Genesis Energy L.P. - 10-Q quarterly report FY2017 Q2

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)



Delaware	76-0513049
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

919 Milam, Suite 2100, Houston, TX	77002
(Address of principal executive offices)	(Zip code)
Registrant’s telephone number, including area code: (713) 860-2500

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)		Smaller reporting company ¨
		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act). Yes ¨ No ý

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding as of August 2, 2017.

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GENESIS ENERGY, L.P.

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		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Partners’ Capital	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
	1. Organization and Basis of Presentation and Consolidation	7
	2. Recent Accounting Developments	7
	3. Inventories	8
	4. Fixed Assets	9
	5. Equity Investees	10
	6. Intangible Assets	12
	7. Debt	13
	8. Partners' Capital and Distributions	13
	9. Business Segment Information	14
	10. Transactions with Related Parties	16
	11. Supplemental Cash Flow Information	17
	12. Derivatives	17
	13. Fair-Value Measurements	20
	14. Commitments and Contingencies	21
	15. Subsequent Events	22
	16. Condensed Consolidating Financial Information	22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	50
Item 4.	Controls and Procedures	50
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults upon Senior Securities	52
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	52
Item 6.	Exhibits	53
SIGNATURES		54

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)



	June 30, 2017			December 31, 2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,077		$	7,029
Accounts receivable - trade, net	217,834			224,682
Inventories	68,787			98,587
Other	31,012			29,271
Total current assets	327,710			359,569
FIXED ASSETS, at cost	4,843,007			4,763,396
Less: Accumulated depreciation	(629,193		)	(548,532		)
Net fixed assets	4,213,814			4,214,864
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	129,164			132,859
EQUITY INVESTEES	390,326			408,756
INTANGIBLE ASSETS, net of amortization	193,389			204,887
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	60,927			56,611
TOTAL ASSETS	$	5,640,376		$	5,702,592
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	117,100		$	119,841
Accrued liabilities	120,096			140,962
Total current liabilities	237,196			260,803
SENIOR SECURED CREDIT FACILITY	1,211,000			1,278,200
SENIOR UNSECURED NOTES, net of debt issuance costs	1,816,259			1,813,169
DEFERRED TAX LIABILITIES	26,249			25,889
OTHER LONG-TERM LIABILITIES	199,835			204,481
PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 117,979,218 units issued and outstanding at June 30, 2017 and December 31, 2016, respectively	2,159,698			2,130,331
Noncontrolling interests	(9,861		)	(10,281		)
Total partners' capital	2,149,837			2,120,050
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	5,640,376		$	5,702,592

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
REVENUES:
Offshore pipeline transportation services	77,638			78,994			162,766			155,120
Refinery services	43,068			41,324			88,114			83,860
Marine transportation	53,202			52,609			103,504			104,645
Onshore facilities and transportation	232,815			273,049			467,830			480,765
Total revenues	406,723			445,976			822,214			824,390
COSTS AND EXPENSES:
Onshore facilities and transportation product costs	188,395			227,998			380,488			390,391
Onshore facilities and transportation operating costs	33,939			24,122			56,178			49,498
Marine transportation operating costs	38,949			34,430			76,191			67,452
Refinery services operating costs	26,606			21,579			53,970			42,564
Offshore pipeline transportation operating costs	18,124			22,676			35,992			40,610
General and administrative	9,338			11,283			19,314			23,504
Depreciation and amortization	56,609			55,900			112,721			102,535
Gain on sale of assets	(26,684		)	—			(26,684		)	—
Total costs and expenses	345,276			397,988			708,170			716,554
OPERATING INCOME	61,447			47,988			114,044			107,836
Equity in earnings of equity investees	10,426			12,157			21,761			22,874
Interest expense	(37,990		)	(35,535		)	(74,729		)	(69,922		)
Income before income taxes	33,883			24,610			61,076			60,788
Income tax expense	(303		)	(1,009		)	(558		)	(2,010		)
NET INCOME	33,580			23,601			60,518			58,778
Net loss attributable to noncontrolling interests	153			126			305			252
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	33,733		$	23,727		$	60,823		$	59,030
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.28		$	0.22		$	0.50		$	0.54
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	122,579			109,979			120,495			109,979

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Total
Partners’ capital, January 1, 2017	117,979	$	2,130,331		$	(10,281	)	$	2,120,050
Net income (loss)	—	60,823			(305		)	60,518
Cash distributions to partners	—	(171,993		)	—			(171,993		)
Cash contributions from noncontrolling interests	—	—			725			725
Issuance of common units for cash, net	4,600	140,537			—			140,537
Partners' capital, June 30, 2017	122,579	$	2,159,698		$	(9,861	)	$	2,149,837
	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Total
Partners’ capital, January 1, 2016	109,979	$	2,029,101		$	(8,350	)	$	2,020,751
Net income	—	59,030			(252		)	58,778
Cash distributions to partners	—	(146,048		)	—			(146,048		)
Partners' capital, June 30, 2016	109,979	$	1,942,083		$	(8,602	)	$	1,933,481

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Six Months Ended June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	60,518		$	58,778
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	112,721			102,535
Provision for leased items no longer in use	12,589			—
Gain on sale of assets	(26,684		)	—
Amortization of debt issuance costs and discount	5,260			4,992
Amortization of unearned income and initial direct costs on direct financing leases	(6,958		)	(7,274		)
Payments received under direct financing leases	10,334			10,333
Equity in earnings of investments in equity investees	(21,761		)	(22,874		)
Cash distributions of earnings of equity investees	29,868			32,778
Non-cash effect of equity-based compensation plans	(1,457		)	4,255
Deferred and other tax liabilities	358			1,409
Unrealized loss on derivative transactions	561			1,313
Other, net	292			7,668
Net changes in components of operating assets and liabilities (Note 11)	8,313			(90,241		)
Net cash provided by operating activities	183,954			103,672
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(126,580		)	(247,416		)
Cash distributions received from equity investees - return of investment	10,323			11,851
Investments in equity investees	—			(1,135		)
Acquisitions	(759		)	(25,394		)
Contributions in aid of construction costs	124			8,940
Proceeds from asset sales	38,237			3,183
Other, net	—			107
Net cash used in investing activities	(78,655		)	(249,864		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	410,700			631,900
Repayments on senior secured credit facility	(477,900		)	(341,100		)
Debt issuance costs	(7,536		)	(1,539		)
Issuance of common units for cash, net	140,537			—
Contributions from noncontrolling interests	725			—
Distributions to common unitholders	(171,993		)	(146,021		)
Other, net	3,216			607
Net cash provided by (used in) financing activities	(102,251		)	143,847
Net increase (decrease) in cash and cash equivalents	3,048			(2,345		)
Cash and cash equivalents at beginning of period	7,029			10,895
Cash and cash equivalents at end of period	$	10,077		$	8,550

The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States, Wyoming and the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. We 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.

As a result of the above changes, we currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, refinery services, marine transportation, and onshore facilities and transportation. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

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


•	Offshore pipeline transportation and processing of crude oil and natural gas 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


•	Onshore facilities and transportation, which include terminaling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO₂.

Basis of Presentation and Consolidation

The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries, including our general partner, Genesis Energy, LLC.

Our results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The Condensed Consolidated Financial Statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the Consolidated Financial Statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016.

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.

2. Recent Accounting Developments

Recently Issued

In May 2014, the 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

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five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective transition method. In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved early adoption of the standard, but not before the original effective date of December 15, 2016. Our process of evaluating the impact of this guidance on each type of revenue contract entered into with customers is ongoing, but nearing completion. This process includes regular involvement from our implementation team in determining any significant impact on accounting treatment, processes, internal controls, and disclosures. While we do not believe there will be a material impact to our revenues upon adoption based on our preliminary assessment, we continue to evaluate the impacts of our pending adoption of this guidance until finalized conclusions are determined and we are still in the process of confirming which transition method to apply. We plan to confirm the transition method in the third quarter of 2017.

In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost or net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements.

In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this guidance.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

3. Inventories

The major components of inventories were as follows:



	June 30, 2017		December 31, 2016
Petroleum products	$	11,703	$	11,550
Crude oil	41,816		73,133
Caustic soda	5,723		4,593
NaHS	9,524		9,304
Other	21		7
Total	$	68,787	$	98,587

Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were below recorded costs by approximately $0.1 million as of June 30, 2017 without similar adjustments required as of December 31, 2016; therefore we reduced the value of inventory in our Condensed Consolidated Financial Statements for this difference in 2017.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	June 30, 2017			December 31, 2016
Crude oil pipelines and natural gas pipelines and related assets	$	2,984,884		$	2,901,202
Onshore facilities, machinery, and equipment	762,610			427,658
Transportation equipment	17,857			17,543
Marine vessels	866,584			863,199
Land, buildings and improvements	102,841			55,712
Office equipment, furniture and fixtures	9,681			9,654
Construction in progress	42,882			440,225
Other	55,668			48,203
Fixed assets, at cost	4,843,007			4,763,396
Less: Accumulated depreciation	(629,193		)	(548,532		)
Net fixed assets	$	4,213,814		$	4,214,864

Our depreciation expense for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Depreciation expense	$	50,397	$	48,807	$	100,321	$	88,519

During the period ending June 30, 2017, we sold certain non-core natural gas gathering and platform assets in the Gulf of Mexico that resulted in a gain of $26.7 million.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations.

The following table presents information regarding our AROs since December 31, 2016:



ARO liability balance, December 31, 2016	$	213,726
Accretion expense	5,581
Change in estimate	729
Divestitures	(7,649		)
Settlements	(12,553		)
Other	240
ARO liability balance, June 30, 2017	$	200,074

Of the ARO balances disclosed above, $20.1 million and $22.4 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of June 30, 2017 and December 31, 2016, respectively. The remainder of the ARO liability as of June 30, 2017 and December 31, 2016 is included in "Other long-term liabilities" on our Unaudited Condensed Consolidated Balance Sheet.

With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated:



Remainder of	2017	$	5,553
	2018	$	9,393
	2019	$	8,627
	2020	$	9,209
	2021	$	9,830

Certain of our unconsolidated affiliates have AROs recorded at June 30, 2017 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.

5. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed or be less than 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 June 30, 2017 and December 31, 2016, the unamortized excess cost amounts totaled $390.3 million and $398.1 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 Unaudited Condensed Consolidated Financial Statements related to our equity investees.



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Genesis’ share of operating earnings	$	14,368		$	16,139		$	29,645		$	30,837
Amortization of excess purchase price	(3,942		)	(3,982		)	(7,884		)	(7,963		)
Net equity in earnings	$	10,426		$	12,157		$	21,761		$	22,874
Distributions received	$	19,566		$	23,298		$	40,191		$	44,629

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables present the unaudited balance sheet and income statement information (on a 100% basis) for Poseidon Oil Pipeline Company (which is our most significant equity investment):



	June 30, 2017			December 31, 2016
BALANCE SHEET DATA:
Assets
Current assets	$	16,907		$	17,111
Fixed assets, net	224,996			232,736
Other assets	1,287			861
Total assets	$	243,190		$	250,708
Liabilities and equity
Current liabilities	$	20,876		$	20,727
Other liabilities	227,762			219,644
Equity	(5,448		)	10,337
Total liabilities and equity	$	243,190		$	250,708



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
INCOME STATEMENT DATA:
Revenues	$	28,501	$	31,010	$	57,406	$	59,439
Operating income	$	20,038	$	23,527	$	40,825	$	45,059
Net income	$	18,580	$	22,385	$	38,015	$	42,749

Poseidon's revolving credit facility

Borrowings under Poseidon’s revolving credit facilities, which was amended and restated in February 2015, are primarily used to fund spending on capital projects. The February 2015 credit facility is non-recourse to Poseidon’s owners and secured by substantially all of Poseidon's assets. The February 2015 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these Unaudited Combined Financial Statements.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. Intangible Assets

The following table summarizes the components of our intangible assets at the dates indicated:



	June 30, 2017						December 31, 2016
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	91,125	$	3,529	$	94,654	$	89,756	$	4,898
Licensing agreements	38,678		35,366		3,312		38,678		34,204		4,474
Segment total	133,332		126,491		6,841		133,332		123,960		9,372
Onshore Facilities & Transportation:
Customer relationships	35,430		34,379		1,051		35,430		33,676		1,754
Intangibles associated with lease	13,260		4,696		8,564		13,260		4,459		8,801
Segment total	48,690		39,075		9,615		48,690		38,135		10,555
Marine contract intangibles	27,000		9,000		18,000		27,000		6,300		20,700
Offshore pipeline contract intangibles	158,101		15,949		142,152		158,101		11,788		146,313
Other	28,816		12,035		16,781		28,569		10,622		17,947
Total	$	395,939	$	202,550	$	193,389	$	395,692	$	190,805	$	204,887

Our amortization of intangible assets for the periods presented was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Amortization of intangible assets	$	5,872	$	6,040	$	11,744	$	12,032

We estimate that our amortization expense for the next five years will be as follows:



Remainder of	2017	$	11,842
	2018	$	21,513
	2019	$	17,178
	2020	$	16,241
	2021	$	10,634

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Debt

Our obligations under debt arrangements consisted of the following:



	June 30, 2017						December 31, 2016
	Principal		Unamortized Discount and Debt Issuance Costs		Net Value		Principal		Unamortized Discount and Debt Issuance Costs		Net Value
Senior secured credit facility	$	1,211,000	$	—	$	1,211,000	$	1,278,200	$	—	$	1,278,200
6.000% senior unsecured notes due May 2023	400,000		6,224		393,776		400,000		6,758		393,242
5.750% senior unsecured notes due February 2021	350,000		3,653		346,347		350,000		4,163		345,837
5.625% senior unsecured notes due June 2024	350,000		6,165		343,835		350,000		6,614		343,386
6.750% senior unsecured notes due August 2022	750,000		17,699		732,301		750,000		19,296		730,704
Total long-term debt	$	3,061,000	$	33,741	$	3,027,259	$	3,128,200	$	36,831	$	3,091,369

As of June 30, 2017, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Senior Secured Credit Facility

In May 2017, we amended our credit agreement to, among other things, (i) extend the maturity date of the credit facility to May 9, 2022 (provided, that if Genesis does not refinance or repay in full its 5.750% senior notes due 2021 on or prior to November 15, 2020, the maturity date will be November 15, 2020), (ii) change the maximum consolidated leverage ratio to 5.75 to 1.0 for the second quarter of 2017 through the second quarter of 2018, 5.50 to 1.0 for the third quarter of 2018 through the fourth quarter of 2019, 5.25 to 1.0 for the first quarter of 2020 through the fourth quarter of 2020 and 5.00 to 1.0 from the first quarter of 2021 and all periods thereafter, and (iii) add an additional level to the leverage-based pricing grid used to calculate the applicable margin for base rate loans and LIBOR loans to account for changes to the maximum consolidated leverage ratio.

The key terms for rates under our $1.7 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:

•The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings.

•Letter of credit fees range from 1.50% to 3.00%

•The commitment fee on the unused committed amount will range from 0.25% to 0.50%.

•The accordion feature is $300.0 million, giving us the ability to expand the size of the facility up to $2.0 billion for acquisitions or growth projects, subject to lender consent.

At June 30, 2017, we had $1.2 billion borrowed under our $1.7 billion credit facility, with $47.6 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100.0 million of the capacity to be used for letters of credit, of which $1.0 million was outstanding at June 30, 2017. 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. The total amount available for borrowings under our credit facility at June 30, 2017 was $488.0 million.

8. Partners’ Capital and Distributions

At June 30, 2017, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units.

On March 24, 2017, we issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of offering costs, of approximately $140.5 million from that offering.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Distributions

We paid or will pay the following distributions in 2016 and 2017:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2016
1^st Quarter	May 13, 2016		$	0.6725	$	73,961
2^nd Quarter	August 12, 2016		$	0.6900	$	81,406
3^rd Quarter	November 14, 2016		$	0.7000	$	82,585
4^th Quarter	February 14, 2017		$	0.7100	$	83,765
2017
1^st Quarter	May 15, 2017		$	0.7200	$	88,257
2^nd Quarter	August 14, 2017	⁽¹⁾	$	0.7225	$	88,563

(1) This distribution will be paid to unitholders of record as of July 31, 2017.

9. Business Segment Information

In the fourth quarter of 2016, we reorganized our operating segments as a result of 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 onshore pipeline transportation segment, formerly reported under its own segment, are now reported in our onshore facilities and transportation segment. The onshore facilities and transportation segment was formerly named our supply and logistics segment. This segment has been renamed in the second quarter of 2017 to more accurately describe the nature of its operations. This change is consistent with the increasingly integrated nature of our onshore operations. As a result of the above changes, we currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, refinery services, marine transportation, and onshore facilities and transportation. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

We currently manage our businesses through four divisions that constitute our reportable segments:


•	Offshore pipeline transportation – offshore pipeline transportation and processing of crude oil and natural gas 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;


•	Marine transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; and


•	Onshore facilities and transportation – terminaling, blending, storing, marketing and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and 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 gains and 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the periods presented below was as follows:



	Offshore Pipeline Transportation			Refinery Services			Marine Transportation		Onshore Facilities & Transportation			Total
Three Months Ended June 30, 2017
Segment margin (a)	$	78,211		$	16,337		$	14,156	$	25,296		$	134,000
Capital expenditures (b)	$	3,903		$	432		$	11,132	$	42,383		$	57,850
Revenues:
External customers	$	78,577		$	45,210		$	49,311	$	233,625		$	406,723
Intersegment (c)	(939		)	(2,142		)	3,891		(810		)	—
Total revenues of reportable segments	$	77,638		$	43,068		$	53,202	$	232,815		$	406,723
Three Months Ended June 30 2016
Segment margin (a)	$	84,282		$	19,861		$	18,082	$	20,261		$	142,486
Capital expenditures (b)	$	2,373		$	832		$	27,562	$	84,754		$	115,521
Revenues:
External customers	$	76,829		$	43,618		$	50,964	$	274,565		$	445,976
Intersegment (c)	2,165			(2,294		)	1,645		(1,516		)	—
Total revenues of reportable segments	$	78,994		$	41,324		$	52,609	$	273,049		$	445,976
Six Months Ended June 30, 2017
Segment Margin (a)	$	165,300		$	33,833		$	27,119	$	46,393		$	272,645
Capital expenditures (b)	$	6,142		$	945		$	20,665	$	89,085		$	116,837
Revenues:
External customers	$	163,982		$	92,481		$	97,515	$	468,236		$	822,214
Intersegment (c)	(1,216		)	(4,367		)	5,989		(406		)	—
Total revenues of reportable segments	$	162,766		$	88,114		$	103,504	$	467,830		$	822,214
Six Months Ended June 30, 2016
Segment Margin (a)	$	162,900		$	41,060		$	36,998	$	46,409		$	287,367
Capital expenditures (b)	$	31,198		$	1,157		$	35,991	$	173,333		$	241,679
Revenues:
External customers	$	152,955		$	88,368		$	101,624	$	481,443		$	824,390
Intersegment (c)	2,165			(4,508		)	3,021		(678		)	—
Total revenues of reportable segments	$	155,120		$	83,860		$	104,645	$	480,765		$	824,390

Total assets by reportable segment were as follows:



	June 30, 2017		December 31, 2016
Offshore pipeline transportation	$	2,514,688	$	2,575,335
Refinery services	391,208		395,043
Marine transportation	798,835		813,722
Onshore facilities and transportation	1,878,944		1,875,403
Other assets	56,701		43,089
Total consolidated assets	5,640,376		5,702,592


(a)	A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for the periods is presented below.


(b)	Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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

Reconciliation of total Segment Margin to net income:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Total Segment Margin	$	134,000		$	142,486		$	272,645		$	287,367
Corporate general and administrative expenses	(7,137		)	(10,491		)	(15,464		)	(21,849		)
Depreciation, amortization and accretion	(59,382		)	(62,213		)	(117,777		)	(111,388		)
Interest expense	(37,990		)	(35,535		)	(74,729		)	(69,922		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(9,140		)	(11,141		)	(18,430		)	(21,755		)
Non-cash items not included in Segment Margin	(1,867		)	15			(1,430		)	(4,359		)
Cash payments from direct financing leases in excess of earnings	(1,709		)	(1,548		)	(3,376		)	(3,059		)
Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾	3,166			3,163			5,847			6,005
Gain on sale of assets	26,684			—			26,684			—
Non-cash provision for leased items no longer in use	(12,589		)	—			(12,589		)	—
Income tax expense	(303		)	(1,009		)	(558		)	(2,010		)
Net income attributable to Genesis Energy, L.P.	$	33,733		$	23,727		$	60,823		$	59,030


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


(2)	Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

10. 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:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	726	$	762	$	1,403	$	1,488
Revenues from services and fees to Poseidon Oil Pipeline Company, LLC ⁽²⁾	3,044		1,980		6,066		3,956
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	330	$	330
Charges for services from Poseidon Oil Pipeline Company, LLC ⁽²⁾	249		251		490		498


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


(2)	We own 64% interest in Poseidon Oil Pipeline Company, LLC.

Amount due from Related Party

At June 30, 2017 and December 31, 2016 (i) Sandhill Group, LLC owed us $0.2 million and $0.2 million, respectively, for purchases of CO₂ and (ii) Poseidon Oil Pipeline Company, LLC owed us $1.9 million and $1.6 million, respectively, for services rendered.

Transactions with Unconsolidated Affiliates

Poseidon

We are the operator of Poseidon and provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

by either party (as defined in the agreement). Our revenues for the three and six months ended June 30, 2017 reflect the $2.1 million and $4.2 million, respectively, of fees we earned through the provision of services under that agreement.

11. Supplemental Cash Flow Information

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



	Six Months Ended June 30,
	2017			2016
(Increase) decrease in:
Accounts receivable	$	3,666		$	(21,274	)
Inventories	29,800			(34,512		)
Deferred charges	(93		)	(6,272		)
Other current assets	(2,115		)	(4,335		)
Decrease in:
Accounts payable	(6,843		)	(5,642		)
Accrued liabilities	(16,102		)	(18,206		)
Net changes in components of operating assets and liabilities	8,313			(90,241		)

Payments of interest and commitment fees were $80.0 million and $78.4 million for the six months ended June 30, 2017 and June 30, 2016, respectively. We capitalized interest of $11.9 million and $12.3 million during the six months ended June 30, 2017 and June 30, 2016.

At June 30, 2017 and June 30, 2016, we had incurred liabilities for fixed and intangible asset additions totaling $23.2 million and $55.6 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

12. 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.

We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Unaudited Consolidated Statements of Operations.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Unaudited Consolidated Balance Sheets.

At June 30, 2017, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments.



	Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	833		—
Weighted average contract price per bbl	$	46.73	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	417		399
Weighted average contract price per bbl	$	45.01	$	45.82
NYM RBOB Gas futures:
Contract volumes (42,000 gallons)	2		2
Weighted average contract price per gal	$	1.51	$	1.42
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	235		55
Weighted average contract price per bbl	$	41.96	$	42.38
Crude oil options:
Contract volumes (1,000 bbls)	115		60
Weighted average premium received	$	1.16	$	0.48
NYM RBOB Gas options:
Contract volumes (42,000 gallons)	5		—
Weighted average premium received	$	0.02	$	—

Financial Statement Impacts

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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at June 30, 2017 and December 31, 2016:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	June 30, 2017			December 31, 2016
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	477		$	443
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(477		)	(443		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Current Assets - Other	$	1,431		$	3,321
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(931		)	(3,321		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	500		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,267	)	$	(1,772	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,267			1,772
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(931	)	$	(9,506	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	931			7,589
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	(1,917	)


(1)	These derivative liabilities have been funded with margin deposits recorded in our Unaudited Condensed Consolidated Balance Sheets under Current Assets - Other.

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 June 30, 2017, we had a net broker receivable of approximately $1.4 million (consisting of initial margin of $2.6 million decreased by $1.2 million of variation margin). As of December 31, 2016, we had a net broker receivable of approximately $5.6 million (consisting of initial margin of $5.1 million increased by $0.5 million of variation margin). At June 30, 2017 and December 31, 2016, 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended June 30,					Six Months Ended June 30,
		2017		2016			2017		2016
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs	$	5,546	$	(9,398	)	$	11,832	$	(9,951	)
Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs	886		(3,145		)	1,979		(3,482		)
Total commodity derivatives		$	6,432	$	(12,543	)	$	13,811	$	(13,433	)

13. 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 June 30, 2017 and December 31, 2016.



	Fair Value at							Fair Value at
	June 30, 2017							December 31, 2016
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	1,908		$	—	$	—	$	3,764		$	—	$	—
Liabilities	$	(2,198	)	$	—	$	—	$	(11,278	)	$	—	$	—

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 12 for additional information on our derivative instruments.

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 June 30, 2017 our senior unsecured notes had a carrying value of $1.8 billion and a fair value of $1.8 billion, respectively, compared to $1.8 billion and $1.9 billion, respectively, at December 31, 2016. 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Commitments and Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to aid in monitoring compliance and detecting and addressing 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.

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.

In the 2017 Quarter, we recorded a non-cash provision of $12.6 million (included within Onshore facilities and transportation operating costs in our Unaudited Condensed Consolidated Statements of Operations) relating to certain leased railcars no longer in use. Of this amount, $4.1 million is considered current and included in accrued liabilities in our Unaudited Condensed Consolidated Balance Sheet, with the remainder included in other long-term liabilities.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

15. Subsequent Events

On August 2, 2017, we entered into a stock purchase agreement with a subsidiary of Tronox Limited (“Tronox”) pursuant to which we will acquire for approximately $1.325 billion in cash all of Tronox’s trona and trona-based exploring, mining, processing, producing, marketing and selling business. The business holds leases covering acres of land containing proved and probable reserves of trona ore, a soda ash production facility, underground trona ore mines and solution mining operations and related equipment, logistics and other assets.

We currently expect to fund the acquisition price and related transaction costs with proceeds from a notes offering, a preferred units offering and/or borrowings under our $1.7 billion revolving credit facility, as well as cash on hand. We expect to close the acquisition in the second half of 2017.

16. Condensed Consolidating Financial Information

Our $1.8 billion 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 7 for additional information regarding our consolidated debt obligations.

The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

June 30, 2017



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	6	$	—	$	9,595		$	476		$	—		$	10,077
Other current assets	100		—		305,676			12,178			(321		)	317,633
Total current assets	106		—		315,271			12,654			(321		)	327,710
Fixed assets, at cost	—		—		4,765,422			77,585			—			4,843,007
Less: Accumulated depreciation	—		—		(603,726		)	(25,467		)	—			(629,193		)
Net fixed assets	—		—		4,161,696			52,118			—			4,213,814
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	16,060		—		384,724			130,265			(147,569		)	383,480
Advances to affiliates	2,507,192		—		—			81,991			(2,589,183		)	—
Equity investees	—		—		390,326			—			—			390,326
Investments in subsidiaries	2,698,899		—		80,505			—			(2,779,404		)	—
Total assets	$	5,222,257	$	—	$	5,657,568		$	277,028		$	(5,516,477	)	$	5,640,376
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	35,300	$	—	$	187,009		$	15,040		$	(153	)	$	237,196
Senior secured credit facility	1,211,000		—		—			—			—			1,211,000
Senior unsecured notes	1,816,259		—		—			—			—			1,816,259
Deferred tax liabilities	—		—		26,249			—			—			26,249
Advances from affiliates	—		—		2,589,189			—			(2,589,189		)	—
Other liabilities	—		—		164,414			182,839			(147,418		)	199,835
Total liabilities	3,062,559		—		2,966,861			197,879			(2,736,760		)	3,490,539
Partners’ capital, common units	2,159,698		—		2,690,707			89,010			(2,779,717		)	2,159,698
Noncontrolling interests	—		—		—			(9,861		)	—			(9,861		)
Total liabilities and partners’ capital	$	5,222,257	$	—	$	5,657,568		$	277,028		$	(5,516,477	)	$	5,640,376

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2016



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	6	$	—	$	6,360		$	663		$	—		$	7,029
Other current assets	50		—		340,555			12,237			(302		)	352,540
Total current assets	56		—		346,915			12,900			(302		)	359,569
Fixed assets, at cost	—		—		4,685,811			77,585			—			4,763,396
Less: Accumulated depreciation	—		—		(524,315		)	(24,217		)	—			(548,532		)
Net fixed assets	—		—		4,161,496			53,368			—			4,214,864
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	10,696		—		390,214			133,980			(140,533		)	394,357
Advances to affiliates	2,650,930		—		—			73,295			(2,724,225		)	—
Equity investees	—		—		408,756			—			—			408,756
Investments in subsidiaries	2,594,882		—		80,735			—			(2,675,617		)	—
Total assets	$	5,256,564	$	—	$	5,713,162		$	273,543		$	(5,540,677	)	$	5,702,592
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	34,864	$	—	$	211,591		$	14,505		$	(157	)	$	260,803
Senior secured credit facility	1,278,200		—		—			—			—			1,278,200
Senior unsecured notes	1,813,169		—		—			—			—			1,813,169
Deferred tax liabilities	—		—		25,889			—			—			25,889
Advances from affiliates	—		—		2,724,224			—			(2,724,224		)	—
Other liabilities	—		—		165,266			179,592			(140,377		)	204,481
Total liabilities	3,126,233		—		3,126,970			194,097			(2,864,758		)	3,582,542
Partners’ capital, common units	2,130,331		—		2,586,192			89,727			(2,675,919		)	2,130,331
Noncontrolling interests	—		—		—			(10,281		)	—			(10,281		)
Total liabilities and partners’ capital	$	5,256,564	$	—	$	5,713,162		$	273,543		$	(5,540,677	)	$	5,702,592

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2017



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	77,638		$	—		$	—		$	77,638
Refinery services	—			—		42,995			2,089			(2,016		)	43,068
Marine transportation	—			—		53,202			—			—			53,202
Onshore facilities and transportation	—			—		228,291			4,524			—			232,815
Total revenues	—			—		402,126			6,613			(2,016		)	406,723
COSTS AND EXPENSES:
Onshore facilities and transportation	—			—		222,055			279			—			222,334
Marine transportation costs	—			—		38,949			—			—			38,949
Refinery services operating costs	—			—		26,586			2,036			(2,016		)	26,606
Offshore pipeline transportation operating costs	—			—		17,362			762			—			18,124
General and administrative	—			—		9,338			—			—			9,338
Depreciation and amortization	—			—		55,984			625			—			56,609
Gain on sale of assets	—			—		(26,684		)	—			—			(26,684		)
Total costs and expenses	—			—		343,590			3,702			(2,016		)	345,276
OPERATING INCOME	—			—		58,536			2,911			—			61,447
Equity in earnings of subsidiaries	71,691			—		(395		)	—			(71,296		)	—
Equity in earnings of equity investees	—			—		10,426			—			—			10,426
Interest (expense) income, net	(37,958		)	—		3,466			(3,498		)	—			(37,990		)
Income before income taxes	33,733			—		72,033			(587		)	(71,296		)	33,883
Income tax benefit (expense)	—			—		(303		)	—			—			(303		)
NET INCOME	33,733			—		71,730			(587		)	(71,296		)	33,580
Net loss attributable to noncontrolling interest	—			—		—			153			—			153
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	33,733		$	—	$	71,730		$	(434	)	$	(71,296	)	$	33,733

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended June 30 2016



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	78,994					$	—		$	78,994
Refinery services	—			—		42,115			1,715			(2,506		)	41,324
Marine transportation	—			—		52,609			—			—			52,609
Onshore facilities and transportation	—			—		268,063			4,986			—			273,049
Total revenues	—			—		441,781			6,701			(2,506		)	445,976
COSTS AND EXPENSES:
Onshore facilities and transportation costs	—			—		251,840			280			—			252,120
Marine transportation costs	—			—		34,430			—			—			34,430
Refinery services operating costs	—			—		22,167			1,918			(2,506		)	21,579
Offshore pipeline transportation operating costs	—			—		22,044			632			—			22,676
General and administrative	—			—		11,283			—			—			11,283
Depreciation and amortization	—			—		55,275			625			—			55,900
Total costs and expenses	—			—		397,039			3,455			(2,506		)	397,988
OPERATING INCOME	—			—		44,742			3,246			—			47,988
Equity in earnings of subsidiaries	60,205			—		(156		)	—			(60,049		)	—
Equity in earnings of equity investees	—			—		12,157			—			—			12,157
Interest (expense) income, net	(35,508		)	—		3,632			(3,659		)	—			(35,535		)
Income before income taxes	24,697			—		60,375			(413		)	(60,049		)	24,610
Income tax expense	—			—		(1,097		)	88			—			(1,009		)
NET INCOME	24,697			—		59,278			(325		)	(60,049		)	23,601
Net loss attributable to noncontrolling interest	—			—		—			126			—			126
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	24,697		$	—	$	59,278		$	(199	)	$	(60,049	)	$	23,727

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2017



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	162,766		$	—		$	—		$	162,766
Refinery services	—			—		88,029			3,899			(3,814		)	88,114
Marine transportation	—			—		103,504			—			—			103,504
Onshore facilities and transportation	—			—		458,361			9,469			—			467,830
Total revenues	—			—		812,660			13,368			(3,814		)	822,214
COSTS AND EXPENSES:
Onshore facilities and transportation costs	—			—		436,126			540			—			436,666
Marine transportation costs	—			—		76,191			—			—			76,191
Refinery services operating costs	—			—		53,739			4,045			(3,814		)	53,970
Offshore pipeline transportation operating costs	—			—		34,468			1,524			—			35,992
General and administrative	—			—		19,314			—			—			19,314
Depreciation and amortization	—			—		111,471			1,250			—			112,721
Gain on sale of assets	—			—		(26,684		)	—			—			(26,684		)
Total costs and expenses	—			—		704,625			7,359			(3,814		)	708,170
OPERATING INCOME	—			—		108,035			6,009			—			114,044
Equity in earnings of subsidiaries	135,500			—		(645		)	—			(134,855		)	—
Equity in earnings of equity investees	—			—		21,761			—			—			21,761
Interest (expense) income, net	(74,677		)	—		6,986			(7,038		)	—			(74,729		)
Income before income taxes	60,823			—		136,137			(1,029		)	(134,855		)	61,076
Income tax expense	—			—		(558		)	—			—			(558		)
NET INCOME	60,823			—		135,579			(1,029		)	(134,855		)	60,518
Net loss attributable to noncontrolling interest	—			—		—			305			—			305
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	60,823		$	—	$	135,579		$	(724	)	$	(134,855	)	$	60,823

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2016



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	155,120					$	—		$	155,120
Refinery services	—			—		84,409			2,518			(3,067		)	83,860
Marine transportation	—			—		104,645			—			—			104,645
Onshore facilities and transportation	—			—		470,234			10,531			—			480,765
Total revenues	—			—		814,408			13,049			(3,067		)	824,390
COSTS AND EXPENSES:
Onshore facilities and transportation costs	—			—		439,313			576			—			439,889
Marine transportation costs	—			—		67,452			—			—			67,452
Refinery services operating costs	—			—		42,613			3,018			(3,067		)	42,564
Offshore pipeline transportation operating costs	—			—		39,349			1,261			—			40,610
General and administrative	—			—		23,504			—			—			23,504
Depreciation and amortization	—			—		101,285			1,250			—			102,535
Total costs and expenses	—			—		713,516			6,105			(3,067		)	716,554
OPERATING INCOME	—			—		100,892			6,944			—			107,836
Equity in earnings of subsidiaries	128,863			—		(78		)	—			(128,785		)	—
Equity in earnings of equity investees	—			—		22,874			—			—			22,874
Interest (expense) income, net	(69,833		)	—		7,266			(7,355		)	—			(69,922		)
Income before income taxes	59,030			—		130,954			(411		)	(128,785		)	60,788
Income tax (expense) benefit	—			—		(2,007		)	(3		)	—			(2,010		)
NET INCOME	59,030			—		128,947			(414		)	(128,785		)	58,778
Net loss attributable to noncontrolling interest	—			—		—			252			—			252
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	59,030		$	—	$	128,947		$	(162	)	$	(128,785	)	$	59,030

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2017



	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 provided by operating activities	$	102,991		$	—	$	242,004		$	646		$	(161,687	)	$	183,954
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(126,580		)	—			—			(126,580		)
Cash distributions received from equity investees - return of investment	—			—		10,323			—			—			10,323
Investments in equity investees	(140,537		)	—		—			—			140,537			—
Acquisitions	—			—		(759		)	—			—			(759		)
Intercompany transfers	143,738			—		—			—			(143,738		)	—
Repayments on loan to non-guarantor subsidiary	—			—		3,296			—			(3,296		)	—
Contributions in aid of construction costs	—			—		124			—			—			124
Proceeds from asset sales	—			—		38,237			—			—			38,237
Other, net	—			—		—			—			—			—
Net cash used in investing activities	3,201			—		(75,359		)	—			(6,497		)	(78,655		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	410,700			—		—			—			—			410,700
Repayments on senior secured credit facility	(477,900		)	—		—			—			—			(477,900		)
Debt issuance costs	(7,536		)	—		—			—			—			(7,536		)
Intercompany transfers	—			—		(135,170		)	(8,568		)	143,738			—
Issuance of common units for cash, net	140,537			—		140,537			—			(140,537		)	140,537
Distributions to common unitholders	(171,993		)	—		(171,993		)	—			171,993			(171,993		)
Contributions from noncontrolling interest	—			—		—			725			—			725
Other, net	—			—		3,216			7,010			(7,010		)	3,216
Net cash used in financing activities	(106,192		)	—		(163,410		)	(833		)	168,184			(102,251		)
Net increase in cash and cash equivalents	—			—		3,235			(187		)	—			3,048
Cash and cash equivalents at beginning of period	6			—		6,360			663			—			7,029
Cash and cash equivalents at end of period	$	6		$	—	$	9,595		$	476		$	—		$	10,077

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2016



	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 provided by operating activities	$	80,297		$	—	$	154,169		$	4,918		$	(135,712	)	$	103,672
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(247,416		)	—			—			(247,416		)
Cash distributions received from equity investees - return of investment	—			—		11,851			—			—			11,851
Investments in equity investees	—			—		(1,135		)	—			—			(1,135		)
Acquisitions	—			—		(25,394		)	—			—			(25,394		)
Intercompany transfers	(223,537		)	—		—			—			223,537			—
Repayments on loan to non-guarantor subsidiary	—			—		2,979			—			(2,979		)	—
Contributions in aid of construction costs	—			—		8,940			—			—			8,940
Proceeds from asset sales	—			—		3,183			—			—			3,183
Other, net	—			—		107			—			—			107
Net cash used in investing activities	(223,537		)	—		(246,885		)	—			220,558			(249,864		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	631,900			—		—			—			—			631,900
Repayments on senior secured credit facility	(341,100		)	—		—			—			—			(341,100		)
Debt issuance costs	(1,539		)	—		—			—			—			(1,539		)
Intercompany transfers	—			—		236,775			(13,238		)	(223,537		)	—
Distributions to common unitholders	(146,021		)	—		(146,021		)	—			146,021			(146,021		)
Other, net	—			—		607			7,330			(7,330		)	607
Net cash provided by financing activities	143,240			—		91,361			(5,908		)	(84,846		)	143,847
Net decrease in cash and cash equivalents	—			—		(1,355		)	(990		)	—			(2,345		)
Cash and cash equivalents at beginning of period	6			—		8,288			2,601			—			10,895
Cash and cash equivalents at end of period	$	6		$	—	$	6,933		$	1,611		$	—		$	8,550

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K for the year ended December 31, 2016.

Included in Management’s Discussion and Analysis are the following sections:


•	Overview


•	Results of Operations


•	Liquidity and Capital Resources


•	Non-GAAP Financial Measures


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported net income attributable to Genesis Energy, L.P. of $33.7 million, or $0.28 per common unit, during the three months ended June 30, 2017 (“2017 Quarter”) compared to net income attributable to Genesis Energy, L.P. of $23.7 million, or $0.22 per common unit, during the three months ended June 30, 2016 (“2016 Quarter”). This increase principally relates to a $26.7 million non-cash gain involving the sale and disposition of certain non-core natural gas gathering and platform assets in the Gulf of Mexico. This increase was partially offset by a non-cash provision of $12.6 million relating to certain leased railcars no longer in use (included in Onshore facilities and transportation operating costs in our Unaudited Condensed Consolidated Statements of Operations). This provision was recorded at fair value and we anticipate the future impact on net income relating these railcars to be insignificant.

Cash flow from operating activities was $119.3 million for the 2017 Quarter compared to $62.6 million for the 2016 Quarter.

Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") was $90.2 million for the 2017 Quarter, a decrease of $5.9 million, or 6.1%, from the 2016 Quarter. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Segment Margin (as defined below in "Non-GAAP Financial Measures") was $134.0 million for the 2017 Quarter, a decrease of $8.5 million, or 6.0%, from the 2016 Quarter.

During the quarter, we experienced extraordinary planned and unplanned downtime by our producer customers at several major fields in the Gulf of Mexico which resulted in our reported segment margin for the quarter being negatively impacted. While we expect some continuation of such negative effects in the third quarter, we believe they will be largely behind us going into the fourth quarter and in no way are reflective of the underlying long-term resiliency of the deepwater.

In spite of these specific challenges, we are encouraged by the ramping volumes we are beginning to experience on our recently completed organic projects in the Baton Rouge corridor and in and around Texas City. Our marine and refinery services segments performed consistent with our expectations. All in all, we feel we are reasonably positioned at this point to realize increasing financial contributions from our businesses with little additional capital required. This should allow us to work towards our goal of decreasing leverage in future periods with the majority of our capital spend behind us and the majority of our expected increased segment margin in front of us.

On August 2, 2017, we entered into a stock purchase agreement with a subsidiary of Tronox Limited ("Tronox") pursuant to which we will acquire for approximately $1.325 billion in cash all of Tronox's trona and trona-based exploring, mining, processing, producing, marketing and selling business (the “Alkali Business”). The Alkali Business is the world’s largest producer of natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. The Alkali Business produces approximately four million tons of natural soda ash per year, representing approximately 28% of all the natural soda ash produced in the world, and based on current production rates, has an estimated reserve life remaining of over 100 years. Having been in continuous operations for almost 70 years, it sells its products to a broad, industry-diverse and worldwide customer base, including numerous long-term relationships.

In conjunction with the transaction, Genesis has received binding commitments for the purchase of approximately $750 million of 8.75% Class A Convertible Preferred Units from investment vehicles affiliated with KKR Global Infrastructure Investors

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II, LP (“KKR”) and GSO Capital Partners LP (“GSO”). KKR and GSO will acquire approximately 22.2 million units at a price of $33.71 per unit.

The acquisition of Tronox’s Alkali Business is an exciting growth opportunity for us. We believe the acquisition to be immediately deleveraging and will provide further diversification and substantial scale to the partnership. The business is a great strategic fit with our current asset base and shares many characteristics with our existing refinery services business. It is a market leader with high barriers to entry, and generates stable and predictable cash flow, with production sold out each of the last seven years and estimated last twelve months adjusted EBITDA of $166 million. We are excited to partner with KKR and GSO, two leading global investment firms. We believe their investment not only validates our view of the Alkali Business opportunity but also underscores the quality of Genesis’ existing diverse asset footprint including industry leading positions in multiple businesses.

We currently expect to fund the acquisition price and related transaction costs with proceeds from the sale of the preferred units, a notes offering and/or borrowings under our $1.7 billion senior secured credit facility, as well as cash on hand. We expect to close the acquisition in the second half of 2017.

A more detailed discussion of our segment results and other costs is included below in "Results of Operations".

Distribution Increase

In July 2017, we declared our forty-eighth consecutive increase in our quarterly distribution to our common unitholders. In August 2017, we will pay a distribution of $0.7225 per unit related to the 2017 Quarter.

Segment Reporting Change

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2017 Quarter decreased $39.3 million, or 8.8%, from the 2016 Quarter. Additionally, our costs and expenses, exclusive of our non-cash gain on asset sales and non-cash provision for leased railcars no longer in use, decreased $38.6 million, or 9.7%, between those two periods.

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products through our onshore facilities and transportation segment. The decrease in our revenues and costs between those two quarterly periods is primarily attributable to decreases in crude oil and petroleum product sales volumes as discussed further below. In general, we do not expect fluctuations in prices for crude oil and natural gas to materially affect our net income, Available Cash before Reserves or Segment Margin to the same extent they affect our revenues and costs. We have limited our direct commodity price exposure through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin.

As discussed throughout this document and throughout our Annual Report on Form 10-K, we have some indirect exposure to certain changes in prices for crude oil and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the section of our Annual Report entitled “Risks Related to Our Business”.

Prices of crude oil have partially recovered since the 2016 Quarter. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") increased 5.9% to $48.29 per barrel in the 2017 Quarter, as compared to $45.59 per barrel in the 2016 Quarter. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products,

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producing minimal direct impact on Segment Margin from those operations. However, due to the indirect exposure to changes in prices discussed above, the factors addressed in our onshore facilities and transportation segment discussion below, and the fact the crude oil prices have remained low for an extended period of time as compared to the five year period before 2015 , our crude oil and petroleum product sales volumes have continued to decline, including a 26.3% decrease in the 2017 Quarter as compared to the 2016 Quarter.

Increases in certain of our operating costs between the respective quarters, such as those associated with our refinery services and marine transportation segments, are not correlated with crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.

We currently have two distinct, complementary types of operations-(i) our onshore-based refinery-centric crude oil and refined petroleum products transportation, facilities, logistics, and handling operations, focusing predominantly on refinery-centric customers (as opposed to producers), and (ii) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large reservoir, long-lived crude oil and natural gas properties. Refiners are the shippers of over 80% of the volumes transported on our onshore crude pipelines, and refiners contract for over 80% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. The shippers on our offshore pipelines are mostly integrated and large independent energy companies who have developed, and continue to explore for, numerous large-reservoir, long-lived crude oil properties whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in this lower commodity price environment. Given these facts, we do not expect changes in commodity prices to impact our net income, Available Cash before Reserves or Segment Margin in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2017 and June 30, 2016 was as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)				(in thousands)
Offshore pipeline transportation	78,211		84,282		$	165,300	$	162,900
Onshore facilities and transportation	25,296		20,261		46,393		46,409
Refinery services	16,337		19,861		33,833		41,060
Marine transportation	14,156		18,082		27,119		36,998
Total Segment Margin	$	134,000	$	142,486	$	272,645	$	287,367

We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees and certain litigation expenses that are not deducted to determine our Pro Forma Adjusted EBITDA under our revolving credit facility. Our Segment Margin definition also includes the non-income portion of payments received under direct financing leases and eliminates non-cash revenues, expenses, gains, losses and charges (such as depreciation and amortization, unrealized gain or loss on derivative transactions not designated as hedges for accounting purposes, gain or loss on sale of non-surplus assets and equity based compensation expense that is not settled in cash). Our reconciliation of total Segment Margin to net income reflects that Segment Margin (as defined above) excludes corporate general and administrative expenses, non-cash gains and charges, depreciation, amortization and accretion, interest expense, certain non-cash items, and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. See "Non-GAAP Financial Measures" for further discussion surrounding total Segment Margin.

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A reconciliation of total Segment Margin to net income for the periods presented is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Total Segment Margin	$	134,000		$	142,486		$	272,645		$	287,367
Corporate general and administrative expenses	(7,137		)	(10,491		)	(15,464		)	(21,849		)
Depreciation, amortization and accretion	(59,382		)	(62,213		)	(117,777		)	(111,388		)
Interest expense	(37,990		)	(35,535		)	(74,729		)	(69,922		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(9,140		)	(11,141		)	(18,430		)	(21,755		)
Non-cash items not included in Segment Margin	(1,867		)	15			(1,430		)	(4,359		)
Cash payments from direct financing leases in excess of earnings	(1,709		)	(1,548		)	(3,376		)	(3,059		)
Gain on sale of assets	26,684			—			26,684			—
Non-cash provision for leased items no longer in use	(12,589		)	—			(12,589		)	—
Differences in timing of cash receipts for certain contractual arrangements ₍₂₎	3,166			3,163			5,847			6,005
Income tax expense	(303		)	(1,009		)	(558		)	(2,010		)
Net income attributable to Genesis Energy, L.P.	$	33,733		$	23,727		$	60,823		$	59,030

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

(2) Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

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Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)						(in thousands)
Offshore crude oil pipeline revenue	$	65,805		$	66,248		$	137,079		$	129,632
Offshore natural gas pipeline revenue	11,834			12,746			25,688			25,488
Offshore pipeline operating costs, excluding non-cash expenses	(15,324		)	(16,363		)	(30,880		)	(34,171		)
Distributions from equity investments ⁽¹⁾	19,215			22,770			39,565			43,622
Other	(3,319		)	(1,119		)	(6,152		)	(1,671		)
Offshore pipeline transportation Segment Margin	$	78,211		$	84,282		$	165,300		$	162,900

Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	219,693			214,884			228,851			205,878
Poseidon	256,727			265,157			258,507			257,386
Odyssey	116,663			104,816			115,645			106,304
GOPL ⁽²⁾	6,719			5,030			8,089			5,612
Total crude oil offshore pipelines	599,802			589,887			611,092			575,180

Natural gas transportation volumes (MMBtus/d)	502,801			588,068			539,347			592,933

Volumetric Data net to our ownership interest ⁽³⁾:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	219,693			214,884			228,851			205,878
Poseidon	164,305			169,700			165,444			164,727
Odyssey	33,832			30,397			33,537			30,828
GOPL ⁽²⁾	6,719			5,030			8,089			5,612
Total crude oil offshore pipelines	424,549			420,011			435,921			407,045

Natural gas transportation volumes (MMBtus/d)	240,800			310,982			260,061			308,631


(1)	Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2017 and 2016, respectively.


(2)	One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system.


(3)	Volumes are the product of our effective ownership interest through the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.

Three Months Ended June 30, 2017 Compared with Three Months Ended June 30, 2016

Offshore Pipeline Transportation Segment Margin for the 2017 Quarter decreased $6.1 million, or 7%, from the 2016 Quarter. The 2017 Quarter was negatively impacted by both anticipated and unanticipated downtime at several major fields, including weather related downtime, affecting certain of our deepwater Gulf of Mexico customers and thus certain of our key crude oil and natural gas assets, including our Poseidon pipeline and certain associated laterals which we own. While such downtime was temporary and each of the major fields are back to being fully operational, we expect additional planned downtime for maintenance involving certain customers' fields during the third quarter of 2017.

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Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

Offshore pipeline transportation Segment Margin for the first six months of 2017 increased $2.4 million, or 1%, from the first six months of 2016. The increase was the result of new production primarily attributable to 2016 drilling activity that predominantly occurred near existing infrastructure due to attractive economics even in current pricing conditions. Our extensive pipeline network benefited ratably from this activity.

Onshore Facilities and Transportation Segment

Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks, railcars, and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals, rail facilities and CO2 pipelines operating primarily within the United States Gulf Coast and Rocky Mountain crude oil markets. In addition, we utilize our railcar and trucking fleets that support the purchase and sale of gathered and bulk purchased crude oil, as well as purchased and sold refined products. Through these assets we offer our customers a full suite of services, including the following:


•	facilitating the transportation of crude oil from producers to refineries and from owned and third party terminals to refiners via pipelines;


•	transporting CO2 from natural and anthropogenic sources to crude oil fields owned by our customers;


•	shipping crude oil and refined products to and from producers and refiners via trucks, pipelines, and railcars;


•	loading and unloading railcars at our crude-by-rail terminals;


•	storing and blending of crude oil and intermediate and finished refined products;


•	purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and


•	purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets.

We also use our terminal facilities to take advantage of contango market conditions, to gather and market crude oil, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills and assets to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.

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Operating results from our onshore facilities and transportation segment were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)						(in thousands)
Gathering, marketing, and logistics revenue	$	215,297		$	256,799		$	434,986		$	446,364
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines	16,608			15,041			31,345			31,554
Payments received under direct financing leases not included in income	1,709			1,548			3,376			3,059
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(187,913		)	(230,501		)	(380,966		)	(390,740		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(21,313		)	(23,676		)	(43,600		)	(48,798		)
Other	908			1,050			1,252			4,970
Segment Margin	$	25,296		$	20,261		$	46,393		$	46,409

Volumetric Data (average barrels per day):
Onshore crude oil pipelines:
Texas	31,598			40,568			19,822			56,963
Jay	14,435			14,583			14,868			14,178
Mississippi	8,520			10,715			8,668			11,164
Louisiana ⁽¹⁾	131,300			20,213			107,100			24,869
Wyoming	20,638			13,987			18,603			10,684
Onshore crude oil pipelines total	206,491			100,066			169,061			117,858

CO₂ pipeline (average Mcf/day):
Free State	60,070			83,965			75,420			107,795

Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	48,564			65,929			47,819			67,955
Rail load/unload volumes ⁽²⁾	69,362			5,735			61,511			13,472

(1) Total daily volume for the three months and six months ended June 30, 2017 includes 66,442 and 49,346 barrels per day respectively of intermediate refined products associated with our new Port of Baton Rouge Terminal pipelines which became operational in the fourth quarter of 2016.

(2) Indicates total barrels for either loading or unloading at all rail facilities.

Three Months Ended June 30, 2017 Compared with Three Months Ended June 30, 2016

Segment Margin for our onshore facilities and transportation segment increased by $5.0 million, or 25%, between the two three month periods. In the 2017 Quarter, this increase is primarily attributable to the ramp up in volumes on our pipeline, rail and terminal infrastructure on our recently completed infrastructure in the Baton Rouge corridor. In addition, relative to the first quarter of 2017, we experienced an increase in sequential volumes on our Texas pipeline system as the repurposing of our Houston area crude oil pipeline and expansion of our terminal infrastructure became operational in the 2017 Quarter. These factors were partially offset by a decrease in our Segment Margin due to lower demand in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. We find it difficult to compete with certain persons in the market who are willing to lose money on such local gathering because they are attempting to minimize their losses from minimum volume or take-or-pay commitments they previously made in anticipation of new production that has not yet come online.

Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

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Segment Margin for our onshore facilities and transportation segment did not significantly change between the first six months of 2017 and the first six months of 2016. The first six months of 2017 include the effects of the ramp up in volumes on our pipeline, rail and terminal infrastructure on our recently completed infrastructure in the Baton Rouge corridor. This was principally offset by lower demand for our services in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. In addition, the first six months of 2017 were negatively impacted by lower volumes on our Texas pipeline system, as the repurposing of our Houston area crude oil pipeline and expansion of our terminal infrastructure did not became operational until the 2017 Quarter while the first six months of 2016 included historical volumes on our legacy Texas pipeline system assets prior to the repurposing project.

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Volumes sold (in Dry short tons "DST"):
NaHS volumes	30,665		30,011		65,194		61,817
NaOH (caustic soda) volumes	17,809		21,387		34,216		40,149
Total	48,474		51,398		99,410		101,966

Revenues (in thousands):
NaHS revenues	$	34,093	$	32,308	$	71,507	$	66,626
NaOH (caustic soda) revenues	9,765		9,951		18,366		18,944
Other revenues	1,352		1,359		2,608		2,798
Total external segment revenues	$	45,210	$	43,618	$	92,481	$	88,368

Segment Margin (in thousands)	$	16,337	$	19,861	$	33,833	$	41,060

Average index price for NaOH per DST ⁽¹⁾	$	623	$	447	$	596	$	431

(1) Source: IHS Chemical. In the fourth quarter of 2016, IHS posted a non-market adjustment to previously posted US Caustic Soda Index prices. This adjustment is reflected in our disclosed index prices.

Three Months Ended June 30, 2017 Compared with Three Months Ended June 30, 2016

Refinery services Segment Margin for the 2017 Quarter decreased $3.5 million, or 18%. The 2017 Quarter results were in line with our expectations and include the effects of previously disclosed commercial discussions with certain of our host refineries and several NaHS customers, which resulted in extending the term and tenor of a large number of contractual relationships. This includes the extension of our largest refinery services agreement at our Westlake facility through 2026.

Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

Refinery services Segment Margin for the first six months of 2017 decreased $7.2 million, or 18%. The first six months of 2017 results include the effects of previously disclosed commercial discussions with certain of our host refineries and several NaHS customers, which resulted in extending the term and tenor of a large number of contractual relationships. This includes the extension of our largest refinery services agreement at our Westlake facility through 2026.

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Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 83 barges (74 inland and 9 offshore) with a combined transportation capacity of 2.9 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues (in thousands):
Inland freight revenues	$	20,609		$	21,362		$	42,059		$	44,294
Offshore freight revenues	19,303			21,776			37,444			42,969
Other rebill revenues ⁽¹⁾	13,290			9,471			24,001			17,382
Total segment revenues	$	53,202		$	52,609		$	103,504		$	104,645

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	39,046		$	34,527		$	76,385		$	67,647

Segment Margin (in thousands)	$	14,156		$	18,082		$	27,119		$	36,998

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	90.6		%	91.7		%	90.3		%	93.3		%
Offshore Barge Utilization	99.3		%	91.6		%	97.9		%	88.5		%

(1) Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.

(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and dry-docking.

Three Months Ended June 30, 2017 Compared with Three Months Ended June 30, 2016

Marine Transportation Segment Margin for the 2017 Quarter decreased $3.9 million, or 22%, from the 2016 Quarter. The decrease in Segment Margin is primarily due to a combination of slightly lower utilization and lower day rates on our inland fleet, as well as lower day rates on our offshore fleet (which offset higher utilization as adjusted for planned dry docking time). This excludes the M/T American Phoenix which is under long term contract through September 2020. In our inland fleet, utilization was strong at the beginning of the 2017 Quarter, but slowed towards the end as turnarounds at certain of our refinery customers ended and other market factors resulted in weaker demand for black oil barge freight. Such weaker demand has also continued to apply pressure on our rates and we expect these factors to continue to impact our inland fleet in the third quarter. In our offshore barge fleet, as a number of our units have come off longer term contracts, we have continued to choose to primarily place them in spot service or short-term (less than a year) service, as we continue to believe the day rates currently being offered by the market are at, or approaching, cyclical lows.

Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

Marine transportation Segment Margin for the first six months of 2017 decreased $9.9 million, or 27%, from the first six months of 2016. The decrease in Segment Margin is primarily due to a combination of slightly lower utilization and lower day rates on our inland fleet, as well as lower day rates on our offshore fleet (which offset higher utilization as adjusted for planned dry docking time). This excludes the M/T American Phoenix which is under long term contract through September 2020. In our inland fleet, utilization was strong at the beginning of the 2017 Quarter (as well as the end of the first quarter of 2017), but slowed towards the end as turnarounds at certain of our refinery customers ended and other market factors resulted in weaker demand for black oil barge freight service. Such weaker demand has also continued to apply pressure on our rates and we expect these factors to continue to impact our inland fleet in the third quarter. In our offshore barge fleet, as a number of our units have come off longer term contracts, we have continued to choose to primarily place them in spot service or short-term (less than a year) service, as we continue to believe the day rates currently being offered by the market are at, or approaching, cyclical lows.

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Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017			2016
	(in thousands)					(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	9,358		$	7,048	$	17,279		$	18,376
Segment	792			578		1,576			1,446
Equity-based compensation plan expense	(1,139		)	2,911		(455		)	2,679
Third party costs related to business development activities and growth projects	327			746		914			1,003
Total general and administrative expenses	$	9,338		$	11,283	$	19,314		$	23,504

Total general and administrative expenses decreased $1.9 million and $4.2 million between the three and six month periods primarily due to the effects of changes in assumptions used to value our equity based compensation awards that are tied to our unit price.

Depreciation and amortization expense



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)				(in thousands)
Depreciation expense	$	50,397	$	48,807	$	100,321	$	88,519
Amortization of intangible assets	5,872		6,040		11,744		12,032
Amortization of CO2 volumetric production payments	340		1,053		656		1,984
Total depreciation and amortization expense	$	56,609	$	55,900	$	112,721	$	102,535

Total depreciation and amortization expense increased $0.7 million and $10.2 million between the three and six month periods primarily as a result of placing additional assets into service.

Interest expense, net



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)						(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	12,574		$	10,670		$	24,157		$	20,041
Interest expense, senior unsecured notes	28,610			28,610			57,219			57,219
Amortization of debt issuance costs and discount	2,678			2,551			5,260			4,992
Capitalized interest	(5,872		)	(6,296		)	(11,907		)	(12,330		)
Net interest expense	$	37,990		$	35,535		$	74,729		$	69,922

Net interest expense increased $2.5 million and $4.8 million between the three and six month periods primarily due to an increase in our average outstanding indebtedness from acquired and constructed assets.

Income tax expense

A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

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Other

In addition to the items previously discussed, net income for the 2017 Quarter included a $0.4 million unrealized loss on derivative positions as compared to a $0.3 million unrealized gain on derivative positions in the 2016 Quarter. Net income for the first six months of 2017 included an unrealized loss on derivative positions, excluding fair value hedges, of $0.6 million. Net income for the first six months of 2016 included an unrealized loss on derivative positions of $1.3 million.

Liquidity and Capital Resources

General

As of June 30, 2017, we had $488.0 million of remaining borrowing capacity under our $1.7 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.

Our primary cash requirements consist of:


•	working capital, primarily inventories and trade receivables and payables;


•	routine operating expenses;


•	capital growth and maintenance projects;


•	acquisitions of assets or businesses;


•	payments related to servicing outstanding debt; and


•	quarterly cash distributions to our unitholders.

Capital Resources

Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time — including through equity and debt offerings (public and private), borrowings under our credit facility and other financing transactions—and to implement our growth strategy successfully. No assurance can be made that we will be able to raise additional capital on satisfactory terms or implement our growth strategy successfully.

At June 30, 2017, our long-term debt totaled $3 billion, consisting of $1.2 billion outstanding under our credit facility (including $48 million borrowed under the inventory sublimit tranche) and $1.8 billion of senior unsecured notes, comprised of $350 million carrying amount due on February 15, 2021, $400 million carrying amount due on May 15, 2023, $350 million carrying amount due on June 15, 2024, and $750 million carrying amount due August 1, 2022.

Equity Distribution Program and Shelf Registration Statements

We expect to issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to opportunistically acquiring assets and businesses and constructing new facilities.

In 2016, we implemented an equity distribution program that will allow us to consummate “at the market” offerings of common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue additional common units from time to time, although there are limits to the amount of our “at the market” offerings the market can absorb from time to time. In connection with implementing our equity distribution program, we filed a universal shelf registration statement (our "EDP Shelf") with the SEC. Our EDP Shelf allows us to issue up to $400.0 million of equity and

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debt securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in August 2017. We expect to file a replacement universal shelf registration statement before our EDP Shelf expires. As of June 30, 2017, we have issued no additional units under this program.

We have another universal shelf registration statement (our "2015 Shelf") on file with the SEC. Our 2015 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2015 Shelf will expire in April 2018. We expect to file a replacement universal shelf registration statement before our 2015 Shelf expires.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem, as we make payments and receive payments for the purchase and sale of crude oil.

In our petroleum products activities, we buy products and typically either move those products to one of our storage facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.

The storage of our inventory of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the crude oil or petroleum products, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, we may be required to deposit margin funds with the NYMEX when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.

See Note 11 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the six months ended June 30, 2017 and June 30, 2016.

Net cash flows provided by our operating activities for the Six Months Ended June 30, 2017 were $184.0 million compared to $103.7 million for the Six Months Ended June 30, 2016. This increase in operating cash flow is primarily due to a decrease in working capital needs.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, organic growth projects, maintenance capital expenditures and distributions we pay to our unitholders. We finance maintenance capital expenditures and smaller organic growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and organic growth projects) with borrowings under our credit facility, equity issuances and/or issuances of senior unsecured notes.

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Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, business and other asset acquisitions for the six months ended June 30, 2017 and June 30, 2016 is as follows:



	Six Months Ended June 30,
	2017		2016
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets	$	2,937	$	2,248
Refinery services assets	945		1,157
Marine transportation assets	9,047		6,446
Onshore facilities and transportation assets	2,502		5,904
Information technology systems	57		396
Total maintenance capital expenditures	15,488		16,151
Growth capital expenditures:
Offshore pipeline transportation assets	$	3,205	$	1,615
Refinery services assets	—		—
Marine transportation assets	11,618		29,545
Onshore facilities and transportation assets	86,583		167,429
Information technology systems	262		5,812
Total growth capital expenditures	101,668		204,401
Total capital expenditures for fixed and intangible assets	117,156		220,552
Capital expenditures for acquisitions, net of liabilities assumed:
Acquisition of remaining interest in Deepwater Gateway ⁽¹⁾	—		26,200
Total business combinations capital expenditures	—		26,200
Capital expenditures related to equity investees	—		1,135
Total capital expenditures	$	117,156	$	247,887


(1)	Amount represents our purchase price for our purchase of the remaining 50% interest in Deepwater Gateway in the first quarter of 2016.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We continue to pursue a long-term growth strategy that may require significant capital.

Growth Capital Expenditures

We anticipate spending approximately $75.0 million, inclusive of capitalized interest, during the remainder of 2017 for projects currently under construction. The most significant of our recent projects are described below.

Baton Rouge Area Infrastructure Expansion

We are currently expanding our existing Baton Rouge area infrastructure to allow for greater capacity and flexibility in servicing our major refinery customer in the region. This expansion includes the construction of an additional 500,000 barrels of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes received at our Baton Rouge area facilities. We expect these assets to become operational in the first quarter of 2018.

Houston Area Crude Oil Pipeline and Terminal Infrastructure

We have constructed new, and expanded existing, crude oil pipeline and terminal facilities in Webster, Texas and Texas City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We have also constructed a new crude oil pipeline that delivers crude oil received from upstream crude oil pipelines (including CHOPS, which delivers crude oil originating in the deepwater Gulf of Mexico to the Texas City area) to our new Texas City Terminal, which connects to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal includes approximately 750,000 barrels of crude oil tankage. As a part of this project, we hav also made the necessary upgrades on our existing 18-inch Webster to Texas City crude oil pipeline to reverse the direction of flow. The result of this expanded crude oil infrastructure allows additional optionality to Houston and Baytown area refineries, including the ExxonMobil Baytown

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refinery, its largest refinery in the U.S.A., and provides additional delivery outlets for other crude oil pipelines. These assets became operational in the second quarter of 2017.

Raceland Terminal and Crude Oil Pipeline

We have constructed a new crude oil terminal and pipeline in Raceland, Louisiana that connects to existing midstream infrastructure to provide further distribution to the Louisiana refining markets. Our new Raceland Terminal consists of 515,000 barrels of crude oil tankage and unit train unloading facilities capable of unloading up to two unit trains per day. We have also constructed a new crude oil pipeline that will deliver crude oil received from the Poseidon system, which currently delivers crude oil originating in the deepwater Gulf of Mexico to the Houma, Louisiana area, to our new Raceland Terminal for further distribution. These assets became fully operational at the end of the second quarter of 2017.

Inland Marine Barge Transportation Expansion

We ordered 28 new-build barges and 18 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of 20 of those barges and 16 of those push boats through June 30, 2017. We expect to take delivery of those remaining vessels periodically through 2017 and 2018.

Maintenance Capital Expenditures

Our slight decrease in maintenance capital expenditures for the six months ended June 30, 2017 Quarter as compared to the six months ended June 30, 2016 Quarter principally relates to a decrease in maintenance capital projects on onshore facilities and transportation assets, as partially offset by an increase in marine maintenance capital spending as a result of higher spending on certain vessel replacement parts and components. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.

Proceeds from Assets Sales

The six months ended June 30, 2017 include proceeds from asset sales of $38.2 million, as compared to proceeds of $3.2 million during the six months ended June 30, 2016. This is principally comprised of the sale of certain non-core natural gas gathering and platform assets in the Gulf of Mexico in the 2017 Quarter.

Distributions to Unitholders

On August 14, 2017, we will pay a distribution of $0.7225 per common unit totaling $88.6 million with respect to the 2017 Quarter to common unitholders of record on July 31, 2017. This is the forty-eighth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 8 to our Unaudited Condensed Consolidated Financial Statements.

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Non-GAAP Financial Measure Reconciliations

For definitions and discussion of our Non-GAAP financial measures refer to the "Non-GAAP Financial Measures" as later discussed and defined.

Available Cash before Reserves for the periods presented below was as follows:



	Three Months Ended June 30,
	2017			2016
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	33,733		$	23,727
Depreciation, amortization and accretion	59,382			62,213
Cash received from direct financing leases not included in income	1,709			1,548
Cash effects of sales of certain assets	5,003			209
Effects of distributable cash generated by equity method investees not included in income	9,140			11,141
Expenses related to acquiring or constructing growth capital assets	327			747
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value	480			(338		)
Maintenance capital utilized ⁽¹⁾	(3,120		)	(1,795		)
Non-cash tax expense	153			710
Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾	(3,166		)	(3,163		)
Gain on sale of assets	(26,684		)	—
Non-cash provision for leased items no longer in use	12,589			—
Other items, net	618			1,036
Available Cash before Reserves	90,164			96,035


(1)	For a description of the term "maintenance capital utilized," please see the definition of the term "Available Cash Before Reserves" discussed below.


(2)	Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

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	Three Months Ended June 30,
	2017			2016
	(in thousands)
Cash Flows from Operating Activities	$	119,349		$	62,566
Adjustments to reconcile net cash flow provided by operating activities to Available Cash before Reserves:
Maintenance capital utilized ⁽¹⁾	(3,120		)	(1,795		)
Proceeds from certain asset sales	5,003			209
Amortization and writeoff of debt issuance costs, including premiums and discounts	(2,678		)	(2,551		)
Effects of available cash of equity method investees not included in operating cash flows	4,805			6,063
Net changes in components of operating assets and liabilities not included in calculation of Available Cash before Reserves	(37,381		)	38,174
Non-cash effect of equity based compensation expense	2,248			(4,679		)
Expenses related to acquiring or constructing assets that provide new sources of cash flow	327			747
Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾	(3,166		)	(3,163		)
Other items, net	4,777			464
Available Cash before Reserves	90,164			96,035


(1)	For a description of the term "maintenance capital utilized," please see the definition of the term "Available Cash Before Reserves" discussed below.


(2)	Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.

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Non- GAAP Financial Measures

General

To help evaluate our business, we use the non-generally accepted accounting principle (“non-GAAP”) financial measure of Available Cash before Reserves. We also present total Segment Margin as if it were a non-GAAP measure. Our Non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The schedules above provide reconciliations of Available Cash before Reserves to its most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States of America (GAAP). A reconciliation of total Segment Margin to net income is also included in our segment disclosure in Note 9 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just two of the relevant data points considered from time to time.

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user.

Segment Margin

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. We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees and certain litigation expenses that are not deducted to determine our Pro Forma Adjusted EBITDA under our revolving credit facility. Our Segment Margin definition also includes the non-income portion of payments received under direct financing leases and eliminates non-cash revenues, expenses, gains, losses and charges (such as depreciation and amortization, unrealized gain or loss on derivative transactions not designated as hedges for accounting purposes, gain or loss on sale of non-surplus assets and equity based compensation expense that is not settled in cash).

A reconciliation of total Segment Margin to net income is included in our segment disclosure in Note 9 to our Unaudited Condensed Consolidated Financial Statements, as well as previously in this Item 2.

Available Cash before Reserves

Purposes, Uses and Definition

Available Cash before Reserves, also referred to as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:


(1)	the financial performance of our assets;


(2)	our operating performance;


(3)	the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;


(4)	the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and


(5)	our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

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We define Available Cash before Reserves as net income as adjusted for certain items, some of the most significant of which tend to be (a) the elimination of certain non-cash revenues, expenses, gains, losses or charges (such as depreciation and amortization, unrealized gain or loss on derivative transactions not designated as hedges for accounting purposes, gain or loss on sale of non-surplus assets and equity compensation expense that is not settled in cash), (b) the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees (includes distributions attributable to the quarter and received during or promptly following such quarter), (c) the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, (d) certain litigation expenses that are not deducted in determining our Pro Forma Adjusted EBITDA under our senior secured credit facility, and (e) the subtraction of maintenance capital utilized, which is described in detail below.

Disclosure Format Relating to Maintenance Capital

We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

Maintenance Capital Requirements

Maintenance Capital Expenditures

Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.

Initially, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

As we exist today, a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s recently increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves. Our maintenance capital utilized measure, which is described in more detail below, constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

Maintenance Capital Utilized

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We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.

Because we did not initially use our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Commercial Commitments

There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2016.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2016, nor do we have any debt or equity triggers based upon our unit or commodity prices.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:


•	demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;


•	throughput levels and rates;


•	changes in, or challenges to, our tariff rates;


•	our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;


•	service interruptions in our pipeline transportation systems and processing operations;


•	shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell such products;


•	risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;


•	changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;


•	the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and crude oil spill in the Gulf;

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•	planned capital expenditures and availability of capital resources to fund capital expenditures;


•	our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;


•	loss of key personnel;


•	cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level or continue to increase quarterly cash distributions in the future;


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


•	hazards and operating risks that may not be covered fully by insurance;


•	our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow;


•	changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers or counterparties;


•	adverse rulings, judgments, or settlements in litigation or other legal or tax matters;


•	the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and


•	the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 12 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this Quarterly Report on Form 10-Q is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

There were no changes during the second quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

Except as described below, there has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, except as supplemented by our quarterly Reports on Form 10-Q and Current Reports on Form 8-K and Form 8-K/A. As set forth below, we have revised, clarified and supplemented our risk factors, including those contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Annual Report”).

As part of the filing of this Form 10-Q, we intend to revise, clarify and supplement our risk factors, including those contained in the Annual Report. The risk factors below should be considered together with the other risk factors described in the Annual Report and filings with the SEC under the Securities Exchange Act of 1934, as amended, after the Annual Report. For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016, as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

As a result of the Alkali Business Acquisition, we anticipate that the scope and size of our operations and business will substantially change. We cannot provide assurance that our expansion in scope and size will be successful.

We anticipate that the Alkali Business Acquisition will substantially expand the scope and size of our business by adding substantial assets and operations to our existing business. The anticipated future growth of our business will impose significant added responsibilities on management, including the need to identify, recruit, train and integrate additional employees. Our senior management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in the Alkali Business Acquisition. Our ability to manage our business and growth will require us to continue to improve our operational, financial and management controls, reporting systems and procedures. We may also encounter risks, costs and expenses associated with any undisclosed or other unanticipated liabilities and use more cash and other financial resources on integration and implementation activities than we expect. We may not be able to successfully integrate the Alkali Business into our existing operations or realize the expected economic benefits of the Alkali Business Acquisition, which may have a material adverse effect on our business, financial condition and results of operations, including our distributable cash flow.

Failure to successfully combine our business with the assets to be acquired in the Alkali Business Acquisition, or an inaccurate estimate by us of the benefits to be realized from the Alkali Business Acquisition, may adversely affect our future results.

The Alkali Business Acquisition involves potential risks, including:


•	the failure to realize expected profitability, growth or accretion;


•	environmental or regulatory compliance matters or liabilities;


•	antitrust or legal compliance matters or liabilities;


•	labor compliance matters or liabilities;


•	title or permit issues;


•	the incurrence of significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and


•	the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.

The expected benefits from the pending Alkali Business Acquisition may not be realized if our estimates of the potential net cash flows associated with the assets to be acquired by us in the Alkali Business Acquisition are materially inaccurate or if we fail to identify operating issues or liabilities associated with the assets prior to closing. The accuracy of our estimates of the potential net cash flows attributable to such assets is inherently uncertain. If certain issues are identified after closing of the Alkali Business Acquisition, the stock purchase agreement provides for limited recourse against Tronox.

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If we close the Alkali Business Acquisition and if any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of the Alkali Business Acquisition may not be fully realized, if at all, and our future financial condition, results of operations and distributable cash flow could be negatively impacted.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits.

(a) Exhibits



	3.1	Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 of the Registration Statement on Form S-1, File No. 333-11545).
	3.2	Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011, File No. 001-12295).
	3.3	Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.5	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	3.6	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
	10.1	Fifth Amendment to Fourth Amended and Restated Credit Agreement and Second Amendment to Fourth Amended and Restated Guarantee and Collateral Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 15, 2017, File No. 001-12295).
*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Schema Document
*	101.CAL	XBRL Calculation Linkbase Document
*	101.LAB	XBRL Label Linkbase Document
*	101.PRE	XBRL Presentation Linkbase Document
*	101.DEF	XBRL Definition Linkbase Document



*	Filed herewith

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		GENESIS ENERGY, L.P. (A Delaware Limited Partnership)

	By:	GENESIS ENERGY, LLC, as General Partner



Date:	August 3, 2017	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer

Genesis Energy L.P. - 10-Q quarterly report FY2017 Q2

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