLC
SOUTHEAST KEATHLEY CANYON PIPELINE COMPANY, L.L.C.
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Steven A. Finklea
|
|
|
Name:
|
Steven A. Finklea, CCTS
|
|
|
Title:
|
Vice President
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
GENESIS PIPELINE ALABAMA, LLC
GENESIS DAVISON, LLC
DAVISON PETROLEUM SUPPLY, LLC
DAVISON TRANSPORTATION SERVICES, LLC
RED RIVER TERMINALS, L.L.C. [LA]
TEXAS CITY CRUDE OIL TERMINAL, LLC
TDC, L.L.C.
GENESIS NEJD HOLDINGS, LLC
GENESIS FREE STATE HOLDINGS, LLC
DAVISON TRANSPORTATION SERVICES, INC.
TDC SERVICES, LLC
GENESIS CHOPS I, LLC
GENESIS CHOPS II, LLC
GEL CHOPS GP, LLC
GENESIS ENERGY, LLC
GENESIS MARINE, LLC
MILAM SERVICES, INC.
GEL TEX MARKETING, LLC
GEL LOUISIANA FUELS, LLC
GEL WYOMING, LLC
GENESIS SEKCO, LLC
GEL SEKCO, LLC
GENESIS RAIL SERVICES, LLC
GEL OFFSHORE PIPELINE, LLC
GENESIS OFFSHORE, LLC
GEL OFFSHORE, LLC
GENESIS ODYSSEY, LLC
GEL ODYSSEY, LLC
GENESIS POSEIDON, LLC
GEL POSEIDON, LLC
PRONGHORN RAIL SERVICES, LLC
GENESIS BR, LLC
BR PORT SERVICES, LLC
CASPER EXPRESS PIPELINE, LLC
|
AP MARINE, LLC
TBP2, LLC
GEL PRCS, LLC
POWDER RIVER EXPRESS, LLC
POWDER RIVER OPERATING, LLC
GEL TEXAS PIPELINE, LLC
THUNDER BASIN HOLDINGS, LLC
THUNDER BASIN PIPELINE, LLC
ANTELOPE REFINING, LLC
POWDER RIVER CRUDE SERVICES, LLC
GENESIS OFFSHORE HOLDINGS, LLC
GENESIS SAILFISH HOLDINGS, LLC
GENESIS POSEIDON HOLDINGS, LLC
CAMERON HIGHWAY OIL PIPELINE COMPANY, LLC
CAMERON HIGHWAY PIPELINE GP, L.L.C.
FLEXTREND DEVELOPMENT COMPANY, L.L.C.
GEL DEEPWATER, LLC
GEL IHUB, LLC
GENESIS DEEPWATER HOLDINGS, LLC
GENESIS GTM OFFSHORE OPERATING COMPANY, LLC
GENESIS IHUB HOLDINGS, LLC
GENESIS SMR HOLDINGS, LLC
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
MANTA RAY GATHERING COMPANY, L.L.C.
MATAGORDA OFFSHORE, LLC
POSEIDON PIPELINE COMPANY, L.L.C.
SAILFISH PIPELINE COMPANY, L.L.C.
SEAHAWK SHORELINE SYSTEM, LLC
SOUTHEAST KEATHLEY CANYON PIPELINE COMPANY, L.L.C.
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Robert V. Deere
|
|
|
Name:
|
Robert V. Deere
|
|
|
Title:
|
Chief Financial Officer
|
By:
|
/s/ Steven A. Finklea
|
|
|
Name:
|
Steven A. Finklea, CCTS
|
|
|
Title:
|
Vice President
|
(a)
|
Each Incremental Lender that is an Increasing Lender hereby agrees that (i) its Committed Amount will be increased by the amount of its Incremental Facility Committed Amount set forth on
Schedule 1
attached hereto effective as of the date on which the conditions described in Section 5(c) below are satisfied (or waived in accordance with Section 9.02 of the Credit Agreement), (ii) after giving effect to such increase, its total Committed Amount will be the amount of its “Total Committed Amount” set forth on
Schedule 1
attached hereto, (iii) it shall continue to be a Lender under the Credit Agreement and (iv) this Second Amendment constitutes the Committed Amount Increase Certificate for such Incremental Lender required by Section 2.05(c)(ii)(D) of the Credit Agreement.
|
(b)
|
Each Incremental Lender that is an Additional Lender hereby agrees (i) to become a Lender under the Credit Agreement effective as of the date on which the conditions described in
|
(c)
|
On the date on which the conditions described in Section 5(c) below are satisfied (or waived in accordance with Section 9.02 of the Credit Agreement), (i) each of the existing Lenders shall assign to each of the Incremental Lenders, and each of the Incremental Lenders shall purchase from each of the existing Lenders, at the principal amount thereof, such interests in the outstanding Loans and participations in Letters of Credit outstanding on such date that will result in, after giving effect to all such assignments and purchases, each existing Lender and each Incremental Lender holding its Ratable Portion of the outstanding Loans and participations in Letters of Credit after giving effect to the addition of the Incremental Facility Committed Amounts hereby; (ii) each Incremental Facility Committed Amount shall be deemed, for all purposes, a Committed Amount and each loan made thereunder shall be deemed, for all purposes, a Loan and have the same terms as any existing Loan and (iii) each Incremental Lender shall constitute a Lender with respect to its Incremental Facility Committed Amount and all matters relating thereto.
|
(d)
|
Each Incremental Lender (i) confirms that it has received a copy of the Credit Agreement and the other Loan Documents, together with copies of the financial statements referred to therein and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Second Amendment; (ii) agrees that it will, independently and without reliance upon the Administrative Agent or any other Lender or agent thereunder and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement; (iii) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Credit Agreement and the other Loan Documents as are delegated to Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (iv) agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Credit Agreement are required to be performed by it as a Lender.
|
(a)
|
Section 1.01 of the Credit Agreement is hereby amended by inserting the following defined terms in the appropriate alphabetic order:
|
(b)
|
The definition of “Permitted Encumbrances” in Section 1.01 of the Credit Agreement is hereby amended by amended and restating in their entirety as follows each of clause (h) thereof and the proviso at the end thereof:
|
(c)
|
Section 6.01(j) of the Credit Agreement is hereby amended by amending and restating clause (ii) of the proviso therein in its entirety as follows:
|
(d)
|
Section 6.02 of the Credit is hereby amended by (i) deleting the “and” from the end of Section 6.02(i) of the Credit Agreement, (ii) renaming the existing Section 6.02(j) of the Credit Agreement as Section 6.02(k) of the Credit Agreement and (iii) inserting the following new clause (j) after Section 6.02(i) of the Credit Agreement:
|
(e)
|
Section 6.14 of the Credit Agreement is hereby amended to add the following as a new clause (d) thereof:
|
(a)
|
Section 1.01 of the Credit Agreement is hereby amended by inserting the following defined terms in the appropriate alphabetic order:
|
(b)
|
Section 1.01 of the Credit Agreement is hereby amended by restating the following definitions in their entirety:
|
(i)
|
such Acquisition shall not constitute or include an Acquisition that results in a Joint Venture;
|
(ii)
|
no Default or Event of Default then exists or would result therefrom;
|
(iii)
|
with respect to any Acquisition that constitutes a Substantial Transaction, the Borrower shall have made and submitted to the Administrative Agent and the Lenders calculations with respect to the financial covenants contained in Section 6.14 for the respective Calculation Period on a
Pro
Forma
Basis as if the respective Acquisition that constitutes a Substantial Transaction (as well as the other Acquisitions that constitute Substantial Transactions
theretofore consummated after the first day of such Calculation Period) had occurred on the first day of such Calculation Period, and such calculations shall show that such financial covenants would have been complied with if such Acquisition had occurred on the first day of such Calculation Period; and
|
(iv)
|
such Acquisition shall not be hostile.”
|
(c)
|
The definition of “Adjusted Consolidated EBITDA” in Section 1.01 of the Credit Agreement is hereby amended by adding the following immediately prior to the period at the end of the first sentence of such definition:
|
(d)
|
The definition of “Consolidated Interest Expense” in Section 1.01 of the Credit Agreement is hereby amended by adding the following immediately prior to the period at the end of such definition:
|
(e)
|
Section 2.05(c)(i) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:
|
(f)
|
Each of Section 2.05(c)(ii)(D) of the Credit Agreement and Section 2.05(c)(ii)(E) of the Credit Agreement are hereby amended by adding the language “(except in connection with any increase consummated on the Increase and Amendment Effective Date)” immediately after the reference to “processing and recordation fee of $3,500” therein.
|
(g)
|
Section 6.01 of the Credit Agreement is hereby amended by (i) deleting the “and” from the end of Section 6.01(l) of the Credit Agreement, (ii) renaming the existing Section 6.01(m) of the Credit Agreement as Section 6.01(o) of the Credit Agreement and (iii) inserting the following new clauses (m) and (n) after Section 6.01(l) of the Credit Agreement:
|
(h)
|
Section 6.02(j) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:
|
(i)
|
Section 6.14(a) of the Credit Agreement is hereby amended and restated in its entirety to read as follows:
|
Fiscal Quarter Ending
|
Consolidated Leverage Ratio if the Equity Condition is satisfied on or prior to the Increase and Amendment Effective Date
|
Consolidated Leverage Ratio if the Equity Condition is not satisfied on or prior to the Increase and Amendment Effective Date
|
September 30, 2015
|
5.75 to 1.00
|
6.00 to 1.00
|
December 31, 2015
|
5.50 to 1.00
|
5.75 to 1.00
|
March 31, 2016
|
5.50 to 1.00
|
5.75 to 1.00
|
June 30, 2016
|
5.50 to 1.00
|
5.50 to 1.00
|
September 30, 2016 and thereafter
|
5.00 to 1.00
|
5.00 to 1.00
|
(j)
|
Sections 6.14(b) and 6.14(c) of the Credit Agreement are each hereby amended by adding “, commencing with the Test Period ending September 30, 2015” after the first reference to “Test Period” that appears in each of Section 6.14(b) and Section 6.14(c) of the Credit Agreement.
|
(k)
|
Section 6.14 of the Credit Agreement is hereby amended to add the following as a new clause (e) thereof:
|
(l)
|
Section 6.17 of the Credit Agreement is hereby amended and restated in its entirety as follows:
|
(m)
|
Schedule 2.01
to the Credit Agreement is hereby amended and restated in its entirety as attached hereto.
|
(n)
|
Exhibit I
to the Credit Agreement is hereby amended and restated in its entirety as attached hereto.
|
(a)
|
The amendments set forth in Section 3 of this Second Amendment shall not become effective until the date (the “
Second Amendment Effective Date
”) on which each of the following conditions is satisfied (or waived in accordance with Section 9.02 of the Credit Agreement):
|
(i)
|
The Administrative Agent shall have received, from the Required Lenders and the Borrower, executed counterparts (in such number as may be requested by the Administrative Agent) of this Second Amendment;
provided
that this Section 5(a)(i) does not require the delivery of the counterparts described in Section 5(c)(i).
|
(b)
|
The amendments set forth in Section 4 of this Second Amendment and the obligations of the Incremental Lenders to make Loans under the Incremental Facility Committed Amounts hereunder shall not become effective until the date (the “
Increase and Amendment Effective Date
”) on which each of the following conditions is satisfied (or waived in accordance with Section 9.02 of the Credit Agreement):
|
(i)
|
The conditions set forth in Section 5(a) shall have been satisfied.
|
(ii)
|
Prior to or substantially simultaneously with the Increase and Amendment Effective Date, the Specified Acquisition shall have been consummated in accordance with applicable law and the Specified Acquisition PSA, and the Administrative Agent shall have received a certificate executed by a Responsible Officer of the Borrower, dated as of the Increase and Amendment Effective Date, certifying that such acquisition was consummated in accordance with Section 6.05 of the Credit Agreement (as amended hereby), together with such additional evidence of compliance as shall be reasonably requested by the Administrative Agent. The Specified Acquisition PSA shall not have been altered, amended or otherwise changed or supplemented or any provision waived or consented to (including any change in the purchase price) without the prior written consent of the Arrangers (such consent not to be unreasonably withheld or delayed). All conditions precedent to the consummation of the Specified Acquisition, as set forth in the Specified Acquisition PSA, shall have been satisfied in all material respects (without waiver thereof that has not been consented to in writing by the Arrangers (such consent not to be unreasonably withheld or delayed)).
|
(iii)
|
(A) None of the Arrangers (or any Affiliate thereof that are Lenders) shall become aware after July 16, 2015 of any information, or any event, development or change with respect
|
(iv)
|
The Administrative Agent shall have received a reaffirmation agreement in form and substance satisfactory to the Administrative Agent, executed and delivered by each of the Borrower Parties with respect to its obligations and the Liens granted by it under the Security Documents.
|
(v)
|
The Administrative Agent shall have received, on behalf of itself, the Lenders and each Issuing Bank on the Increase and Amendment Effective Date, (A) the favorable written opinion of Akin Gump Strauss Hauer & Feld LLP, counsel to the Borrower Parties, and of other counsel to the Borrower Parties reasonably requested by the Administrative Agent, in each case, in form and substance satisfactory to the Administrative Agent, dated as of the Increase and Amendment Effective Date in substantially the same scope as those delivered under the Credit Agreement prior to the Increase and Amendment Effective Date (other than as to collateral acquired as part of the Specified Acquisition) and (B) reasonably satisfactory evidence that all ownership interests of Borrower in the Borrower’s Subsidiaries, the Seller Entities and the Specified Acquired Business shall be owned by the Borrower or one or more Subsidiaries, in each case, free and clear of any Lien not permitted under the Loan Documents.
|
(vi)
|
The Administrative Agent shall have received: (A) an unaudited balance sheet and related statements of operations and cash flows of Borrower for each fiscal quarter of the 2015 fiscal year ended at least 45 days prior to the Increase Amendment Effective Date and for the elapsed period of the 2015 fiscal year ending on the last day of such fiscal quarter and for the comparable periods of the prior fiscal year (the “
Quarterly Financial Statements
”), all of which financial statements shall meet the requirements of Regulation S-X under the Securities Act and all other accounting rules and regulations of the Securities and Exchange Commission promulgated thereunder applicable to a Quarterly Report on Form 10-Q, (B) such financial information, if any, with respect to the Specified Acquired Business as the Borrower shall have received from Enterprise Products Operating LLC pursuant to the Specified Acquisition PSA on or prior to the Increase and Amendment Effectiveness Date promptly following the receipt thereof by the Borrower and (C) pro forma financial statements giving effect to the Transactions (as defined below), each in form satisfactory to the Administrative Agent, and forecasts prepared by management of the Borrower, each in form satisfactory to the Administrative Agent, of balance sheets, income statements and cash flow statements for each quarter for the first
|
(vii)
|
The Administrative Agent shall have received a certificate, in form and substance satisfactory to the Administrative Agent, executed on behalf of each of the Borrower Parties, which certificate shall certify as to the financial condition and solvency of the Borrower and each of the other Borrower Parties, on a consolidated basis with their respective Subsidiaries, in each case, after giving effect to the Transactions.
|
(viii)
|
The Administrative Agent, the Arrangers and the Lenders shall have received all fees and other amounts due and payable on or prior to the Increase and Amendment Effective Date, including (A) to the extent invoiced, reimbursement or payment of all out of pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement and (B) all upfront fees and amendment fees payable for the account of the Incremental Lenders and the Lenders, as applicable, due and payable under each of (1) the Commitment Letter, dated as of July 16, 2015 (the “
Commitment Letter
”), by and among the Borrower, the Arrangers, Wells Fargo Bank, National Association, Bank of America, N.A. and Bank of Montreal and (2) the Fee Letter, dated as of July 16, 2015 (the “
Fee Letter
”), by and among the Borrower, the Arrangers, Wells Fargo Bank, National Association, Bank of America, N.A., and Bank of Montreal. The Borrower shall have complied with all of its obligations under, and the terms of, the Fee Letter.
|
(ix)
|
The Administrative Agent shall have received, at least five (5) Business Days prior to the Increase and Amendment Effective Date, and be reasonably satisfied in form and substance with, all documentation and other information required by bank regulatory authorities under applicable “know-your-customer” and anti-money laundering rules and regulations, including but not restricted to the USA Patriot Act.
|
(x)
|
The Administrative Agent shall have received and reviewed lien searches reasonably requested by the Administrative Agent, and the Borrower shall have delivered duly completed UCC-3 termination statements requested by the Administrative Agent with respect to any Liens reflected in such search results that are not permitted by the Credit Agreement.
|
(xi)
|
The Administrative Agent shall have received with respect to the Borrower and each other Borrower Party (other than Restricted Subsidiaries acquired in connection with the Specified Acquisition): (A) certificates of good standing as of a recent date issued by the appropriate Governmental Authority of the state or jurisdiction of its incorporation or organization, where applicable; (B) a certificate of the Secretary or Assistant Secretary of each Borrower Party dated the Increase and Amendment Effective Date and certifying (1) that attached thereto are true and correct copies of the Organizational Documents of such Borrower Party or that there have been no changes to the Organizational Documents thereof from those most recently delivered to the Administrative Agent in connection with the Credit Agreement and that such documents remain in full force and effect, (2) that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors or other governing body of such Borrower Party (and, if applicable, any parent company of such Borrower Party) authorizing the execution, delivery and performance of this Second Amendment and any related Loan Documents and the borrowings hereunder and thereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect, and (3) as to the incumbency and
|
(xii)
|
The Administrative Agent shall have received “life of loan” flood certification(s) from a firm reasonably acceptable to the Administrative Agent covering any “Building” or “Manufactured (Mobile) Home” (each, as defined in the applicable Flood Insurance Regulations and to the extent not constituting Excluded Property) constituting Collateral showing whether or not such buildings are located in a special flood hazard area subject by federal regulation to mandatory flood insurance requirements, and to the extent required by Section 5.12(d) of the Credit Agreement, provide evidence of flood insurance related thereto.
|
(xiii)
|
The Administrative Agent shall have received a Note executed by the Borrower in favor of each Lender requesting a Note.
|
(xiv)
|
The Borrower shall be in compliance with Section 2.05(c)(ii)(A)-(B) of the Credit Agreement.
|
(xv)
|
At the time of and after giving effect to this Second Amendment, (A) all of the representations and warranties of each Borrower Party contained in each Loan Document to which it is a party shall be true and correct in all material respects (except that any such representations and warranties that are modified by materiality shall be true and correct in all respects), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations and warranties shall continue to be true and correct in all material respects as of such specified earlier date (except that any such representations and warranties that are modified by materiality shall be true and correct in all respects);
provided
that the representations and warranties with respect to the Specified Acquired Business shall be limited to the extent set forth in the penultimate paragraph of the Commitment Letter, and (B) no Default shall have occurred and be continuing.
|
(xvi)
|
The Administrative Agent shall have received evidence of the receipt of all governmental, regulatory, shareholder, lender and other third party consents and approvals necessary in connection with the Transaction, the failure to obtain which would reasonably be expected to result in a Material Adverse Effect (as defined in Section 5(b)(iii)); and the expiration of all applicable waiting periods (including, without limitation, the expiration or termination of the requisite waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976) without any action being taken by any governmental authority with respect to the Transactions that could reasonably be expected to materially and adversely affect the ability to consummate the Transactions on the terms described herein or result in a Material Adverse Effect (as defined in Section 5(b)(iii)). All Loans made by the Lenders to the Borrower or any of its Affiliates shall be in full compliance with the Federal Reserve’s regulations.
|
(xvii)
|
The absence of any action, suit, investigation or proceeding pending or, to the knowledge of the Borrower, threatened in any court or before any arbitrator or governmental authority that could reasonably be expected to have a Material Adverse Effect (as defined in Section 5(b)(iii)).
|
(xviii)
|
The Administrative Agent shall have had a Bank Marketing Period in accordance with and as defined in the Commitment Letter, except to the extent waived by the Arrangers in their sole discretion.
|
(xix)
|
After giving effect to the Specified Acquisition and the other Transactions, there shall be at least $250,000,000 of remaining availability under the Credit Agreement or the Replacement Credit Facility, as applicable.
|
(xx)
|
The Administrative Agent shall have received evidence reasonably acceptable to it that all insurance required to be maintained pursuant to the Loan Documents (including with respect to the Specified Acquired Business) has been obtained and is in effect, and the Borrower Parties shall have used commercially reasonable efforts to cause such insurance to (A) provide that no cancellation, material reduction in amount or material change in coverage thereof shall be effective until at least thirty days after receipt by the Administrative Agent of written notice thereof and (B) name the Administrative Agent, on behalf of the Secured Parties, as an additional insured, loss payee or mortgagee, as the case may be.
|
(c)
|
The obligations of the Incremental Lenders to make Loans under the Incremental Facility Committed Amounts hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 9.02 of the Credit Agreement)
|
(i)
|
The Administrative Agent shall have received, from the Incremental Lenders and the Borrower, executed counterparts (in such number as may be requested by the Administrative Agent) of this Second Amendment with respect to Section 2.
|
(ii)
|
The conditions set forth in Sections 5(a) and 5(b) shall have been satisfied.
|
(iii)
|
The Administrative Agent, each Incremental Lender (solely with respect to its own Incremental Facility Committed Amount) and the Borrower shall have agreed upon
Schedule 1
to this Second Amendment, the Administrative Agent shall have provided an updated
Schedule 2.01
to the Credit Agreement reflecting changes to the Lenders’ Committed Amounts in accordance with Section 2 above, and
Schedule 1
and
Schedule 2.01
shall have been attached to this Second Amendment.
|
(a)
|
On or prior to the date that is 30 days after the Increase and Amendment Effective Date (as such date may be extended by the Administrative Agent in its sole discretion), the Borrower Parties shall have satisfied (or caused to be satisfied) the following requirements:
|
(i)
|
the Administrative Agent shall have received with respect to each Restricted Subsidiary acquired in connection with the Specified Acquisition: (A) certificates of good standing as of a recent date issued by the appropriate Governmental Authority of the state or jurisdiction of its incorporation or organization, where applicable; (B) a certificate of the Secretary or Assistant Secretary of such Restricted Subsidiary certifying (1) that attached thereto are true and correct copies of the Organizational Documents of (x) such Restricted Subsidiary and (y) each Joint Venture in which such Restricted Subsidiary owns an interest and, in each case, that such documents remain in full force and effect, (2) that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors or other governing body of such Restricted Subsidiary (and, if applicable, any parent company of such Restricted Subsidiary) authorizing the execution, delivery and performance of any Loan Documents (or joinders thereto) executed by such Restricted Subsidiary and the guaranties provided thereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect, and (3) as to the incumbency and specimen signature of each officer executing any Loan Document or any other document delivered in connection herewith on behalf of such Restricted Subsidiary; and (C) a certificate of another officer as to the incumbency and specimen signature of
|
(ii)
|
the Borrower shall have taken such actions, or shall have caused the applicable Borrower Party to take such actions, as may be necessary to ensure a valid First Priority perfected Lien over 100% of the Equity Interests (other than Excluded Property) acquired by any Borrower Party in connection with the Specified Acquisition, and each Restricted Subsidiary acquired in connection with the Specified Acquisition shall have duly executed and delivered to the Administrative Agent an Assumption Agreement (as defined in the Guarantee and Collateral Agreement) and other Security Documents (other than those Security Documents described in Section 6(b)), as reasonably specified by and in form and substance reasonably satisfactory to the Administrative Agent, guaranteeing and securing payment of all the Secured Obligations;
|
(iii)
|
the Borrower and its Restricted Subsidiaries shall deliver all necessary financing statements (including “transmitting utility” financing statements) and financing statement amendments necessary in connection with the Loan Documents as a result of any of the Transactions; and
|
(iv)
|
each such Restricted Subsidiary executing or delivering a document pursuant to clause (ii) or (iii) above shall (A) deliver opinions of counsel related thereto, each in scope, form and substance reasonably satisfactory to Administrative Agent, (B) pay, or cause to be paid, all fees related to any such registration, filing or recording associated with the foregoing and (C) deliver any other deliverables required by Section 5.10 of the Credit Agreement in connection with the foregoing.
|
(b)
|
On or prior to the date that is 60 days after the Increase and Amendment Effective Date (as such date may be extended by the Administrative Agent in its sole discretion), the Borrower Parties shall have satisfied (or caused to be satisfied) the following requirements:
|
(i)
|
the Administrative Agent shall have received, to the extent necessary in connection with the Incremental Facility Committed Amounts, fully executed and notarized mortgage modifications, in proper form for recording in all appropriate offices in all applicable jurisdictions;
|
(ii)
|
each Restricted Subsidiary acquired in connection with the Specified Acquisition shall execute and deliver to the Administrative Agent any and all Mortgages and other instruments and documents necessary to grant Liens in any Real Property to the Administrative Agent for the benefit of the Secured Parties to the extent the Administrative Agent may reasonably deem necessary or desirable in order to perfect, protect and preserve such Liens required under the Credit Agreement; and
|
(iii)
|
each such Restricted Subsidiary executing or delivering a Mortgage or other document pursuant to clause (i) or (ii) above shall (A) deliver opinions of counsel related thereto, each in scope, form and substance reasonably satisfactory to Administrative Agent, (B) pay, or cause to be paid, all taxes and fees related to any such registration, filing or recording associated with the foregoing and (C) deliver any other deliverables required by Section 5.10 of the Credit Agreement in connection with the foregoing.
|
(a)
|
Confirmation
. The provisions of the Loan Documents, as amended by this Second Amendment, shall remain in full force and effect in accordance with their terms following the effectiveness of this Second Amendment.
|
(b)
|
Ratification and Affirmation; Representations and Warranties
. Each of the undersigned does hereby adopt, ratify, and confirm the Credit Agreement and the other Loan Documents, as amended hereby, and its obligations thereunder. The Borrower hereby (a) acknowledges, renews and extends its continued liability under each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly
|
(c)
|
Loan Document
. This Second Amendment and each agreement, instrument, certificate or document executed by the Borrower or any other Borrower Party or any of its or their respective officers in connection therewith are “Loan Documents” as defined and described in the Credit Agreement and all of the terms and provisions of the Loan Documents relating to other Loan Documents shall apply hereto and thereto.
|
(d)
|
Counterparts
. This Second Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Second Amendment by facsimile or other electronic transmission shall be effective as delivery of a manually executed counterpart hereof.
|
(e)
|
NO ORAL AGREEMENT
. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.
|
(f)
|
GOVERNING LAW
. THIS SECOND AMENDMENT (INCLUDING, BUT NOT LIMITED TO, THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.
|
|
GENESIS ENERGY, L.P.
, as Borrower
|
|
By: GENESIS ENERGY, LLC, its general partner
|
|
|
|
By:
/s/ Robert V. Deere
|
|
Robert V. Deere
|
|
Chief Financial Officer
|
|
GENESIS ENERGY, L.P.
, as Borrower
|
|
By: GENESIS ENERGY, LLC, its general partner
|
|
|
|
By:
/s/ Robert V. Deere
|
|
Robert V. Deere
|
|
Chief Financial Officer
|
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION
, as Administrative Agent, Issuing
|
|
Bank and a Lender
|
|
|
|
By:
/s/ Andrew Ostroy
|
|
Name: Andrew Ostroy
|
|
Title: Director
|
|
WELLS FARGO BANK, NATIONAL
|
|
ASSOCIATION
, as Administrative Agent, Issuing
|
|
Bank and a Lender
|
|
|
|
By:
/s/ Andrew Ostroy
|
|
Name: Andrew Ostroy
|
|
Title: Director
|
|
BANK OF AMERICA, N.A.
, as a Lender
|
|
|
|
By:
/s/ Michael Clayborne
|
|
Name: Michael Clayborne
|
|
Title: Vice President
|
|
BANK OF AMERICA, N.A.
, as a Lender
|
|
|
|
By:
/s/ Michael Clayborne
|
|
Name: Michael Clayborne
|
|
Title: Vice President
|
|
BMO HARRIS FINANCING, INC.
, as a Lender
|
|
|
|
By:
/s/ Kevin Utsey
|
|
Name: Kevin Utsey
|
|
Title: Director
|
|
BMO HARRIS FINANCING, INC.
, as a Lender
|
|
|
|
By:
/s/ Kevin Utsey
|
|
Name: Kevin Utsey
|
|
Title: Director
|
|
CITIBANK, N.A.
, as a Lender
|
|
|
|
By:
/s/ Michael Zeller
|
|
Name: Michael Zeller
|
|
Title: Vice President
|
|
CITIBANK, N.A.
, as a Lender
|
|
|
|
By:
/s/ Peter Kardos
|
|
Name: Peter Kardos
|
|
Title: Vice President
|
|
Deutsche Bank AG New York Branch
, as a Lender
|
|
|
|
By:
/s/ Dusan Lazarov
|
|
Name: Dusan Lazarov
|
|
Title: Director
|
|
Deutsche Bank AG New York Branch
, as a Lender
|
|
|
|
By:
/s/ Marcus M. Tarkington
|
|
Name: Marcus M. Tarkington
|
|
Title: Director
|
|
ROYAL BANK OF CANADA
, as a Lender
|
|
|
|
By:
/s/ Jason S. York
|
|
Name: Jason S. York
|
|
Title: Authorized Signatory
|
|
ROYAL BANK OF CANADA
, as a Lender
|
|
|
|
By:
/s/ Jason S. York
|
|
Name: Jason S. York
|
|
Title: Authorized Signatory
|
|
ABN AMRO CAPITAL USA LLC
, as a Lender
|
|
|
|
By:
/s/ David Montgomery
|
|
Name: David Montgomery
|
|
Title: Executive Director
|
|
|
|
By:
/s/ Darrell Holley
|
|
Name: Darrell Holley
|
|
Title: Managing Director
|
|
ABN AMRO CAPITAL USA LLC
, as a Lender
|
|
|
|
By:
/s/ Kaylan Hopson
|
|
Name: Kaylan Hopson
|
|
Title: Vice President
|
|
|
|
By:
/s/ Darrell Holley
|
|
Name: Darrell Holley
|
|
Title: Managing Director
|
|
COMPASS BANK
, as a Lender
|
|
|
|
By:
/s/ Blake Kirshman
|
|
Name: Blake Kirshman
|
|
Title: Senior Vice President
|
|
COMPASS BANK
, as a Lender
|
|
|
|
By:
/s/ Blake Kirshman
|
|
Name: Blake Kirshman
|
|
Title: Senior Vice President
|
|
THE BANK OF NOVA SCOTIA
, as a Lender
|
|
|
|
By:
/s/ Mark Sparrow
|
|
Name: Mark Sparrow
|
|
Title: Director
|
|
THE BANK OF NOVA SCOTIA
, as a Lender
|
|
|
|
By:
/s/ Mark Sparrow
|
|
Name: Mark Sparrow
|
|
Title: Director
|
|
SCOTIABANC INC.
, as a Lender
|
|
|
|
By:
/s/ J.F. Todd
|
|
Name: J.F. Todd
|
|
Title: Managing Director
|
|
U.S. BANK NATIONAL ASSOCIATION
, as a Lender
|
|
|
|
By:
/s/ Ben J. Leonard
|
|
Name: Ben J. Leonard
|
|
Title: Vice President
|
|
U.S. BANK NATIONAL ASSOCIATION
, as a Lender
|
|
|
|
By:
/s/ Ben J. Leonard
|
|
Name: Ben J. Leonard
|
|
Title: Vice President
|
Name of Incremental
Lender
|
Existing Committed
Amount
|
Incremental Facility
Committed Amount
|
Total Committed
Amount
|
Wells Fargo Bank, National Association
|
$90,000,000
|
$60,000,000
|
$150,000,000
|
Bank of America, N.A.
|
$90,000,000
|
$60,000,000
|
$150,000,000
|
BMO Harris
Financing, Inc.
|
$90,000,000
|
$60,000,000
|
$150,000,000
|
Citibank, N.A.
|
$73,000,000
|
$52,000,000
|
$125,000,000
|
Deutsche Bank AG New York Branch
|
$73,000,000
|
$52,000,000
|
$125,000,000
|
Royal Bank of
Canada
|
$73,000,000
|
$52,000,000
|
$125,000,000
|
ABN AMRO Capital
USA LLC
|
$73,000,000
|
$41,000,000
|
$114,000,000
|
Compass Bank
|
$73,000,000
|
$41,000,000
|
$114,000,000
|
U.S. Bank National
Association
|
$73,000,000
|
$41,000,000
|
$114,000,000
|
The Bank of Nova
Scotia
|
$36,500,000
|
$41,000,000
|
$77,500,000
|
Total:
|
$744,500,000
|
$500,000,000
|
$1,244,500,000
|
Name of Lender
|
Committed Amount
|
Wells Fargo Bank, National Association
|
$150,000,000
|
Bank of America, N.A.
|
$150,000,000
|
BMO Harris Financing, Inc.
|
$150,000,000
|
Citibank, N.A.
|
$125,000,000
|
Deutsche Bank AG New York Branch
|
$125,000,000
|
Royal Bank of Canada
|
$125,000,000
|
U.S. Bank National Association
|
$114,000,000
|
ABN AMRO Capital USA LLC
|
$114,000,000
|
Compass Bank
|
$114,000,000
|
The Bank of Nova Scotia
|
$77,500,000
|
Regions Bank
|
$59,000,000
|
Scotiabank Inc.
|
$36,500,000
|
Amegy Bank National Association
|
$35,000,000
|
Cadence Bank, N.A.
|
$30,000,000
|
Comerica Bank
|
$25,000,000
|
Santander Bank, N.A.
|
$25,000,000
|
Sumitomo Mitsui Banking Corporation
|
$25,000,000
|
Trustmark Bank
|
$20,000,000
|
Total
|
$1,500,000,000.00
|
|
Ladies and Gentlemen:
|
|
GENESIS ENERGY, L.P.
|
|
By: GENESIS ENERGY, LLC, its general partner
|
|
|
|
By:
|
|
Name:
|
|
Title:
|
|
I.
Interest Coverage Ratio
.
|
A.
|
Adjusted Consolidated EBITDA (Schedule 2) for the four
|
B.
|
Consolidated Interest Expense for such period
2
: $_____________
|
C.
|
Consolidated Interest Coverage Ratio (Line I.A / Line I.B): ________ to 1.00
|
|
Minimum Interest Coverage Ratio
|
|
3.00 to 1.00
3
|
A.
|
Consolidated Total Funded Debt as at the Statement Date: $___________
|
B.
|
Adjusted Consolidated EBITDA (Schedule 2) for the four
|
C.
|
Consolidated Leverage Ratio (Line II.A / Line II.B): ______ to 1.00
|
Fiscal Quarter Ending
|
Consolidated Leverage Ratio if the Equity Condition is satisfied on or prior to the Increase and Amendment Effective Date
|
Consolidated Leverage Ratio if the Equity Condition is not satisfied on or prior to the Increase and Amendment Effective Date
|
September 30, 2015
|
5.75 to 1.00
|
6.00 to 1.00
|
December 31, 2015
|
5.50 to 1.00
|
5.75 to 1.00
|
March 31, 2016
|
5.50 to 1.00
|
5.75 to 1.00
|
June 30, 2016
|
5.50 to 1.00
|
5.50 to 1.00
|
September 30, 2016 and thereafter
4
|
5.00 to 1.00
|
5.00 to 1.00
|
A.
|
Consolidated Total Senior Secured Funded Debt as at the
|
B.
|
Adjusted Consolidated EBITDA (Schedule 2) for the four
|
C.
|
Consolidated Senior Secured Leverage Ratio
|
|
Maximum Consolidated Senior Leverage Ratio
|
Prior to a Permitted Acquisition Period:
|
3.75 to 1.00
|
During a Permitted Acquisition Period:
|
4.25 to 1.00
5
|
|
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Four Fiscal Quarter Period
|
||||||
|
|
Ended
|
Ended
|
Ended
|
Ended
|
Ended
|
||||||
|
Consolidated Net Income of the Borrower and its Subsidiaries
8
|
—
|
—
|
—
|
—
|
—
|
||||||
+
|
Interest Expense
|
—
|
—
|
—
|
—
|
—
|
||||||
+
|
Federal, state, local income and foreign withholding taxes
|
—
|
—
|
—
|
—
|
—
|
||||||
+
|
Depreciation, depletion and amortization expense
|
—
|
—
|
—
|
—
|
—
|
||||||
+
|
Deferred or non-cash equity compensation or stock option or similar compensation expense
|
|
|
|
|
|
||||||
—
|
Actual cash payments made with respect to deferred compensation
|
|
|
|
|
|
||||||
+
|
Cash received by the Borrower or any Restricted Subsidiary pursuant to any Direct Financing Lease
|
|
|
|
|
|
||||||
+
|
Transaction Costs
9
|
—
|
—
|
—
|
—
|
—
|
||||||
=
|
Consolidated EBITDA before cash distributions
|
|
|
|
|
|
+
|
Cash distributions from Unrestricted Subsidiaries
10
|
|
|
|
|
|
+
|
Cash distributions from Joint Ventures or the Equity Interests of other Persons
|
|
|
|
|
|
=
|
Consolidated EBITDA
|
|
|
|
|
|
+
|
Pro Forma Adjustments (other than Non-Historical Pro Forma Adjustments and Material Project EBITDA Adjustments)
|
|
|
|
|
|
+
|
Non-Historical Pro Forma Adjustments, as applicable
|
|
|
|
|
|
+
|
Material Project EBITDA Adjustments, as applicable
|
|
|
|
|
|
=
|
(Preliminary) Adjusted Consolidated EBITDA
|
|
|
|
|
|
—
|
Cash distributions from Joint Ventures (except for Joint Ventures (other than Exempted Joint Ventures) consummated on or before the Effective Date) in excess of 25% of (Preliminary) Adjusted Consolidated EBITDA
11
|
|
|
|
|
|
=
|
Adjusted Consolidated EBITDA
|
—
|
—
|
—
|
—
|
—
|
SUBSIDIARY
|
|
JURISDICTION OF ORGANIZATION
|
ANTELOPE REFINING, LLC
|
|
DELAWARE
|
AP MARINE, LLC
|
|
DELAWARE
|
BR PORT SERVICES, LLC
|
|
DELAWARE
|
CAMERON HIGHWAY OIL PIPELINE COMPANY, LLC
|
|
DELAWARE
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CAMERON HIGHWAY PIPELINE GP, L.L.C.
|
|
DELAWARE
|
CAMERON HIGHWAY PIPELINE I, L.P.
|
|
DELAWARE
|
CASPER EXPRESS PIPELINE, LLC
|
|
DELAWARE
|
DAVISON PETROLEUM SUPPLY, LLC
|
|
DELAWARE
|
DAVISON TRANSPORTATION SERVICES, INC.
|
|
DELAWARE
|
DAVISON TRANSPORTATION SERVICES, LLC
|
|
DELAWARE
|
FLEXTREND DEVELOPMENT COMPANY, L.L.C.
|
|
DELAWARE
|
GEL CHOPS GP, LLC
|
|
DELAWARE
|
GEL CHOPS I, L.P.
|
|
DELAWARE
|
GEL CHOPS II, L.P.
|
|
DELAWARE
|
GEL DEEPWATER, LLC
|
|
DELAWARE
|
GEL IHUB, LLC
|
|
DELAWARE
|
GEL ODYSSEY, LLC
|
|
DELAWARE
|
GEL OFFSHORE PIPELINE, LLC
|
|
DELAWARE
|
GEL OFFSHORE, LLC
|
|
DELAWARE
|
GEL POSEIDON, LLC
|
|
DELAWARE
|
GEL PRCS, LLC
|
|
DELAWARE
|
GEL SEKCO, LLC
|
|
DELAWARE
|
GEL TEX MARKETING, LLC
|
|
DELAWARE
|
GEL TEXAS PIPELINE, LLC
|
|
DELAWARE
|
GEL WYOMING, LLC
|
|
DELAWARE
|
GENESIS BR, LLC
|
|
DELAWARE
|
GENESIS CHOPS I, LLC
|
|
DELAWARE
|
GENESIS CHOPS II, LLC
|
|
DELAWARE
|
GENESIS CO2 PIPELINE, L.P.
|
|
DELAWARE
|
GENESIS CRUDE OIL, L.P.
|
|
DELAWARE
|
GENESIS DAVISON, LLC
|
|
DELAWARE
|
GENESIS DEEPWATER HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS ENERGY FINANCE CORPORATION
|
|
DELAWARE
|
GENESIS ENERGY, L.P.
|
|
DELAWARE
|
GENESIS ENERGY, LLC
|
|
DELAWARE
|
GENESIS FREE STATE HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS FREE STATE PIPELINE, LLC
|
|
DELAWARE
|
GENESIS GTM OFFSHORE OPERATING COMPANY, LLC
|
|
DELAWARE
|
GENESIS IHUB HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS MARINE, LLC
|
|
DELAWARE
|
SUBSIDIARY
|
|
JURISDICTION OF ORGANIZATION
|
GENESIS NATURAL GAS PIPELINE, L.P.
|
|
DELAWARE
|
GENESIS NEJD HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS NEJD PIPELINE, LLC
|
|
DELAWARE
|
GENESIS ODYSSEY, LLC
|
|
DELAWARE
|
GENESIS OFFSHORE HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS OFFSHORE, LLC
|
|
DELAWARE
|
GENESIS PIPELINE ALABAMA, LLC
|
|
ALABAMA
|
GENESIS PIPELINE TEXAS, L.P.
|
|
DELAWARE
|
GENESIS PIPELINE USA, L.P.
|
|
DELAWARE
|
GENESIS POSEIDON HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS POSEIDON, LLC
|
|
DELAWARE
|
GENESIS RAIL SERVICES, LLC
|
|
DELAWARE
|
GENESIS SAILFISH HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS SEKCO, LLC
|
|
DELAWARE
|
GENESIS SMR HOLDINGS, LLC
|
|
DELAWARE
|
GENESIS SYNGAS INVESTMENTS, L.P.
|
|
DELAWARE
|
GENESIS TEXAS CITY TERMINAL, LLC
|
|
DELAWARE
|
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
|
|
DELAWARE
|
MANTA RAY GATHERING COMPANY, L.L.C.
|
|
TEXAS
|
MATAGORDA OFFSHORE, LLC
|
|
TEXAS
|
MILAM SERVICES, INC.
|
|
DELAWARE
|
POSEIDON PIPELINE COMPANY, L.L.C.
|
|
DELAWARE
|
POWDER RIVER CRUDE SERVICES, LLC
|
|
DELAWARE
|
POWDER RIVER EXPRESS, LLC
|
|
DELAWARE
|
POWDER RIVER OPERATING, LLC
|
|
DELAWARE
|
PRONGHORN RAIL SERVICES, LLC
|
|
DELAWARE
|
RED RIVER TERMINALS, L.L.C.
|
|
LOUISIANA
|
SAILFISH PIPELINE COMPANY, L.L.C.
|
|
DELAWARE
|
SEAHAWK SHORELINE SYSTEM, LLC
|
|
TEXAS
|
SOUTHEAST KEATHLEY CANYON PIPELINE COMPANY, LLC
|
|
DELAWARE
|
TBP2, LLC
|
|
DELAWARE
|
TDC SERVICES, LLC
|
|
DELAWARE
|
TDC, L.L.C.
|
|
LOUISIANA
|
TEXAS CITY CRUDE OIL TERMINAL, LLC
|
|
DELAWARE
|
THUNDER BASIN HOLDINGS, LLC
|
|
DELAWARE
|
THUNDER BASIN PIPELINE, LLC
|
|
DELAWARE
|
1.
|
I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.;
|
2.
|
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and
|
d.
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors:
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 26, 2016
|
/s/ Grant E. Sims
|
|
|
Grant E. Sims
|
|
|
Chief Executive Officer
|
1.
|
I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.;
|
2.
|
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:
|
a)
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and
|
d)
|
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors:
|
a)
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 26, 2016
|
/s/ Robert V. Deere
|
|
|
Robert V. Deere
|
|
|
Chief Financial Officer
|
|
(1)
|
the Partnership’s Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
|
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
February 26, 2016
|
/s/ Grant E. Sims
|
|
Grant E. Sims
|
|
Chief Executive Officer,
|
|
Genesis Energy, LLC
|
|
(1)
|
the Partnership’s Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
|
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
February 26, 2016
|
/s/ Robert V. Deere
|
|
Robert V. Deere
|
|
Chief Financial Officer,
|
|
Genesis Energy, LLC
|