Genesis Energy (GEL) 8-K 2014 FY Other Events

Table of Contents Exhibit 99.1

Item 8. Financial Statements and Supplementary Data

GENESIS ENERGY, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

	Page
Financial Statements of Genesis Energy, L.P.
Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Partners’ Capital	6
Consolidated Statements of Cash Flows	7
Notes to Consolidated Financial Statements	8
1. Organization	8
2. Summary of Significant Accounting Policies	8
3. Acquisitions and Divestitures	12
4. Receivables	15
5. Inventories	15
6. Fixed Assets and Asset Retirement Obligations	16
7. Net Investment in Direct Financing Leases	16
8. Equity Investees	17
9. Intangible Assets, Goodwill and Other Assets	18
10. Debt	19
11. Partners' Capital and Distributions	21
12. Business Segment Information	22
13. Transactions with Related Parties	25
14. Supplemental Cash Flow Information	25
15. Equity-Based Compensation Plans and Employee Benefit Plans	26
16. Major Customers and Credit Risk	28
17. Derivatives	29
18. Fair-Value Measurements	31
19. Commitments and Contingencies	32
20. Income Taxes	33
21. Quarterly Financial Data (Unaudited)	36
22. Condensed Consolidating Financial Information	36

1

Table of Contents Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Genesis Energy, LLC and Unitholders of

Genesis Energy, L.P.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Genesis Energy, L.P. and subsidiaries (the "Partnership") as of December 31, 2014 and 2013, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2014. We also have audited the Partnership's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting (not presented herein). Our responsibility is to express an opinion on these financial statements and an opinion on the Partnership's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Genesis Energy, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 22, during the second quarter of 2015, the Partnership took actions related to certain non-guarantor subsidiaries that resulted in these subsidiaries previously categorized as non-guarantor becoming wholly owned guarantor subsidiaries. The changes made to guarantor subsidiaries did not impact the Partnership's previously reported consolidated revenues, operating income or net income. The condensed consolidating balance sheet as of December 31, 2014 and 2013 and the condensed consolidating statements of operations and cash flows for the years ended December 31, 2014, 2013, and 2012 have been retrospectively adjusted to reflect these updates to the Partnership’s guarantor subsidiaries.

2

Table of Contents Exhibit 99.1

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2015

(July 2, 2015 as to Note 22 to the consolidated financial statements)

3

Table of Contents Exhibit 99.1

GENESIS ENERGY, L.P.

CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,462		$	8,866
Accounts receivable—trade, net	271,529			368,033
Inventories	46,829			85,330
Other	27,546			72,994
Total current assets	355,366			535,223
FIXED ASSETS, at cost	1,899,058			1,327,974
Less: Accumulated depreciation	(268,057		)	(199,230		)
Net fixed assets	1,631,001			1,128,744
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	145,959			151,903
EQUITY INVESTEES	628,780			620,247
INTANGIBLE ASSETS, net of amortization	82,931			62,928
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	61,291			38,111
TOTAL ASSETS	$	3,230,374		$	2,862,202
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable—trade	$	245,405		$	316,204
Accrued liabilities	117,740			130,349
Total current liabilities	363,145			446,553
SENIOR SECURED CREDIT FACILITY	550,400			582,800
SENIOR UNSECURED NOTES	1,050,639			700,772
DEFERRED TAX LIABILITIES	18,754			15,944
OTHER LONG-TERM LIABILITIES	18,233			18,396
COMMITMENTS AND CONTINGENCIES (Note 19)
PARTNERS’ CAPITAL:
Common unitholders, 95,029,218 and 88,690,985 units issued and outstanding at December 31, 2014 and 2013, respectively	1,229,203			1,097,737
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	3,230,374		$	2,862,202

The accompanying notes are an integral part of these consolidated financial statements.

4

Table of Contents Exhibit 99.1

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

	Year Ended December 31,
	2014			2013			2012
REVENUES:
Pipeline transportation services	86,453			86,508			76,290
Refinery services	207,401			205,985			196,017
Marine transportation	229,282			152,542			118,204
Supply and logistics	3,323,028			3,689,795			2,976,850
Total revenues	3,846,164			4,134,830			3,367,361
COSTS AND EXPENSES:
Supply and logistics product costs	3,166,336			3,547,141			2,840,970
Supply and logistics operating costs	110,716			102,187			82,776
Marine transportation operating costs	142,793			104,676			80,547
Refinery services operating costs	121,401			131,289			123,477
Pipeline transportation operating costs	30,767			27,206			21,894
General and administrative	50,692			46,790			41,837
Depreciation and amortization	90,908			64,784			61,150
Total costs and expenses	3,713,613			4,024,073			3,252,651
OPERATING INCOME	132,551			110,757			114,710
Equity in earnings of equity investees	43,135			22,675			14,345
Interest expense	(66,639		)	(48,583		)	(40,923		)
Income from continuing operations before income taxes	109,047			84,849			88,132
Income tax (expense) benefit	(2,845		)	(845		)	9,205
Income from continuing operations	106,202			84,004			97,337
Income (loss) from discontinued operations	—			2,105			(1,018		)
NET INCOME	$	106,202		$	86,109		$	96,319
BASIC AND DILUTED NET INCOME PER COMMON UNIT:
Continuing operations	$	1.18		$	1.00		$	1.24
Discontinued operations	—			0.03			(0.01		)
Net income per common unit	$	1.18		$	1.03		$	1.23
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	90,060			83,957			78,363

`

The accompanying notes are an integral part of these consolidated financial statements.

5

Table of Contents Exhibit 99.1

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

	Number of Common Units	Partners' Capital
December 31, 2011	71,965	$	792,638
Net income	—	96,319
Cash distributions	—	(142,383		)
Issuance of units for cash, net (Note 11)	5,750	169,421
Conversion of waiver units (Note 11)	3,476	—
Other	12	500
December 31, 2012	81,203	916,495
Net income	—	86,109
Cash distributions	—	(168,441		)
Issuance of units for cash, net (Note 11)	5,750	263,574
Conversion of waiver units (Note 11)	1,738	—
December 31, 2013	88,691	1,097,737
Net income	—	106,202
Cash distributions	—	(200,461		)
Issuance of common units for cash, net (Note 11)	4,600	225,725
Conversion of waiver units (Note 11)	1,738	—
December 31, 2014	95,029	$	1,229,203

The accompanying notes are an integral part of these consolidated financial statements.

6

Table of Contents Exhibit 99.1

GENESIS ENERGY, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	106,202		$	86,109		$	96,319
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	90,908			64,796			61,166
Amortization and write-off of debt issuance costs and premium	4,785			4,339			4,037
Amortization of unearned income and initial direct costs on direct financing leases	(15,706		)	(16,152		)	(16,788		)
Payments received under direct financing leases	21,235			21,262			21,804
Equity in earnings of investments in equity investees	(43,135		)	(22,675		)	(14,345		)
Cash distributions of earnings of equity investees	57,165			34,132			23,900
Non-cash effect of equity-based compensation plans	4,494			12,473			7,197
Deferred and other tax benefits	1,745			(152		)	(9,222		)
Unrealized (gains) losses on derivative transactions	(17,984		)	1,313			86
Other, net	3,391			(873		)	2,085
Net changes in components of operating assets and liabilities, net of acquisitions (See Note 14)	77,954			(46,186		)	13,065
Net cash provided by operating activities	291,054			138,386			189,304
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(443,482		)	(343,119		)	(146,456		)
Cash distributions received from equity investees—return of investment	18,363			12,432			14,909
Investments in equity investees	(40,926		)	(94,551		)	(63,749		)
Acquisitions	(157,000		)	(230,880		)	(205,576		)
Proceeds from asset sales and discontinued operations	272			1,910			773
Other, net	(1,214		)	(1,622		)	(1,508		)
Net cash used in investing activities	(623,987		)	(655,830		)	(401,607		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,839,900			1,593,300			1,674,400
Repayments on senior secured credit facility	(1,872,300		)	(1,510,500		)	(1,583,700		)
Proceeds from issuance of senior unsecured notes, including premium	350,000			350,000			101,000
Debt issuance costs	(11,896		)	(8,157		)	(7,105		)
Issuance of common units for cash, net	225,725			263,574			169,421
Distributions to common unitholders	(200,461		)	(168,441		)	(142,383		)
Other, net	2,561			(4,748		)	1,135
Net cash provided by financing activities	333,529			515,028			212,768
Net increase (decrease) in cash and cash equivalents	596			(2,416		)	465
Cash and cash equivalents at beginning of period	8,866			11,282			10,817
Cash and cash equivalents at end of period	$	9,462		$	8,866		$	11,282

The accompanying notes are an integral part of these consolidated financial statements.

7

Table of Contents Exhibit 99.1

GENESIS ENERGY, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

We are a limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. We were formed in 1996 and are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.

In the fourth quarter of 2014, we reorganized our operating segments as a result of a change in the way our Chief

Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and

allocates resources. The results of our marine transportation activities, formerly reported in the Supply and Logistics Segment,

are now reported in our Marine Transportation Segment. In addition, the results of our offshore and onshore pipeline

transportation activities, formerly reported in the Pipeline Transportation Segment, are now reported separately in our Onshore

Pipeline Transportation Segment and Offshore Pipeline Transportation Segments.

As a result of the above changes, we currently manage our businesses through five divisions that constitute our

reportable segments – Onshore Pipeline Transportation, Offshore Pipeline Transportation, Refinery Services, Marine

Transportation and Supply and Logistics. Our disclosures related to prior periods have been recast to reflect our reorganized

segments.

These five divisions that constitute our reportable segments consist of the following:

•Onshore pipeline transportation of crude oil and, to a lesser extent, carbon dioxide (or “CO2”);

• Offshore pipeline transportation of crude oil in the Gulf of Mexico;

• 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.    

2. Summary of Significant Accounting Policies

Basis of Consolidation and Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2014 and 2013 and our results of operations, changes in partners’ capital and cash flows for the years ended December 31, 2014, 2013 and 2012. All intercompany balances and transactions have been eliminated. The accompanying Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries.

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Joint Ventures

We participate in several joint ventures, including a 50% interest in Cameron Highway Oil Pipeline Company (or “CHOPS”), a 50% interest in Southeast Keathley Canyon Pipeline Company, LLC (or “SEKCO”), a 28% interest in Poseidon Oil Pipeline Company, L.L.C. (or "Poseidon") and a 29% interest in Odyssey Pipeline L.L.C. (or "Odyssey"). We account for our investments in these joint ventures by the equity method of accounting. See Notes 3 and 8.

Use of Estimates

The preparation of our Consolidated Financial Statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances. Significant estimates that we make include: (1) liability and contingency accruals, (2) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (3) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (4) estimates of future asset retirement obligations. Additionally, for purposes of the calculation of the fair value of awards under equity-based

8

Table of Contents Exhibit 99.1

compensation plans, we make estimates regarding the expected life of the rights, expected forfeiture rates of the rights, volatility of our unit price and expected future distribution yield on our units. While we believe these estimates are reasonable, actual results could differ from these estimates. Changes in facts and circumstances may result in revised estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. We have no requirement for compensating balances or restrictions on cash. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.

Accounts Receivable

We review our outstanding accounts receivable balances on a regular basis and record an allowance for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.

Inventories

Our inventories are valued at the lower of cost or market. Cost is determined principally under the average cost method within specific inventory pools.

Fixed Assets

Property and equipment are carried at cost. Depreciation of property and equipment is provided using the straight-line method over the respective estimated useful lives of the assets. Asset lives are 5 to 40 years for pipelines and related assets, 20 to 30 years for marine vessels, 10 to 20 years for machinery and equipment, 3 to 7 years for transportation equipment, and 3 to 10 years for buildings and improvements, office equipment, furniture and fixtures and other equipment.

Interest is capitalized in connection with the construction of major facilities. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life.

Maintenance and repair costs are charged to expense as incurred. Costs incurred for major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset. Certain volumes of crude oil and refined products are classified in fixed assets, as they are necessary to ensure efficient and uninterrupted operations of the gathering businesses. These crude oil and refined products volumes are carried at their weighted average cost.

Long-lived assets are reviewed for impairment. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to be generated from the use and ultimate disposal of the asset. If the carrying value is determined to not be recoverable under this method, an impairment charge equal to the amount the carrying value exceeds the fair value is recognized. Fair value is generally determined from estimated discounted future net cash flows.

Deferred Charges on Marine Transportation Assets

Our marine vessels are required by US Coast Guard regulations to be re-certified after a certain period of time, usually every five years.  The US Coast Guard states that vessels must meet specified "seaworthiness" standards to maintain required operating certificates. To meet such standards, vessels must undergo regular inspection, monitoring, and maintenance, referred to as "dry-docking." Typical dry-docking costs include costs incurred to comply with regulatory and vessel classification inspection requirements, blasting and steel coating, and steel replacement. We defer and amortize these costs to maintenance and repair expense over the length of time that the certification is supposed to last.

Asset Retirement Obligations

Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. In general, our future asset retirement obligations relate to future costs associated with the removal of our oil and CO₂ pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset. Accretion of the discount increases the liability and is recorded to expense. See Note 6.

Direct Financing Leasing Arrangements

For our direct financing leases, we record the gross finance receivable, unearned income and the estimated residual value of the leased pipelines. Unearned income represents the excess of the gross receivable plus the estimated residual value over the costs of the pipelines. Unearned income is recognized as financing income using the interest method over the term of the transaction and is included in pipeline transportation services revenue in the Consolidated Statements of Operations. The pipeline cost is not included in fixed assets.

We review our direct financing lease arrangements for credit risk. Such review includes consideration of the credit rating and financial position of the lessee. See Note 7.

9

Table of Contents Exhibit 99.1

CO₂ Assets

Our CO₂ assets include three volumetric production payments, which are amortized on a units-of-production method. These assets are included in Other Assets in our Consolidated Balance Sheets. See Note 9.

Intangible and Other Assets

Intangible assets with finite useful lives are amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We are amortizing our customer and supplier relationships, contract agreements, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Intangible assets associated with lease or other items are being amortized on a straight-line basis.

We test intangible assets periodically to determine if impairment has occurred. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. No impairment has occurred of intangible assets in any of the periods presented.

Costs incurred in connection with the issuance of long-term debt and certain amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate, and test if necessary, goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. During evaluation, we perform a qualitative assessment of relevant events and circumstances to determine the likelihood of goodwill impairment. If it is deemed more likely than not that the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not necessary. If the calculated fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings may be necessary to reduce the carrying value of the goodwill to its implied fair value. In the event that we determine that goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made. No goodwill impairment has occurred in any of the periods presented. See Note 9 for further information.

Environmental Liabilities

We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.

Equity-Based Compensation

Our stock appreciation rights plan and phantom units issued under our 2010 Long-Term Incentive Plan result in the payment of cash to our employees or directors of our general partner upon exercise or vesting of the related award. The fair values of our equity-based awards are re-measured at the end of each reporting period and are recorded as liabilities. The liability and related compensation cost for our stock appreciation rights are calculated using a Black-Scholes option pricing model that takes into consideration the expected future value of the rights at their expected exercise dates and management’s assumptions about expectation of forfeitures prior to vesting. The fair value of our phantom units is equal to the market price of our common units. Our phantom units include both service-based and performance-based awards. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award. See Note 15 for more information on these plans.

Revenue Recognition

Product Sales—Revenues from the sale of crude oil, petroleum products and CO₂ by our supply and logistics segment, and caustic soda and NaHS by our refinery services segment are recognized when title to the inventory is transferred to the customer, pricing is fixed and determinable, collectibility is reasonably assured and there are no further significant obligations for future performance by us. Most frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although in certain situations, title transfers when the inventory is loaded for transportation to the customer. Our crude oil and petroleum products are typically sold at prices based off daily or monthly published prices. Many of our contracts for sales of NaHS incorporate the price of caustic soda in the pricing formulas.

Marine Transportation—Revenues from the inland and offshore marine transportation of heavy refined petroleum products, including asphalt and crude oil, via our barges or vessels are recognized over the transit time of individual shipments as determined on an individual contract basis. Revenue from these contracts is typically based on a set day rate or a set fee per

10

Table of Contents Exhibit 99.1

cargo movement. The costs of fuel, substantially all of which is a pass through expense, and other specified operational costs are directly reimbursed by the customer under most of these contracts.

Rail Facility Loading and Unloading Revenues—Revenues based on a per barrel fee from the loading and/or unloading of crude oil at our rail facilities is recognized as the crude oil enters or exits the railcars.

Pipeline Transportation—Revenues from transportation of crude oil by our pipelines are based on actual volumes at a published tariff. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to the specifications outlined in our regulated tariffs.

In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs include the right for us to make volumetric deductions from the shippers for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances.

We compare these allowances to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or a reduction of revenue, based on prevailing market prices at that time. When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand and record a liability for the purchase of crude oil that we must make to replace the lost volumes. We reflect inventories in the Consolidated Financial Statements at the lower of the recorded value or the market value at the balance sheet date. We value liabilities to replace crude oil at current market prices. The crude oil in inventory can then be sold, resulting in additional revenue if the sales price exceeds the inventory value.

Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline revenues.

Cost of Sales and Operating Expenses

Supply and logistics costs and expenses include the cost to acquire the product and the associated costs to transport it to our terminal facilities or to a customer for sale. Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks, railcars and barges, including personnel costs, fuel and maintenance of our equipment.

When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions on a net basis in our Consolidated Statements of Operations as supply and logistics revenues.

Marine operating costs consist primarily of employee and related costs to man the boats, barges, and vessels, maintenance and supply costs related to general upkeep of the boats, barges, and vessels, and fuel costs which are rebillable and passed through to the customer.

The most significant operating costs in our refinery services segment consist of the costs to operate NaHS plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas stream, and costs to transport the NaHS and caustic soda.

Pipeline operating costs consist primarily of power costs to operate pumping equipment, personnel costs to operate the pipelines, insurance costs and costs associated with maintaining the integrity of our pipelines.

Excise and Sales Taxes

We collect and remit excise and sales taxes to state and federal governmental authorities on its sales of fuels. These taxes are presented on a net basis, with any differences due to rebates allowed by those governmental entities reflected as a reduction of product cost in the Consolidated Statements of Operations.

Income Taxes

We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our Consolidated Statements of Operations, is included in the federal income tax returns of each partner.

Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized. Penalties and interest related to income taxes will be included in income tax expense in the Consolidated Statements of Operations.

Derivative Instruments and Hedging Activities

When we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk. Derivative transactions, which can include forward contracts and futures positions on the NYMEX, are recorded in the Consolidated Balance Sheets as assets and liabilities based on the derivative’s fair value. Changes in the fair

11

Table of Contents Exhibit 99.1

value of derivative contracts are recognized currently in earnings unless specific hedge accounting criteria are met. We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting. Accordingly, changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings. See Note 17.

Fair Value of Current Assets and Current Liabilities

The carrying amount of other current assets and other current liabilities approximates their fair value due to their short-term nature.

Net Income Per Common Unit

Basic and diluted net income per common unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding common units during the period. 

Prior Period Reclassifications

Certain prior period amounts have been reclassified to conform to the current period presentation, including our expanded presentation of "Revenues" and "Costs and Expenses" on our Consolidated Statements of Operations and expanded presentation in Note 12 relating to our change in segment reporting as previously discussed in Note 1.

Recent and Proposed Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("FASB") issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance will be effective for us beginning January 1, 2017 and early adoption is not permitted. The guidance permits the use of either a full retrospective or a modified retrospective approach. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

3. Acquisitions and Divestitures

Acquisitions

M/T American Phoenix

On November 13, 2014, we acquired the M/T American Phoenix from Mid Ocean Tanker Company for $157 million. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity that was placed into service during 2012.

The purchase price of $157 million was paid to Mid Ocean Tanker Company in cash, as funded with proceeds from available and committed liquidity under our $1 billion revolving credit facility. We have reflected the financial results of the acquired business in our marine transportation segment from the date of acquisition. We have recorded the assets acquired in the Consolidated Financial Statements at their fair values. Those fair values were developed by management.

The allocation of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows:

Property and equipment	$	125,000
Intangible assets	32,000
Total purchase price	$	157,000

12

Table of Contents Exhibit 99.1

Our Consolidated Financial Statements include the results of our acquired offshore marine transportation business since November 13, 2014, the effective closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:

	Year Ended December 31,
	2014
Revenues	$	3,038
Net income	$	454

The table below presents selected unaudited pro forma financial information for us incorporating the historical results of the acquired M/T American Phoenix. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2013 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. Depreciation expense for the fixed assets acquired is calculated on a straight-line basis over an estimated useful life of approximately 30 years.

	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

Offshore Marine Transportation Business

In August 2013, we acquired substantially all of the assets of the downstream transportation business of Hornbeck Offshore Services, Inc. for $230.9 million, which we refer to as our offshore marine transportation business and assets. The total acquisition cost of $230.9 million was allocated to fixed assets on our Consolidated Balance Sheet. The acquired business was primarily comprised of nine barges and nine tug boats that transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. That acquisition was funded with proceeds from our $1 billion revolving credit facility. We have reflected the financial results of the acquired business in our marine segment from the date of the acquisition.

Our Consolidated Financial Statements include the results of our acquired offshore marine transportation business since August 28, 2013, the effective closing date of that acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:

	Year Ended December 31,
	2013
Revenues	$	30,424
Net income	$	7,348

13

Table of Contents Exhibit 99.1

The table below presents selected unaudited pro forma financial information for us incorporating the historical results of our offshore marine transportation business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2012 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. Depreciation expense for the fixed assets acquired is calculated on a straight-line basis over an estimated useful life of approximately 25 years.

	Year Ended December 31,
	2013		2012
Pro forma earnings data:
Revenues from continuing operations	$	4,177,715	$	3,416,790
Net Income	$	98,846	$	98,665

Interests in Gulf of Mexico Crude Oil Pipeline Systems

On January 3, 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C., a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility. We account for our interests in Poseidon and Odyssey under the equity method of accounting. We have recorded the assets acquired and liabilities assumed of GOPL in the Consolidated Financial Statements at their estimated fair values. Such fair values were developed by management.

Our Consolidated Financial Statements include the results of the acquired pipeline interests since the effective closing date of the acquisition in January 2012. The following table presents selected financial information included in our Consolidated Financial Statements for the year ended December 31, 2012:

	Year Ended December 31,
	2012
Revenues	$	5,508
Equity in earnings of equity investees	$	13,118
Net income	$	15,112

Divestitures

On December 31, 2013 we sold our vehicle fuel procurement and delivery logistics management services business. We sold the business for $1 million and recorded a gain on the sale of approximately $0.9 million, included in Income (loss) from discontinued operations on the Consolidated Statements of Operations. That business, previously reported in our supply and logistics revenues and costs and expenses, was reclassified as discontinued operations in our Consolidated Statements of Operations for the years ended December 31, 2013 and 2012. The summarized operating results of our discontinued operations are as follows:

	Year Ended December 31,
	2013		2012
Revenues	$	593,733	$	702,695
Cost and expenses	592,505		703,715
Operating income (loss)	1,228		(1,020		)
Interest income	2		2
Income (loss) before income taxes	1,230		(1,018		)
Gain on sale of discontinued operations	875		—
Income (loss) from discontinued operations	$	2,105	$	(1,018	)

14

Table of Contents Exhibit 99.1

4. Receivables

Accounts receivable – trade, net consisted of the following:

	December 31,
	2014			2013
Accounts receivable - trade	$	274,502		$	369,559
Allowance for doubtful accounts	(2,973		)	(1,526		)
Accounts receivable - trade, net	$	271,529		$	368,033

The following table presents the activity of our allowance for doubtful accounts for the periods indicated:

	December 31,
	2014		2013			2012
Balance at beginning of period	$	1,526	$	2,372		$	1,044
(Credited) charged to costs and expenses	1,447		(86		)	2,096
Amounts written off	—		(760		)	(768		)
Balance at end of period	$	2,973	$	1,526		$	2,372

5. Inventories

The major components of inventories were as follows:

	December 31,
	2014		2013
Petroleum products	$	30,108	$	71,373
Crude oil	7,266		5,380
Caustic soda	2,850		2,679
NaHS	6,603		5,845
Other	2		53
Total	$	46,829	$	85,330

Inventories are valued at the lower of cost or market. The market value of inventories was below recorded costs by approximately $6.6 million at December 31, 2014; therefore we reduced the value of inventory in our Condensed Consolidated Financial Statements for this difference. At December 31, 2013, market values of our inventory exceeded recorded costs.

15

Table of Contents Exhibit 99.1

6. Fixed Assets and Asset Retirement Obligations

Fixed Assets

Fixed assets consisted of the following:

	December 31,
	2014			2013
Pipelines and related assets	$	466,613		$	338,920
Machinery and equipment	376,672			173,092
Transportation equipment	18,479			19,140
Marine vessels	731,016			554,679
Land, buildings and improvements	38,037			30,170
Office equipment, furniture and fixtures	6,696			5,633
Construction in progress	222,233			183,037
Other	39,312			23,303
Fixed assets, at cost	1,899,058			1,327,974
Less: Accumulated depreciation	(268,057		)	(199,230		)
Net fixed assets	$	1,631,001		$	1,128,744

Depreciation expense was $73.2 million, $46.3 million and $37.4 million for the years ended December 31, 2014, 2013, and 2012, respectively.

Asset Retirement Obligations

A reconciliation of our liability for asset retirement obligations is as follows:

December 31, 2012	$	12,695
Liabilities incurred	789
Accretion expense	848
December 31, 2013	14,332
Liabilities incurred	—
Accretion expense	458
December 31, 2014	$	14,790

7. Net Investment in Direct Financing Leases

Our direct financing leases include a lease of the Northeast Jackson Dome (“NEJD”) Pipeline. Under the terms of the agreement, we are paid quarterly payments, which commenced August 2008. These quarterly payments are fixed at approximately $20.7 million per year during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028, we will convey all of our interests in the NEJD Pipeline to the lessee for a nominal payment. There are requirements in our leases that would provide credit support should the credit rating of our lessee fall to certain levels.

16

Table of Contents Exhibit 99.1

The following table lists the components of the net investment in direct financing leases:

	December 31,
	2014			2013
Total minimum lease payments to be received	$	277,732		$	298,924
Estimated residual values of leased property (unguaranteed)	292			292
Unamortized initial direct costs	1,444			1,621
Less unearned income	(127,531		)	(143,415		)
Net investment in direct financing leases	151,937			157,422
Less current portion (included in other current assets)	(5,978		)	(5,519		)
Long-term portion of net investment in direct financing leases	$	145,959		$	151,903

At December 31, 2014, minimum lease payments to be received for each of the five succeeding fiscal years are $20.7 million.

8. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting (see Note 2 for a description of these investments). The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At December 31, 2014 and 2013, the unamortized excess cost amounts totaled $215.4 million and $225.7 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

The following table presents information included in our Consolidated Financial Statements related to our equity investees.

	Year Ended December 31,
	2014			2013			2012
Genesis’ share of operating earnings	$	53,783		$	33,152		$	24,532
Amortization of excess purchase price	(10,648		)	(10,477		)	(10,187		)
Net equity in earnings	$	43,135		$	22,675		$	14,345
Distributions received	$	75,528		$	46,564		$	38,809

The following tables present the combined balance sheet information for the last two years and income statement data for the last three years for our equity investees (on a 100% basis):

	December 31,
	2014		2013
BALANCE SHEET DATA:
Assets
Current assets	$	42,135	$	70,921
Fixed assets, net	1,015,305		1,028,808
Other assets	4,369		6,823
Total assets	$	1,061,809	$	1,106,552
Liabilities and equity
Current liabilities	$	25,369	$	55,918
Other liabilities	202,613		190,578
Equity	833,827		860,056
Total liabilities and equity	$	1,061,809	$	1,106,552

17

Table of Contents Exhibit 99.1

	Year Ended December 31,
	2014		2013		2012
INCOME STATEMENT DATA:
Revenues	$	246,265	$	183,533	$	162,267
Operating Income	$	146,760	$	102,107	$	80,841
Net Income	$	142,754	$	99,357	$	77,975

9. Intangible Assets, Goodwill and Other Assets

Intangible Assets

The following table reflects the components of intangible assets being amortized at December 31, 2014 and 2013:

		December 31, 2014						December 31, 2013
	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	$	81,880	$	12,774	$	94,654	$	76,283	$	18,371
Licensing agreements	6	38,678		28,983		9,695		38,678		26,055		12,623
Segment total		133,332		110,863		22,469		133,332		102,338		30,994
Supply & Logistics:
Customer relationships	5	35,430		30,228		5,202		35,430		28,568		6,862
Intangibles associated with lease	15	13,260		3,512		9,748		13,260		3,039		10,221
Segment total		48,690		33,740		14,950		48,690		31,607		17,083
Marine contract intangibles	5	32,000		833		31,167		—		—		—
Other	5	22,797		8,452		14,345		21,356		6,505		14,851
Total		$	236,819	$	153,888	$	82,931	$	203,378	$	140,450	$	62,928

The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services. The supply and logistics lease relates to a terminal facility in Shreveport, Louisiana. The marine contract intangibles relate to the contracts we assumed in the purchase of the M/T American Phoenix in November 2014.

We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. The supply and logistics lease, marine contract, and other intangible assets are being amortized on a straight-line basis. Amortization expense on intangible assets was $13.4 million, $14.6 million and $19.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.

18

Table of Contents Exhibit 99.1

The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:

	2015		2016		2017		2018		2019
Refinery Services:
Customer relationships	$	4,405	$	3,471	$	2,737	$	2,161	$	—
Licensing agreements	2,711		2,510		2,324		2,150		—
Supply and Logistics:
Customer relationships	1,275		981		757		586		454
Intangibles associated with lease	474		474		474		474		474
Marine contract intangibles	6,417		5,400		5,400		5,400		5,400
Other	2,057		2,025		2,006		2,006		2,006
Total	$	17,339	$	14,861	$	13,698	$	12,777	$	8,334

Goodwill

The carrying amount of goodwill by business segment at both December 31, 2014 and 2013 was $301.9 million in refinery services and $23.1 million in supply and logistics. We have not recognized any impairment losses related to goodwill for any of the periods presented.

Other Assets

Other assets consisted of the following:

	December 31,
	2014		2013
CO2 volumetric production payments, net of amortization	$	9,395	$	4,421
Deferred marine charges (1)	13,042		2,829
Other deferred costs and deposits	38,854		30,861
Other assets, net of amortization	$	61,291	$	38,111

(1) See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2)

The CO₂ assets are being amortized on a units-of-production method. We recorded amortization of $4.2 million in 2014, $3.9 million in 2013 and $3.8 million in 2012.

10. Debt

At December 31, 2014 and 2013, our obligations under debt arrangements consisted of the following:

	December 31,
	2014		2013
Senior secured credit facility	$	550,400	$	582,800
7.875% senior unsecured notes (including unamortized premium of $639 and $772 in 2014 and 2013, respectively)	350,639		350,772
5.750% senior unsecured notes	$	350,000	350,000
5.625% senior unsecured notes	$	350,000	—
Total long-term debt	$	1,601,039	$	1,283,572

19

Table of Contents Exhibit 99.1

Senior Secured Credit Facility

In June 2014, we amended and restated our $1 billion senior secured credit facility with a syndicate of banks to, among other things, extend the term of our credit facility to July 25, 2019. Additionally, the accordion feature was increased from $300 million to $500 million, giving us the ability to expand the size of the facility up to an aggregate $1.5 billion for acquisitions or internal growth projects, subject to lender consent. Our credit facility includes an inventory financing sublimit of $150 million.

The key terms for rates under our credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:

• 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, 2014, the applicable margins on our borrowings were 1.25% for alternate base rate borrowings and 2.25% 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, 2014, our letter of credit rate was 2.25%.

• We pay a commitment fee on the unused portion of the $1 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, 2014).

Our credit facility is secured by liens on a substantial portion of our assets, and by guarantees by all of our restricted subsidiaries (as defined in the credit facility).

Our credit facility contains customary covenants (affirmative, negative and financial) that could limit the manner in which we may conduct our business. As defined in our credit facility, we are required to meet three primary financial metrics—a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. Our credit agreement provides for the temporary inclusion of certain pro forma adjustments to the calculations of the required ratios following material acquisitions. In general, our leverage ratio calculation compares our consolidated funded debt (including outstanding notes we have issued) to EBITDA (as defined and adjusted in accordance with the credit facility) and cannot exceed 5.00 to 1.00 (5.50 to 1.00 in an acquisition period). Our senior secured leverage ratio excludes outstanding debt under senior unsecured notes and cannot exceed 3.75 to 1.00 (4.25 to 1.00 in an acquisition period). Our interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense and must be greater than 3.00 to 1.00 (2.75 to 1.00 during an acquisition period).

At December 31, 2014, we had $550.4 million borrowed under our credit facility, with $45.0 million of the borrowed amount designated as a loan under the inventory sublimit. The credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $10.8 million was outstanding at December 31, 2014. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of July 25, 2019. The total amount available for borrowings under our credit facility at December 31, 2014 was $438.8 million.

Senior Unsecured Notes

In November 2010, we issued $250 million in aggregate principal amount of 7.875% senior unsecured notes due December 15, 2018 (the "2018 Notes"). The 2018 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year. In February 2012, we issued an additional $100 million of aggregate principal amount of additional 2018 Notes. The additional 2018 Notes were issued at 101% of face value at an effective interest rate of 7.682%. The additional 2018 Notes have the same terms and conditions as the notes previously issued under the indenture. The issuance increased the total aggregate principal amount of the 2018 Notes to $350 million.

On February 8, 2013, we issued $350 million of aggregate principal amount of 5.75% senior unsecured notes (the "2021 Notes"). The 2021 Notes were sold at face value. Interest payments are due on February 15 and August 15 of each year. The 2021 Notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes.

On May 15, 2014, we issued $350 million in aggregate principal amount of 5.625% senior unsecured notes (the "2024 Notes"). The 2024 Notes were sold at face value. Interest payments are due on June 15 and December 15 of each year with the initial interest payment due December 15, 2014. The 2024 Notes mature on June 15, 2024.

20

Table of Contents Exhibit 99.1

The 2018, 2021 and 2024 Notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and are each fully and unconditionally guaranteed, subject to customary exceptions pursuant to the indentures governing our 2018, 2021 and 2024 Notes, as discussed below, jointly and severally, by certain of our wholly-owned subsidiaries. We have the right to redeem the 2018 Notes at any time after December 15, 2014, at a premium to the face amount of the notes that varies based on the time remaining to maturity of the 2018 Notes. We have the right to redeem the 2021 Notes at any time after February 15, 2017, at a premium to the face amount of the 2021 Notes that varies based on the time remaining to maturity on the 2021 Notes. Prior to February 15, 2016, we may also redeem up to 35% of the principal amount of the 2021 Notes for 105.75% of the face amount with the proceeds from an equity offering of our common units. We have the right to redeem the 2024 Notes at any time after June 15, 2019, at a premium to the face amount of the 2024 Notes that varies based on the time remaining to maturity on the 2024 Notes. Prior to June 15, 2017, we may also redeem up to 35% of the principal amount of the 2024 Notes for 105.625% of the face amount with the proceeds from an equity offering of our common units.

Guarantees of the 2018, 2021 and 2024 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not a restricted subsidiary of the Partnership (ii) if the Partnership designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, (iv) upon the liquidation or dissolution of such guarantor, or (v) at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers and any other guarantor.

Covenants and Compliance

Our credit agreement and the indenture governing the senior notes contain cross-default provisions. Our credit documents prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, those agreements contain various covenants limiting our ability to, among other things:

• 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.

A default under our credit documents would permit the lenders thereunder to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit facility, our ability to make distributions of “available cash” is not restricted. As of December 31, 2014, we were in compliance with the financial covenants contained in our credit facility and indenture.

11. Partners’ Capital and Distributions

At December 31, 2014, our outstanding equity consisted of 94,989,221 Class A common units and 39,997 Class B common units. The Class A units are traditional common units in us. The Class B units are identical to the Class A units and, accordingly, have voting and distribution rights equivalent to those of the Class A units, and, in addition, the Class B units have the right to elect all of our board of directors and are convertible into Class A units under certain circumstances, subject to certain exceptions.     

Our outstanding equity also included non-voting securities -- waiver units -- that were entitled to a minimal quarterly distribution until conversion into Class A common units at a 1 to 1 ratio. As of December 31, 2014, all of our waiver units had been converted into common units.

21

Table of Contents Exhibit 99.1

Distributions

Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. We paid distributions in 2015, 2014 and 2013 as follows:

Distribution For	Date Paid	Per Unit Amount		Total Amount
2012
4th Quarter	February 14, 2013	$	0.4850	$	39,390
2013
1st Quarter	May 15, 2013	$	0.4975	$	40,405
2nd Quarter	August 14, 2013	$	0.5100	$	42,302
3rd Quarter	November 14, 2013	$	0.5225	$	46,344
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

Equity Issuances and Contributions

Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs.

In September 2014, we issued 4,600,000 Class A common units in a public offering at a price of $50.71 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $225.7 million from that offering. We used the net proceeds for general partnership purposes, including the repayment of outstanding borrowings under our revolving credit facility.

In September 2013, we issued 5,750,000 Class A common units in a public offering at a price of $47.51 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $263.6 million from that offering. We used the net proceeds for general partnership purposes, including the repayment of outstanding borrowings under our revolving credit facility.

In March 2012, we issued 5,750,000 Class A common units in a public offering at a price of $30.80 per unit. We received proceeds, net of underwriting discounts and offering costs, of $169.4 million from the offering. The net proceeds were used for general corporate purposes, including the repayment of borrowings under our credit facility.     

The new common units issued in 2014, 2013 and 2012 to the public for cash were as follows:

Period	Purchaser of Common Units	Units	Gross Unit Price		Issuance Value		Costs			Net Proceeds
September 2014	Public	4,600	$	50.71	$	233,266	$	(7,541	)	$	225,725
September 2013	Public	5,750	$	47.51	$	273,183	$	(9,609	)	$	263,574
March 2012	Public	5,750	$	30.80	$	177,100	$	(7,679	)	$	169,421

12. Business Segment Information

Our operations consist of five operating segments (see Note 1 for discussion of segment reporting change):

• Onshore Pipeline Transportation –transportation of crude oil, and to a lesser extent, CO₂;

• Offshore Pipeline Transportation – offshore transportation of crude oil in the Gulf of Mexico;

• 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;

22

Table of Contents Exhibit 99.1

• 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, CO₂.

Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States.

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases.

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment.

Segment information for each year presented below is as follows:

	Onshore Pipeline Transportation		Offshore Pipeline Transportation		Refinery Services			Marine Transportation		Supply & Logistics(a)			Total
Year Ended December 31, 2014
Segment Margin (b)	$	61,231	$	71,598	$	84,851		$	86,239	$	43,345		$	347,264
Capital expenditures (c)	$	46,611	$	37,639	$	2,385		$	232,783	$	325,130		$	644,548
Revenues:
External customers	$	66,760	$	3,296	$	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	$	83,157	$	3,296	$	207,401		$	229,282	$	3,323,028		$	3,846,164
Year Ended December 31, 2013
Segment Margin (b)	$	64,349	$	44,530	$	75,361		$	47,726	$	48,394		$	280,360
Capital expenditures (c)	$	130,787	$	94,286	$	3,258		$	260,736	$	215,138		$	704,205
Revenues:
External customers	$	65,452	$	3,923	$	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	$	82,585	$	3,923	$	205,985		$	152,542	$	3,689,795		$	4,134,830
Year Ended December 31, 2012
Segment Margin (b)	$	58,039	$	38,500	$	72,883		$	37,528	$	55,383		$	262,333
Capital expenditures (c)	$	59,345	$	269,365	$	2,692		$	37,188	$	57,708		$	426,298
Revenues:
External customers	$	56,198	$	5,508	$	205,110		$	99,016	$	3,001,529		$	3,367,361
Intersegment (d)	14,584		—		(9,093		)	19,188		(24,679		)	—
Total revenues of reportable segments	$	70,782	$	5,508	$	196,017		$	118,204	$	2,976,850		$	3,367,361

Total assets by reportable segment were as follows:

	December 31, 2014		December 31, 2013		December 31, 2012
Onshore pipeline transportation	$	460,012	$	437,912	$	325,189
Offshore pipeline transportation	645,668		637,323		565,463
Refinery services	403,703		417,121		414,170
Marine transportation	745,128		529,914		276,736
Supply and logistics	907,189		782,547		473,611
Other assets	68,674		57,385		54,495
Total consolidated assets	$	3,230,374	$	2,862,202	$	2,109,664

23

Table of Contents Exhibit 99.1

(a) Discontinued operations are included in Segment Margin but excluded from revenues for all periods presented.

(b) A reconciliation of Segment Margin to income from continuing operations before income taxes for each year is presented below.

(c) Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of internal growth projects) as well as acquisitions of businesses and interests in equity investees. In addition to construction of internal growth projects, capital spending in our Offshore pipeline transportation segment included $36.1 million and $94.3 million during the years ended December 31, 2014 and December 31, 2013 representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline. During 2014, capital spending in our marine transportation segment included $157 million for our purchase of the M/T American Phoenix. During 2013, capital spending in our marine segment also included $230.9 million for the acquisition of our offshore marine transportation assets. During 2012, capital spending in our pipeline transportation segment also included $205.6 million for the acquisition of interests in several Gulf of Mexico pipelines.

(d) Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.

Reconciliation of Segment Margin to income from continuing operations:

	Year Ended December 31,
	2014			2013			2012
Segment Margin	$	347,264		$	280,360		$	262,333
Corporate general and administrative expenses	(47,065		)	(43,353		)	(38,372		)
Depreciation and amortization	(90,908		)	(64,784		)	(61,150		)
Interest expense	(66,639		)	(48,583		)	(40,923		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)	(31,093		)	(23,889		)	(24,464		)
Non-cash items not included in Segment Margin	3,017			(7,551		)	(5,280		)
Cash payments from direct financing leases in excess of earnings	(5,529		)	(5,110		)	(5,016		)
Income tax expense	(2,845		)	(845		)	9,205
Discontinued operations	—			(2,241		)	1,004
Income from continuing operations	$	106,202		$	84,004		$	97,337

(1) Includes distributions attributable to the quarter and received during or promptly following such quarter.

24

Table of Contents Exhibit 99.1

13. Transactions with Related Parties

Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:

	Year Ended December 31,
	2014		2013		2012
Revenues:
Sales of CO2 to Sandhill Group, LLC (1)	$	3,060	$	3,076	$	2,905
Petroleum products sales to Davison family businesses(2)	—		1,293		1,344
Petroleum products sales to an affiliate of the Quintana Group (2)(3)	—		—		21,143
Expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	630	$	600	$	600
Marine operating fuel and expenses provided by an affiliate of the Quintana Group (3)	—		—		6,260

(1) We own a 50% interest in Sandhill Group, LLC (or "Sandhill).

(2) Amounts included in discontinued operations for all periods presented.

(3) The Quintana Group monetized all of its remaining investment in our common units on October 5, 2012. Transactions with the Quintana Group are included in the above table as related party transactions through October 5, 2012.

Our CEO, Mr. Sims, owns an aircraft which is used by us for business purposes in the course of operations. We pay Mr. Sims a fixed monthly fee and reimburse the aircraft management company for costs related to our usage of the aircraft, including fuel and the actual out-of-pocket costs. Based on current market rates for chartering of private aircraft under long-term, priority arrangements with industry recognized chartering companies, we believe that the terms of this arrangement are no worse than what we could have expected to obtain in an arms-length transaction.

Amounts due from Related Parties

At December 31, 2014, and 2013, Sandhill owed us $0.3 million and $0.2 million, respectively, for purchases of CO₂.     

14. Supplemental Cash Flow Information

The following table provides information regarding the net changes in components of operating assets and liabilities:

	Year Ended December 31,
	2014			2013			2012
(Increase) decrease in:
Accounts receivable	$	95,014		$	(96,300	)	$	(34,299	)
Inventories	38,501			1,720			14,074
Deferred Charges	(8,935		)	—			—
Other current assets	62,305			(39,170		)	(9,593		)
Increase (decrease) in:
Accounts payable	(73,307		)	41,718			53,146
Accrued liabilities	(35,624		)	45,846			(10,263		)
Net changes in components of operating assets and liabilities	$	77,954		$	(46,186	)	$	13,065

Payments of interest and commitment fees, net of amounts capitalized, were $74.8 million, $49.7 million and $41.5 million during the years ended December 31, 2014, 2013 and 2012, respectively. We capitalized interest of $13.8 million, $13.3 million and $3.9 million during the years ended December 31, 2014, 2013 and 2012.

During the years ended December 31, 2014 and 2013, we paid taxes of $0.8 million and $0.6 million. During the year ended December 31, 2012, we received a tax refund, net of amounts paid, of $0.3 million.

At December 31, 2014, 2013 and 2012, we had incurred liabilities for fixed and intangible asset additions totaling $61.2 million, $52.5 million and $14.1 million, respectively, which had not been paid at the end of the year. Therefore, these amounts were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

25

Table of Contents Exhibit 99.1

At December 31, 2014 and 2013, we had incurred liabilities for other asset additions totaling $9.4 million and $0.1 million that had not been paid at the end of the year, and, therefore, were not included in the caption "Other, net" under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

15. Equity-Based Compensation Plans and Employee Benefit Plans

2010 Long Term Incentive Plan

In 2010, we adopted the 2010 Long-Term Incentive Plan (the “2010 Plan”). The 2010 Plan provides for the awards of phantom units and distribution equivalent rights to members of our board of directors, and employees who provide services to us. Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met. Distribution equivalent rights (“DERs”) are tandem rights to receive on a quarterly basis a cash amount per phantom unit equal to the amount of cash distributions paid per common unit. The 2010 Plan is administered by the Governance, Compensation and Business Development Committee (the “G&C Committee”) of our board of directors. The G&C Committee (at its discretion) designates participants in the 2010 Plan, determines the types of awards to grant to participants, determines the number of units to be covered by any award, and determines the conditions and terms of any award including vesting, settlement and forfeiture conditions.

The compensation cost associated with the phantom units is re-measured each reporting period based on the market value of our common units, and is recognized over the vesting period. The liability recorded for the estimated amount to be paid to the participants under the 2010 LTIP is adjusted to recognize changes in the estimated compensation cost and vesting. Management’s estimates of the fair value of these awards granted in 2014 are adjusted for assumptions about expected forfeitures of units prior to vesting. For our performance-based awards, our fair value estimates are weighted based on probabilities for each performance condition applicable to the award.

During 2014, we granted 125,988 phantom units with tandem DERs at a weighted average grant fair value of $54.14 per unit. During 2013, we granted 152,964 phantom units with tandem DERs at a weighted average grant date fair value of $46.88 per unit. The phantom units granted during 2014 and 2013 were both service-based and performance-based awards. The service-based awards vest on the third anniversary of the date of grant. Performance-based phantom unit awards granted in 2013 and 2014 will vest on the third anniversary of issuance, in an amount ranging from 50% to 150% of the targeted number of phantom units, if certain quarterly cash distribution per common unit targets are achieved in the fourth quarter of 2015 and 2016, respectively. If the quarterly cash distribution per common unit is below the threshold target, all of the performance-based phantom units granted will be forfeited.

During 2012, we granted 176,995 phantom units with tandem DERs at a weighted average grant date fair value of $31.14 per unit. These phantom units will vest in April 2015, the third anniversary of the date of grant, at 150% of the targeted number of phantom units due to the distribution per common unit target achieved in the fourth quarter of 2014.

A summary of our phantom unit activity for our service-based and performance-based awards is set forth below:

	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, 2013	105,385		$	35.42	$	3,733		334,969		$	35.79	$	11,989
Granted	43,225		$	54.05	2,336			82,763		$	54.18	4,484
Forfeited	(4,599	)	$	43.19	(199		)	(6,899	)	$	43.20	(298		)
Settled	(31,188	)	$	27.11	(846		)	(96,988	)	$	28.21	(2,736		)
Unvested at December 31, 2014	112,823		$	44.53	$	5,024		313,845		$	42.82	$	13,439

At December 31, 2014, we estimated the unrecognized compensation cost of our phantom awards to be approximately $4.9 million to be recognized over a weighted average period of approximately one year. We recorded $8.8 million and $13.1 million of compensation expense for the years ended December 31, 2014 and 2013, respectively. Our liability for these awards totaled $15.4 million and $17.1 million at December 31, 2014 and 2013, respectively.

Stock Appreciation Rights Plan

Our Stock Appreciation Rights Plan is administered by the G&C Committee, which determines, in its full discretion, who shall receive awards under the Plan, the number of rights to award, the grant date of the units and the formula for allocating rights to the participants and the strike price of the rights awarded. Each right is equivalent to one common unit.

26

Table of Contents Exhibit 99.1

The rights have a term of 10 years from the date of grant. If the right has not been exercised at the end of the ten year term and the participant has not terminated employment with us, the right will be deemed exercised as of the date of the right’s expiration and a cash payment will be made as described below.

Upon vesting, the participant may exercise rights and receive a cash payment calculated as the difference between the average of the closing market price of our common units for the ten days preceding the date of exercise over the strike price of the right being exercised. If the G&C Committee determines, in its full discretion, that it would cause significant financial harm to the Partnership to make cash payments to participants who have exercised rights under the Stock Appreciation Rights Plan, then the G&C Committee may authorize deferral of the cash payments until a later date.

Termination for any reason other than death, disability or normal retirement (as these terms are defined in the Stock Appreciation Rights Plan) will result in the forfeiture of any non-vested rights. Upon death, disability or normal retirement, all rights will become fully vested. If a participant is terminated for any reason within one year after the effective date of a change in control (as defined in the plan) all rights will become fully vested.

The compensation cost associated with our Stock Appreciation Rights plan, which upon exercise will result in the payment of cash to the employee, is re-measured each reporting period based on the fair value of the rights calculated using a Black-Scholes option pricing model that takes into consideration the expected future value of the rights at their expected exercise dates and management’s assumptions about expectation of forfeitures prior to vesting.

The liability amount accrued on the balance sheet is adjusted to the fair value of the outstanding awards at each balance sheet date with the adjustment reflected in the Consolidated Statement of Operations. The fair value is adjusted for expected forfeitures of rights (due to terminations before vesting, or expirations after vesting).

The estimates that we make each period to determine the fair value of these rights include the following assumptions:

	Assumptions Used for Fair Value of Rights
	December 31, 2014			December 31, 2013			December 31, 2012
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%

The following table reflects rights activity under our Stock Appreciation Rights Plan as of January 1, 2014, and changes during the year ended December 31, 2014:

	Stock Appreciation Rights		Weighted Average Strike Price		Weighted Average Contractual Remaining Term (Yrs)	Aggregate Intrinsic Value
Outstanding at December 31, 2013	207,498		$	17.43
Exercised during 2014	(37,813	)	$	51.59
Forfeited or expired during 2014	(8,830	)	$	16.03
Outstanding at December 31, 2014	160,855		$	18.08	3.47	$	3,906
Exercisable at December 31, 2014	160,855		$	18.08	3.47	$	3,906

The total intrinsic value of rights exercised during 2014, 2013 and 2012 was $1.4 million, $5.5 million and $3.3 million, respectively, which was paid in cash to the participants.

As of December 31, 2014, all of our SARs were vested and the related total compensation cost had been fully recognized.

We recorded a reduction to compensation expense related to our stock appreciation rights from continuing operations of $2.0 million in 2014. In 2013 and 2012 we recorded compensation expense related to our stock appreciation rights from continuing operations of $5.6 million and $4.3 million, respectively.

27

Table of Contents Exhibit 99.1

Equity-Based Compensation Plan Expense

Equity-based compensation expense from our continuing operations during the three years ended December 31, 2014 was as follows:

	Expense Related to Equity-Based Compensation Plans
Consolidated Statement of Operations	2014			2013		2012
Supply and logistics operating costs	$	485		$	4,524	$	2,707
Marine transportation operating costs	626			586		190
Refinery services operating costs	(62		)	1,978		1,427
Pipeline operating costs	(52		)	510		247
General and administrative expenses	5,824			11,073		6,448
Total	$	6,821		$	18,671	$	11,019

Bonus Program

Bonuses under our bonus plan are paid at the discretion of the G&C Committee to our employees and executive officers based on quantitative and qualitative measures relating to: our financial and operational performance relative to our peers; industry expectations; progress in attaining strategic goals; and individual performance. In 2014, the G&C Committee based bonus amounts primarily on the amount of cash we generated for distributions to our unitholders, measured on a calendar-year basis. Two metrics were considered by the G&C Committee in determining the general bonus pool – the level of Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generated and our company-wide safety record improvement which included a targeted achieved level in our company-wide incident injury rate. The level of Available Cash before Reserves generated for the year as a percentage of a target set by the G&C Committee is weighted 90% and the achieved level of the targeted improvement in our safety record is weighted 10%. The sum of the weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages established by the G&C Committee for the various levels of our employees to determine the maximum general bonus pool. In addition, the G&C Committee also considered other subjective factors in determining the general bonus pool and individual award amounts. At December 31, 2014, we accrued $8.1 million for estimated bonuses to be paid in March 2015. For 2013 and 2012, we paid bonuses totaling $5.3 million and $7.9 million, respectively, to our executive officers and employees.

Employee Benefit Plans

In order to encourage long-term savings and to provide additional funds for retirement to its employees, we sponsor a tax qualified profit-sharing and retirement savings plan. Under this plan, our matching contribution is calculated as an equal match of the first 6% of each employee’s annual pretax contribution. Our profit-sharing plan targets a 3% contribution of each eligible employee’s total compensation (subject to IRS limitations). The expenses included in the Consolidated Statements of Operations for costs relating to this plan were $6.3 million, $4.3 million and $3.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

We also provided certain health care and survivor benefits for our active employees. Our health care benefit programs are self-insured, with a catastrophic insurance policy to limit our costs. We plan to continue self-insuring these plans in the future. The expenses included in the Consolidated Statements of Operations for these benefits were $13.5 million, $10.4 million and $8.8 million in 2014, 2013 and 2012, respectively.

16. Major Customers and Credit Risk

Due to the nature of our supply and logistics operations, a disproportionate percentage of our trade receivables constitute obligations of oil companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of accounts owed by integrated and large independent energy companies with stable payment histories. The credit risk related to contracts which are traded on the NYMEX is limited due to daily margin requirements and other NYMEX requirements.

We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met.

28

Table of Contents Exhibit 99.1

During 2014, 2013 and 2012 our largest customer was Shell Oil Company, which accounted for 12%, 17% and 14% of total revenues respectively. The revenues from Shell Oil Company in all three years relate primarily to our supply and logistics operations.

17. Derivatives

Commodity Derivatives

We have exposure to commodity price changes related to our inventory and purchase commitments. We utilize derivative instruments (primarily futures and options contracts traded on the NYMEX) to hedge our exposure to commodity prices, primarily of crude oil, fuel oil and petroleum products. Our decision as to whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed.

In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party’s exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Consolidated Balance Sheets.

At December 31, 2014, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments. We had no outstanding derivative contracts that were designated as hedges under accounting rules.

	Sell (Short) Contracts		Buy (Long) Contracts
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	366		168
Weighted average contract price per bbl	$	74.82	$	65.30
Diesel futures:
Contract volumes (1,000 bbls)	56		—
Weighted average contract price per gal	$	2.43	$	—
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	465		95
Weighted average contract price per bbl	$	60.07	$	44.95
Crude oil options:
Contract volumes (1,000 bbls)	125		—
Weighted average premium received	$	2.08	$	—

29

Table of Contents Exhibit 99.1

Financial Statement Impacts

The following table summarizes the accounting treatment and classification of our derivative instruments on our Consolidated Financial Statements.

Derivative Instrument	Hedged Risk	Impact of Unrealized Gains and Losses
		Consolidated Balance Sheets	Consolidated Statements of Operations
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

Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities.

The following tables reflect the estimated fair value gain (loss) position of our derivatives at December 31, 2014 and 2013:

Fair Value of Derivative Assets and Liabilities

		Fair Value
	Consolidated Balance Sheets Location	December 31, 2014			December 31, 2013
Asset Derivatives:
Commodity derivatives—futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	16,383		$	615
Gross amount offset in the Consolidated Balance Sheets	Current Assets - Other	(2,310		)	(615		)
Net amount of assets presented in the Consolidated Balance Sheets		14,073			—
Liability Derivatives:
Commodity derivatives—futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other (1)	$	(2,310	)	$	(4,527	)
Gross amount offset in the Consolidated Balance Sheets	Current Assets - Other (1)	2,310			4,527
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 in 2013.

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists.  Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin.  Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange.  On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin.  As of December 31, 2014, we had a net broker receivable of approximately $2.8 million (consisting of initial margin of $2.4 million increased by $0.3 million of variation margin).  As of December 31, 2013, we had a net broker receivable of approximately $5.3 million (consisting of initial margin of $4.1 million increased by $1.2 million of variation margin that had

30

Table of Contents Exhibit 99.1

been returned to us).  At December 31, 2014 and December 31, 2013, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. 

Effect on Operating Results

	Amount of Gain (Loss) Recognized in Income
	Supply & Logistics Product Costs
	Year Ended December 31,
	2014		2013			2012
Commodity derivatives—futures and call options:
Contracts designated as hedges under accounting guidance	$	—	$	—		$	—
Contracts not considered hedges under accounting guidance	35,468		(3,268		)	(2,936		)
Total derivatives	$	35,468	$	(3,268	)	$	(2,936	)

We have no derivative contracts with credit contingent features.

18. Fair-Value Measurements

We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value:    

(1)    Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;

(2)    Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and

(3)    Level 3 fair values are based on unobservable inputs in which little or no market data exists.

As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013.

	December 31, 2014							December 31, 2013
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	16,383		$	—	$	—	$	615		$	—	$	—
Liabilities	$	(2,310	)	$	—	$	—	$	(4,527	)	$	—	$	—

Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.

See Note 17 for additional information on our derivative instruments.

31

Table of Contents Exhibit 99.1

Nonfinancial Assets and Liabilities

We utilize fair value on a non-recurring basis to perform impairment tests as required on our property, plant and equipment, goodwill and intangible assets. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified in Level 3, in the event that we were required to measure and record such assets within our Consolidated Financial Statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3.

Other Fair Value Measurements

We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At December 31, 2014 our senior unsecured notes had a carrying value of $1,050.6 million and a fair value of $1,003.6 million, compared to $700.8 million and $732.4 million, respectively at December 31, 2013. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.

19. Commitments and Contingencies

Commitments and Guarantees

Our office lease for our corporate headquarters extends until October 31, 2022. To transport products, we lease tractors, trailers and railcars. In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS and caustic soda. Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput. We have no minimum volumetric or financial requirements remaining on our pipeline lease.

The future minimum rental payments under all non-cancelable operating leases as of December 31, 2014, were as follows (in thousands):

	Office Space		Transportation Equipment		Terminals and Tanks		Total
2015	$	2,282	$	14,796	$	15,752	$	32,830
2016	1,846		9,451		7,149		18,446
2017	1,625		7,430		2,687		11,742
2018	1,631		5,967		2,692		10,290
2019	1,580		5,705		2,697		9,982
2020 and thereafter	4,484		6,617		20,866		31,967
Total minimum lease obligations	$	13,448	$	49,966	$	51,843	$	115,257

Total operating lease expense from our continuing operations was as follows (in thousands):

Year Ended December 31, 2014	$	37,941
Year Ended December 31, 2013	$	27,674
Year Ended December 31, 2012	$	21,530

We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however no assurance can be made that such environmental releases may not substantially affect our business.

32

Table of Contents Exhibit 99.1

Other Matters

Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.

We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations or cash flows.

20. Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the federal income tax returns of each of our partners.

A few of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We pay federal and state income taxes on these operations.

Our income tax (benefit) expense is as follows:

	Year Ended December 31,
	2014		2013			2012
Current:
Federal	$	—	$	345		$	(8,463	)
State	1,100		650			275
Total current income tax expense (benefit)	$	1,100	$	995		$	(8,188	)
Deferred:
Federal	$	1,508	$	(248	)	$	(1,035	)
State	237		98			18
Total deferred income tax benefit	$	1,745	$	(150	)	$	(1,017	)
Total income tax expense (benefit) from continuing operations (1)	$	2,845	$	845		$	(9,205	)

(1) Our discontinued operations had no income tax benefit or expense in any period presented.

33

Table of Contents Exhibit 99.1

Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the balance sheet date. Deferred tax assets and liabilities consist of the following:

	December 31,
	2014			2013
Deferred tax assets:
Current:
Other current assets	$	262		$	297
Other	8			8
Total current deferred tax asset	270			305
Net operating loss carryforwards	9,048			7,784
Total long-term deferred tax asset	9,048			7,784
Valuation allowances	(737		)	(660		)
Total deferred tax assets	$	8,581		$	7,429
Deferred tax liabilities:
Current:
Other	$	(871	)	$	(785	)
Long-term:
Fixed assets	(4,335		)	(4,441		)
Intangible assets	(14,419		)	(11,503		)
Total long-term liability	(18,754		)	(15,944		)
Total deferred tax liabilities	$	(19,625	)	$	(16,729	)
Total net deferred tax liability	$	(11,044	)	$	(9,300	)

We record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character in the future and in the appropriate taxing jurisdictions.

34

Table of Contents Exhibit 99.1

Our income tax expense (benefit) varies from the amount that would result from applying the federal statutory income tax rate to income from continuing operations before income taxes as follows:

	Year Ended December 31,
	2014			2013			2012
Income from continuing operations before income taxes	$	109,047		$	84,849		$	88,132
Partnership income not subject to tax	(104,751		)	(85,567		)	(90,815		)
Income (loss) subject to income taxes	$	4,296		$	(718	)	$	(2,683	)
Tax expense (benefit) at federal statutory rate	$	1,504		$	(251	)	$	(939	)
State income taxes, net of federal tax	992			660			460
Effects of unrecognized tax positions, federal and state	—			—			(8,205		)
Return to provision, federal and state	(232		)	88			(166		)
Other	581			348			(355		)
Income tax expense (benefit)	$	2,845		$	845		$	(9,205	)
Effective tax rate on income from continuing operations before income taxes (1)	3		%	1		%	N/A

(1) Income tax expense is related to taxable income generated by our corporate subsidiaries and Texas Margin Tax. Due to the income tax benefit in 2012, the effective tax rate as a percentage of our total income from continuing operations before income taxes is not meaningful for those periods.

In 2012, we reversed $8.2 million of uncertain tax positions and recognized an income tax benefit in the Consolidated Statements of Operations as a result of tax audit settlements and the expiration of statutes of limitations. At December 31, 2014 and 2013, we had no uncertain tax positions.

35

Table of Contents Exhibit 99.1

21. Quarterly Financial Data (Unaudited)

The table below summarizes our unaudited quarterly financial data for 2014 and 2013.

	2014 Quarters								Total
	First		Second		Third		Fourth		Year
Revenues from continuing operations	$	1,019,719	$	1,015,049	$	964,114	$	847,282	$	3,846,164
Operating income	$	35,402	$	31,257	$	35,268	$	30,624	$	132,551
Income from continuing operations	$	29,775	$	21,148	$	29,113	$	26,166	$	106,202
Net income	$	29,775	$	21,148	$	29,113	$	26,166	$	106,202
Basic and diluted net income per common unit:
Continuing operations	$	0.34	$	0.24	$	0.33	$	0.28	$	1.18
Net income per common unit	$	0.34	$	0.24	$	0.33	$	0.28	$	1.18
Cash distributions per common unit (1)	$	0.5350	$	0.5500	$	0.5650	$	0.5800	$	2.2300
	2013 Quarters								Total
	First		Second		Third		Fourth		Year
Revenues from continuing operations	$	1,014,808	$	1,068,694	$	1,090,293	$	961,035	$	4,134,830
Operating income	$	30,005	$	33,360	$	24,092	$	23,300	$	110,757
Income from continuing operations	$	22,704	$	26,612	$	17,966	$	16,722	$	84,004
Loss from discontinued operations	$	143	$	290	$	508	$	1,164	$	2,105
Net income	$	22,847	$	26,902	$	18,474	$	17,886	$	86,109
Basic and diluted net income per common unit:
Continuing operations	$	0.28	$	0.32	$	0.21	$	0.19	$	1.00
Discontinued operations	$	—	$	0.01	$	0.01	$	0.01	$	0.03
Net income per common unit	$	0.28	$	0.33	$	0.22	$	0.20	$	1.03
Cash distributions per common unit (1)	$	0.4850	$	0.4975	$	0.5100	$	0.5225	$	2.0150

(1) Represents cash distributions declared and paid in the applicable period.

22. Condensed Consolidating Financial Information

Our $1,050 million aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 10 for additional information regarding our consolidated debt obligations.

During the second quarter of 2015, the Company took actions related to certain non-guarantor subsidiaries that resulted in these subsidiaries previously categorized as non-guarantor becoming wholly owned guarantor subsidiaries. The changes made to guarantor subsidiaries did not impact the Company's previously reported consolidated revenues, operating income or net income. The condensed consolidating balance sheet as of December 31, 2014 and 2013 and the condensed consolidating statements of operations and cash flows for the years ended December 31, 2014, 2013, and 2012 have been retrospectively adjusted to reflect these updates to our guarantor subsidiaries.

The following is condensed consolidating financial information for Genesis Energy, L.P. and subsidiary guarantors:

36

Table of Contents Exhibit 99.1

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	1,378,573		—		333,385			46,215			(1,412,269		)	345,904
Total current assets	1,378,582		—		341,695			47,358			(1,412,269		)	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	28,421		—		269,252			146,700			(154,192		)	290,181
Equity investees and other investments	—		—		628,780			—			—			628,780
Investments in subsidiaries	1,434,255		—		97,195			—			(1,531,450		)	—
Total assets	$	2,841,258	$	—	$	3,234,353		$	252,674		$	(3,097,911	)	$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	11,016	$	—	$	1,761,856		$	2,705		$	(1,412,432	)	$	363,145
Senior secured credit facilities	550,400		—		—			—			—			550,400
Senior unsecured notes	1,050,639		—		—			—			—			1,050,639
Deferred tax liabilities	—		—		18,754			—			—			18,754
Other liabilities	—		—		18,233			154,021			(154,021		)	18,233
Total liabilities	1,612,055		—		1,798,843			156,726			(1,566,453		)	2,001,171
Partners’ capital	1,229,203		—		1,435,510			95,948			(1,531,458		)	1,229,203
Total liabilities and partners’ capital	$	2,841,258	$	—	$	3,234,353		$	252,674		$	(3,097,911	)	$	3,230,374

37

Table of Contents Exhibit 99.1

Condensed Consolidating Balance Sheet
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
ASSETS
Current assets:
Cash and cash equivalents	$	20	$	—	$	8,049		$	797		$	—		$	8,866
Other current assets	1,133,695		—		515,143			37,286			(1,159,767		)	526,357
Total current assets	1,133,715		—		523,192			38,083			(1,159,767		)	535,223
Fixed Assets, at cost	—		—		1,252,445			75,529			—			1,327,974
Less: Accumulated depreciation	—		—		(184,856		)	(14,374		)	—			(199,230		)
Net fixed assets	—		—		1,067,589			61,155			—			1,128,744
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	21,432		—		238,283			152,412			(159,185		)	252,942
Equity investees and other investments	—		—		620,247			—			—			620,247
Investments in subsidiaries	1,236,164		—		89,600			—			(1,325,764		)	—
Total assets	$	2,391,311	$	—	$	2,863,957		$	251,650		$	(2,644,716	)	$	2,862,202
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	10,002	$	—	$	1,592,376		$	3,470		$	(1,159,295	)	$	446,553
Senior secured credit facilities	582,800		—		—			—			—			582,800
Senior unsecured notes	700,772		—		—			—			—			700,772
Deferred tax liabilities	—		—		15,944			—			—			15,944
Other liabilities	—		—		18,396			159,007			(159,007		)	18,396
Total liabilities	1,293,574		—		1,626,716			162,477			(1,318,302		)	1,764,465
Partners' capital	1,097,737		—		1,237,241			89,173			(1,326,414		)	1,097,737
Total liabilities and partners’ capital	$	2,391,311	$	—	$	2,863,957		$	251,650		$	(2,644,716	)	$	2,862,202

38

Table of Contents Exhibit 99.1

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:
Pipeline transportation services	$	—		$	—	$	61,686		$	24,767		$	—		$	86,453
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	—			—		3,816,246			43,056			(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
Pipeline transportation operating costs	—			—		29,910			857			—			30,767
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	—			—		109,643			22,266			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			—		175,392			6,591			(179,138		)	109,047
Income tax benefit (expense)	—			—		(3,030		)	185			—			(2,845		)
Income from continuing operations	106,202			—		172,362			6,776			(179,138		)	106,202
NET INCOME	$	106,202		$	—	$	172,362		$	6,776		$	(179,138	)	$	106,202

39

Table of Contents Exhibit 99.1

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:
Pipeline transportation services	$	—		$	—	$	60,707		$	25,801		$	—		$	86,508
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
Pipeline transportation operating costs	—			—		26,087			1,119			—			27,206
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 benefit (expense)	—			—		(676		)	(169		)	—			(845		)
Income from continuing operations	86,109			—		133,168			6,729			(142,002		)	84,004
Income from discontinued operations	—			—		2,105			—			—			2,105
NET INCOME	$	86,109		$	—	$	135,273		$	6,729		$	(142,002	)	$	86,109

40

Table of Contents Exhibit 99.1

Condensed Consolidating Statement of Operations
Year Ended December 31, 2012
	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:
Pipeline transportation services	$	—		$	—	$	50,106		$	26,184		$	—		$	76,290
Refinery services	—			—		192,083			19,999			(16,065		)	196,017
Marine transportation	—			—		118,204			—			—			118,204
Supply and logistics	—			—		2,976,850			—			—			2,976,850
Total revenues	—			—		3,337,243			46,183			(16,065		)	3,367,361
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,923,746			—			—			2,923,746
Marine transportation costs	—			—		80,547			—			—			80,547
Refinery services operating costs	—			—		120,095			19,489			(16,107		)	123,477
Pipeline transportation operating costs	—			—		21,081			813			—			21,894
General and administrative	—			—		41,837			—			—			41,837
Depreciation and amortization	—			—		58,554			2,596			—			61,150
Total costs and expenses	—			—		3,245,860			22,898			(16,107		)	3,252,651
OPERATING INCOME	—			—		91,383			23,285			42			114,710
Equity in earnings of equity investees	—			—		14,345			—			—			14,345
Equity in earnings of subsidiaries	137,151			—		7,184			—			(144,335		)	—
Interest (expense) income, net	(40,832		)	—		16,500			(16,591		)	—			(40,923		)
Income before income taxes	96,319			—		129,412			6,694			(144,293		)	88,132
Income tax benefit	—			—		8,903			302			—			9,205
Income from continuing operations	96,319			—		138,315			6,996			(144,293		)	97,337
Loss from discontinued operations	—			—		(1,018		)	—			—			(1,018		)
NET INCOME	96,319			—		137,297			6,996			(144,293		)	96,319

41

Table of Contents Exhibit 99.1

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	$	(148,008	)	$	—	$	591,431		$	5,296		$	(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		)
Repayments on loan to non-guarantor subsidiary	—			—		4,993			—			(4,993		)	—
Proceeds from asset sales	—			—		272			—			—			272
Other, net	—			—		(1,214		)	—			—			(1,214		)
Net cash used in investing activities	(182,970		)	—		(618,994		)	—			177,977			(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		)
Issuance of common units for cash, net	225,725			—		225,725			—			(225,725		)	225,725
Distributions to partners/owners	(200,461		)	—		(200,462		)	—			200,462			(200,461		)
Other, net	(1		)	—		2,561			(4,950		)	4,951			2,561
Net cash provided by financing activities	330,967			—		27,824			(4,950		)	(20,312		)	333,529
Net increase (decrease) in cash and cash equivalents	(11		)	—		261			346			—			596
Cash and cash equivalents at beginning of period	20			—		8,049			797			—			8,866
Cash and cash equivalents at end of period	$	9		$	—	$	8,310		$	1,143		$	—		$	9,462

42

Table of Contents Exhibit 99.1

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	$	(280,155	)	$	—	$	557,879		$	5,101		$	(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		)
Repayments on loan to non-guarantor subsidiary	—			—		4,512			—			(4,512		)	—
Proceeds from assets sales	—			—		1,910			—			—			1,910
Other, net	—			—		(1,622		)	—			—			(1,622		)
Net cash used in investing activities	(239,611		)	—		(651,318		)	—			235,099			(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, including premium	350,000			—		—			—			—			350,000
Debt issuance costs	(8,157		)	—		—			—			—			(8,157		)
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			—		90,385			(4,473		)	(90,660		)	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			—		11,103			169			—			11,282
Cash and cash equivalents at end of period	$	20		$	—	$	8,049		$	797		$	—		$	8,866

43

Table of Contents Exhibit 99.1

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
	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	$	(70,083	)	$	—	$	371,256		$	2,602		$	(114,471	)	$	189,304
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(146,296		)	(160		)	—			(146,456		)
Cash distributions received from equity investees - return of investment	27,878			—		14,909			—			(27,878		)	14,909
Investments in equity investees	(169,421		)	—		(63,749		)	—			169,421			(63,749		)
Acquisitions	—			—		(205,576		)	—			—			(205,576		)
Repayments on loan to non-guarantor subsidiary	—			—		4,078			—			(4,078		)	—
Proceeds from asset sales	—			—		773			—			—			773
Other, net	—			—		(1,508		)	—			—			(1,508		)
Net cash used in investing activities	(141,543		)	—		(397,369		)	(160		)	137,465			(401,607		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,674,400			—		—			—			—			1,674,400
Repayments on senior secured credit facility	(1,583,700		)	—		—			—			—			(1,583,700		)
Proceeds from issuance of senior unsecured notes	101,000			—		—			—			—			101,000
Debt issuance costs	(7,105		)	—		—			—			—			(7,105		)
Issuance of ownership interests to partners for cash	169,421			—		169,421			—			(169,421		)	169,421
Distributions to partners/owners	(142,383		)	—		(142,383		)	—			142,383			(142,383		)
Other, net	—			—		1,135			(4,044		)	4,044			1,135
Net cash provided by financing activities	211,633			—		28,173			(4,044		)	(22,994		)	212,768
Net increase in cash and cash equivalents	7			—		2,060			(1,602		)	—			465
Cash and cash equivalents at beginning of period	3			—		9,043			1,771			—			10,817
Cash and cash equivalents at end of period	$	10		$	—	$	11,103		$	169		$	—		$	11,282

44