GENESIS ENERGY LP - Quarter Report: 2016 September (Form 10-Q)

Three Months Ended September 30, 2016

Nine Months Ended September 30, 2016

Net income

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 September 30, 2016

¨ 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨

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 117,939,221 Class A Common Units and 39,997 Class B Common Units outstanding as of November 3, 2016.

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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. Acquisition and Divestiture	8
	4. Inventories	9
	5. Fixed Assets	10
	6. Equity Investees	11
	7. Intangible Assets	13
	8. Debt	14
	9. Partners' Capital and Distributions	14
	10. Business Segment Information	15
	11. Transactions with Related Parties	17
	12. Supplemental Cash Flow Information	18
	13. Derivatives	18
	14. Fair-Value Measurements	21
	15. Contingencies	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	51
Item 4.	Controls and Procedures	51
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
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	52
SIGNATURES		53

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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)



	September 30, 2016			December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,447		$	10,895
Accounts receivable - trade, net	210,808			219,532
Inventories	70,199			43,775
Other	27,322			32,114
Total current assets	311,776			306,316
FIXED ASSETS, at cost	4,707,685			4,310,226
Less: Accumulated depreciation	(509,419		)	(378,247		)
Net fixed assets	4,198,266			3,931,979
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	134,640			139,728
EQUITY INVESTEES	417,214			474,392
INTANGIBLE ASSETS, net of amortization	210,713			223,446
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	57,829			58,692
TOTAL ASSETS	$	5,655,484		$	5,459,599
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	128,189		$	140,726
Accrued liabilities	114,030			161,410
Total current liabilities	242,219			302,136
SENIOR SECURED CREDIT FACILITY	1,167,000			1,115,000
SENIOR UNSECURED NOTES	1,811,633			1,807,054
DEFERRED TAX LIABILITIES	24,644			22,586
OTHER LONG-TERM LIABILITIES	227,879			192,072
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 117,979,218 and 109,979,218 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively	2,190,829			2,029,101
Noncontrolling interests	(8,720		)	(8,350		)
Total partners' capital	2,182,109			2,020,751
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	5,655,484		$	5,459,599

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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
REVENUES:
Offshore pipeline transportation services	89,717			61,388			244,837			63,436
Onshore pipeline transportation services	13,999			19,909			48,400			57,910
Refinery services	45,725			43,332			129,585			135,780
Marine transportation	55,285			60,536			159,930			180,501
Supply and logistics	255,324			387,169			701,688			1,317,891
Total revenues	460,050			572,334			1,284,440			1,755,518
COSTS AND EXPENSES:
Offshore pipeline transportation operating costs	23,122			17,698			63,732			18,341
Onshore pipeline transportation operating costs	5,003			6,721			17,499			19,874
Refinery services operating costs	25,077			22,363			67,641			75,225
Marine transportation operating costs	38,490			33,869			105,942			100,749
Supply and logistics product costs	230,229			354,331			620,620			1,217,374
Supply and logistics operating costs	17,473			24,585			54,475			73,606
General and administrative	11,212			26,799			34,716			54,852
Depreciation and amortization	54,265			41,170			156,800			96,500
Total costs and expenses	404,871			527,536			1,121,425			1,656,521
OPERATING INCOME	55,179			44,798			163,015			98,997
Equity in earnings of equity investees	12,488			14,260			35,362			48,440
Interest expense	(34,735		)	(29,617		)	(104,657		)	(66,737		)
Gain on basis step up on historical interest	—			335,260			—			335,260
Other income/(expense), net	—			—			—			(17,529		)
Income before income taxes	32,932			364,701			93,720			398,431
Income tax expense	(949		)	(1,292		)	(2,959		)	(3,142		)
NET INCOME	31,983			363,409			90,761			395,289
Net loss (gain) attributable to noncontrolling interests	118			(195		)	370			(195		)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	32,101		$	363,214		$	91,131		$	395,094
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	0.28		$	3.38		$	0.81		$	3.93
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	115,718			107,617			111,906			100,653

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, 2016	109,979	$	2,029,101		$	(8,350	)	$	2,020,751
Net income (loss)	—	91,131			(370		)	90,761
Cash distributions to partners	—	(227,454		)	—			(227,454		)
Issuance of common units for cash, net	8,000	298,051			—			298,051
Partners' capital, September 30, 2016	117,979	$	2,190,829		$	(8,720	)	$	2,182,109
	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Total
Partners’ capital, January 1, 2015	95,029	$	1,229,203		$	—		$	1,229,203
Net income	—	395,094			195			395,289
Noncontrolling interest from acquisition	—	—			(6,471		)	(6,471		)
Cash distributions to partners	—	(186,026		)	—			(186,026		)
Cash distributions to noncontrolling interests	—	—			(560		)	(560		)
Issuance of common units for cash, net	14,950	633,759			—			633,759
Partners' capital, September 30, 2015	109,979	$	2,072,030		$	(6,836	)	$	2,065,194

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)



	Nine Months Ended September 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	90,761		$	395,289
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	156,800			96,500
Gain on basis step up on historical interest	—			(335,260		)
Amortization of debt issuance costs and discount or premium	7,563			8,467
Amortization of unearned income and initial direct costs on direct financing leases	(10,856		)	(11,286		)
Payments received under direct financing leases	15,501			15,501
Equity in earnings of investments in equity investees	(35,362		)	(48,440		)
Cash distributions of earnings of equity investees	49,528			54,463
Non-cash effect of equity-based compensation plans	6,102			6,387
Deferred and other tax liabilities	2,058			2,242
Unrealized loss on derivative transactions	742			68
Other, net	8,967			816
Net changes in components of operating assets and liabilities (Note 12)	(63,407		)	7,381
Net cash provided by operating activities	228,397			192,128
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(363,218		)	(359,504		)
Cash distributions received from equity investees - return of investment	16,652			19,360
Investments in equity investees	—			(2,900		)
Acquisitions	(25,394		)	(1,517,428		)
Contributions in aid of construction costs	12,208			—
Proceeds from asset sales	3,303			2,571
Other, net	185			(2,137		)
Net cash used in investing activities	(356,264		)	(1,860,038		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	883,600			1,168,850
Repayments on senior secured credit facility	(831,600		)	(705,150		)
Proceeds from issuance of senior unsecured notes	—			1,139,718
Repayment of senior unsecured notes	—			(350,000		)
Debt issuance costs	(1,578		)	(28,361		)
Issuance of common units for cash, net	298,051			633,759
Distributions to noncontrolling interests	—			(560		)
Distributions to common unitholders	(227,454		)	(186,026		)
Other, net	(600		)	1,786
Net cash provided by financing activities	120,419			1,674,016
Net increase (decrease) in cash and cash equivalents	(7,448		)	6,106
Cash and cash equivalents at beginning of period	10,895			9,462
Cash and cash equivalents at end of period	$	3,447		$	15,568

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, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, and in 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. We manage our businesses through the following five divisions that constitute our reportable segments:


•	Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;


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


•	Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or “NaHS”, commonly pronounced "nash");


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


•	Supply and logistics services, which include terminaling, blending, storing, marketing and transporting crude oil and petroleum products and, on a smaller scale, CO₂.

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, 2015.

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 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 approach. 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

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early adoption of the standard, but not before the original effective date of December 15, 2016. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

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 do not expect adoption to have a material impact on our consolidated financial statements.

In September 2015, the FASB issued ASU 2015-16 in response to stakeholder feedback that restating prior periods to reflect adjustments made to provisional amounts recognized in a business combination adds cost and complexity to financial reporting, but does not significantly improve the usefulness of information provided to users. Under the new ASU, an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The ASU also requires that the acquirer present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance is effective for reporting periods after December 15, 2015, with early adoption permitted. We have adopted this guidance and it has not had a 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. Acquisition and Divestiture

Acquisition

Enterprise Offshore

On July 24, 2015, we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its affiliates for approximately $1.5 billion, subject to certain adjustments. That business includes interests in offshore crude oil and natural gas pipelines and six offshore hub platforms, including a 36% interest in the Poseidon Oil Pipeline System, a 50% interest in the Southeast Keathley Canyon Oil Pipeline System, and a 50% interest in the Cameron Highway Oil Pipeline System. To finance that transaction, in July, we issued 10,350,000 common units in a public offering that generated proceeds of $437.2 million net of underwriter discounts and $750.0 million aggregate principal amount of 6.75% senior unsecured notes due 2022 that generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The remainder of that transaction was financed with borrowings under our senior secured credit facility.

We have reflected the financial results of the acquired business in our Offshore Pipeline Transportation Segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated fair values. Those fair values were developed by management with the assistance of a third-party valuation firm. As of the third quarter of 2016, the purchase price allocation for this transaction has been finalized. Our finalized purchase price allocation remains unchanged from what was disclosed in the financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015.

Our Consolidated Financial Statements include the results of our acquired offshore pipeline transportation business since July 24, 2015, the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:

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The table below presents selected unaudited pro forma financial information incorporating the historical results of our newly acquired offshore pipeline transportation assets. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2014 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of the Enterprise offshore pipelines and services businesses and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had the Enterprise acquisition been completed on January 1, 2014.



	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Pro forma consolidated financial operating results:
Revenues	$	590,994	$	1,930,978
Net Income Attributable to Genesis Energy L.P.	372,828		395,529
Basic and diluted earnings per unit:
As reported net income per unit	$	3.38	$	3.93
Pro forma net income per unit	$	3.39	$	3.65

4. Inventories

The major components of inventories were as follows:



	September 30, 2016		December 31, 2015
Petroleum products	$	2,061	$	14,235
Crude oil	57,035		22,815
Caustic soda	2,867		3,964
NaHS	8,231		2,755
Other	5		6
Total	$	70,199	$	43,775

Inventories are valued at the lower of cost or market. The market value of inventories were not below recorded cost as of September 30, 2016 and were below recorded costs by approximately $0.9 million as of December 31, 2015; therefore we reduced the value of inventory in our Condensed Consolidated Financial Statements for this difference in 2015.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	September 30, 2016			December 31, 2015
Crude oil pipelines and natural gas pipelines and related assets	$	2,667,221		$	2,501,821
Machinery and equipment	419,355			414,100
Transportation equipment	18,639			19,025
Marine vessels	842,700			794,508
Land, buildings and improvements	49,465			41,202
Office equipment, furniture and fixtures	9,441			7,540
Construction in progress	653,949			485,575
Other	46,915			46,455
Fixed assets, at cost	4,707,685			4,310,226
Less: Accumulated depreciation	(509,419		)	(378,247		)
Net fixed assets	$	4,198,266		$	3,931,979

Our depreciation expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Depreciation expense	$	46,909	$	33,716	$	135,428	$	78,265

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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. As a result of the Enterprise acquisition of the offshore pipeline and services business of Enterprise Products Partners, L.P. on July 24, 2015, we recorded AROs based on the fair value measurement assigned during the preliminary purchase price allocation.

The following table presents information regarding our AROs since December 31, 2015:



ARO liability balance, December 31, 2015	$	188,662
AROs arising from the purchase of the remaining interest in Deepwater Gateway	10,470
AROs from the consolidation of historical interest in Deepwater Gateway	10,470
Accretion expense	7,918
Change in estimate	5,609
Settlements	(3,216		)
ARO liability balance, September 30, 2016	$	219,913

Of the ARO balances disclosed above, $5.2 million and $9.8 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015, respectively. The remainder of the ARO liability as of September 30, 2016 and December 31, 2015 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	2016	$	2,710
	2017	$	9,807
	2018	$	8,144
	2019	$	8,735
	2020	$	9,298

Certain of our unconsolidated affiliates have AROs recorded at September 30, 2016 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.

6. 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 September 30, 2016 and December 31, 2015, the unamortized excess cost amounts totaled $402.1 million and $414.0 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

As part of our Enterprise acquisition, we increased our ownership interest in each of Cameron Highway Oil Pipeline Company ("CHOPS") and Southeast Keathley Canyon Pipeline Company, LLC ("SEKCO") from 50% to 100%. Consequently, these entities were reflected as equity investees until July 24, 2015, at which point they became fully consolidated wholly owned subsidiaries.

Also, as part of our Enterprise acquisition, our ownership interest in Poseidon Oil Pipeline Company, LLC ("Poseidon") increased from 28% to 64%. We also acquired a 50% ownership interest in Deepwater Gateway, LLC and a 25.7% interest in Neptune Pipeline Company, LLC. These additional interests are accounted for as equity investments from the acquisition date of July 24, 2015.

In the first quarter of 2016, we purchased the remaining 50% interest in Deepwater Gateway, LLC for approximately $26.0 million (including adjustments for working capital), so we now own 100% of that entity. Consequently, we now consolidate Deepwater Gateway, LLC instead of accounting for our interest under the equity method.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Genesis’ share of operating earnings	$	16,444		$	17,944		$	47,281		$	57,607
Amortization of excess purchase price	(3,956		)	(3,684		)	(11,919		)	(9,167		)
Net equity in earnings	$	12,488		$	14,260		$	35,362		$	48,440
Distributions received	$	21,551		$	23,522		$	66,180		$	73,823

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



	September 30, 2016		December 31, 2015
BALANCE SHEET DATA:
Assets
Current assets	$	14,662	$	18,507
Fixed assets, net	236,509		248,059
Other assets	929		1,133
Total assets	$	252,100	$	267,699
Liabilities and equity
Current liabilities	$	23,135	$	22,456
Other liabilities	211,066		203,514
Equity	17,899		41,729
Total liabilities and equity	$	252,100	$	267,699



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
INCOME STATEMENT DATA:
Revenues	$	31,219	$	30,830	$	90,658	$	92,684
Operating income	$	23,107	$	23,839	$	68,166	$	71,122
Net income	$	21,921	$	22,860	$	64,670	$	67,804

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

7. Intangible Assets

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



	September 30, 2016						December 31, 2015
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	88,888	$	5,766	$	94,654	$	86,285	$	8,369
Licensing agreements	38,678		33,577		5,101		38,678		31,694		6,984
Segment total	133,332		122,465		10,867		133,332		117,979		15,353
Supply & Logistics:
Customer relationships	35,430		33,268		2,162		35,430		32,044		3,386
Intangibles associated with lease	13,260		4,341		8,919		13,260		3,986		9,274
Segment total	48,690		37,609		11,081		48,690		36,030		12,660
Marine contract intangibles	27,000		4,950		22,050		27,000		900		26,100
Offshore pipeline contract intangibles	158,101		9,708		148,393		158,101		3,467		154,634
Other	28,240		9,918		18,322		22,819		8,120		14,699
Total	$	395,363	$	184,650	$	210,713	$	389,942	$	166,496	$	223,446

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Amortization of intangible assets	$	6,122	$	5,554	$	18,154	$	13,745

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



Remainder of	2016	$	6,169
	2017	$	23,532
	2018	$	21,361
	2019	$	17,026
	2020	$	16,125

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. Debt

Our obligations under debt arrangements consisted of the following:



	September 30, 2016						December 31, 2015
	Principal		Unamortized Discount and Debt Issuance Costs ⁽¹⁾		Net Value		Principal		Unamortized Discount and Debt Issuance Costs ⁽¹⁾		Net Value
Senior secured credit facility	$	1,167,000	$	—	$	1,167,000	$	1,115,000	$	—	$	1,115,000
6.000% senior unsecured notes due May 2023	400,000		7,024		392,976		400,000		7,825		392,175
5.750% senior unsecured notes due February 2021	350,000		4,418		345,582		350,000		5,183		344,817
5.625% senior unsecured notes due June 2024	350,000		6,838		343,162		350,000		7,510		342,490
6.750% senior unsecured notes due August 2022	750,000		20,087		729,913		750,000		22,428		727,572
Total long-term debt	$	3,017,000	$	38,367	$	2,978,633	$	2,965,000	$	42,946	$	2,922,054

(1)

In April 2015, the FASB issued guidance that requires the presentation of debt issuance costs in financial statements as a direct reduction of related debt liabilities with amortization of debt issuance costs reported as interest expense. Under current U.S. GAAP standards, debt issuance costs are reported as deferred charges (i.e., as an asset). This guidance is effective for annual periods, and interim periods within those fiscal years, beginning after December 15, 2015 and is to be applied retrospectively upon adoption. Early adoption is permitted, including adoption in an interim period for financial statements that have not been previously issued. Genesis adopted this guidance in the fourth quarter of 2015.

As of September 30, 2016, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Senior Secured Credit Facility

In April 2016, we amended our credit agreement to, among other things, (i) increase the committed amount under our revolving credit facility to $1.7 billion (from $1.5 billion), with the ability to increase the committed amount by an additional $300.0 million, subject to lender consent and (ii) permanently relax the maximum consolidated leverage ratio to 5.5 to 1.0.

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 2.75% on Eurodollar borrowings and from 0.50% to 1.75% on alternate base rate borrowings.

•Letter of credit fees range from 1.50% to 2.50%

•The commitment fee on the unused committed amount will range from 0.250% to 0.500%.

•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 September 30, 2016, we had $1.2 billion borrowed under our $1.7 billion credit facility, with $48.0 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 $6.0 million was outstanding at September 30, 2016. 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 September 30, 2016 was $527.0 million.

9. Partners’ Capital and Distributions

At September 30, 2016, our outstanding common units consisted of 117,939,221 Class A units and 39,997 Class B units.

On July 27, 2016, we issued 8,000,000 Class A common units in a public offering at a price of $37.90 per unit. We received the proceeds, net of underwriting discounts and offering costs, of $298.0 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 2015 and 2016:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2015
1^st Quarter	May 15, 2015		$	0.6100	$	60,774
2^nd Quarter	August 14, 2015		$	0.6250	$	68,737
3^rd Quarter	November 13, 2015		$	0.6400	$	70,387
4^th Quarter	February 12, 2016		$	0.6550	$	72,036
2016
1^st Quarter	May 13, 2016		$	0.6725	$	73,961
2^nd Quarter	August 12, 2016		$	0.6900	$	81,406
3^rdQuarter	November 14, 2016	⁽¹⁾	$	0.7000	$	82,585

(1) This distribution will be paid to unitholders of record as of October 28, 2016.

10. Business Segment Information

We currently manage our businesses through five 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;


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


•	Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and selling the related by-product, NaHS;


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


•	Supply and Logistics – terminaling, blending, storing, marketing and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and, on a smaller scale, CO₂.

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

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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the periods presented below was as follows:



	Offshore Pipeline Transportation		Onshore Pipeline Transportation		Refinery Services			Marine Transportation		Supply & Logistics			Total
Three Months Ended September 30, 2016
Segment margin (a)	$	86,557	$	10,603	$	20,526		$	16,697	$	6,957		$	141,340
Capital expenditures (b)	$	3,977	$	54,968	$	488		$	26,937	$	30,380		$	116,750
Revenues:
External customers	$	89,717	$	10,846	$	48,069		$	53,573	$	257,845		$	460,050
Intersegment (c)	—		3,153		(2,344		)	1,712		(2,521		)	—
Total revenues of reportable segments	$	89,717	$	13,999	$	45,725		$	55,285	$	255,324		$	460,050
Three Months Ended September 30, 2015
Segment margin (a)	$	70,943	$	14,984	$	20,692		$	26,583	$	7,508		$	140,710
Capital expenditures (b)	$	1,520,268	$	45,933	$	118		$	12,489	$	43,942		$	1,622,750
Revenues:
External customers	$	61,388	$	16,735	$	45,738		$	58,490	$	389,983		$	572,334
Intersegment (c)	—		3,174		(2,406		)	2,046		(2,814		)	—
Total revenues of reportable segments	$	61,388	$	19,909	$	43,332		$	60,536	$	387,169		$	572,334
Nine Months Ended September 30, 2016
Segment Margin (a)	$	249,457	$	38,370	$	61,586		$	53,695	$	25,599		$	428,707
Capital expenditures (b)	$	35,175	$	156,977	$	1,645		$	62,928	$	101,704		$	358,429
Revenues:
External customers	$	242,672	$	36,356	$	136,437		$	155,197	$	713,778		$	1,284,440
Intersegment (c)	2,165		12,044		(6,852		)	4,733		(12,090		)	—
Total revenues of reportable segments	$	244,837	$	48,400	$	129,585		$	159,930	$	701,688		$	1,284,440
Nine Months Ended September 30, 2015
Segment Margin (a)	$	121,241	$	43,670	$	60,073		$	79,501	$	28,913		$	333,398
Capital expenditures (b)	$	1,522,407	$	155,417	$	1,568		$	40,151	$	136,568		$	1,856,111
Revenues:
External customers	$	63,436	$	48,422	$	142,959		$	173,733	$	1,326,968		$	1,755,518
Intersegment (c)	—		9,488		(7,179		)	6,768		(9,077		)	—
Total revenues of reportable segments	$	63,436	$	57,910	$	135,780		$	180,501	$	1,317,891		$	1,755,518

Total assets by reportable segment were as follows:



	September 30, 2016		December 31, 2015
Offshore pipeline transportation	$	2,595,408	$	2,623,478
Onshore pipeline transportation	706,589		614,484
Refinery services	390,169		394,626
Marine transportation	813,282		777,952
Supply and logistics	1,107,798		1,000,851
Other assets	42,238		48,208
Total consolidated assets	5,655,484		5,459,599


(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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

contributions to equity investees related to same. In addition to construction of growth projects, capital spending in our Offshore Pipeline Transportation Segment included $2.5 million during the nine months ended September 30, 2015 representing capital contributions to SEKCO, which was an equity investee at that time, to fund our share of the construction costs for its pipeline. We acquired the remaining 50% interest in SEKCO in July 2015.


(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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Total Segment Margin	$	141,340		$	140,710		$	428,707		$	333,398
Corporate general and administrative expenses	(10,420		)	(25,940		)	(32,269		)	(52,192		)
Depreciation and amortization	(54,265		)	(41,170		)	(156,800		)	(96,500		)
Interest expense	(34,735		)	(29,617		)	(104,657		)	(66,737		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(9,063		)	(7,962		)	(30,818		)	(25,383		)
Non-cash items not included in Segment Margin	1,779			1,316			(5,428		)	473
Cash payments from direct financing leases in excess of earnings	(1,586		)	(1,448		)	(4,645		)	(4,215		)
Gain on step up of historical basis	—			335,260			—			335,260
Loss on extinguishment of debt	—			—			—			(19,225		)
Other, net	—			(6,643		)	—			(6,643		)
Income tax expense	(949		)	(1,292		)	(2,959		)	(3,142		)
Net income attributable to Genesis Energy, L.P.	$	32,101		$	363,214		$	91,131		$	395,094


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

11. 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	878	$	913	$	2,366	$	2,418
Revenues from provision of services to Poseidon Oil Pipeline Company, LLC ⁽²⁾	1,979		1,980		5,935		1,980
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	495	$	525
Charges for services from Poseidon Oil Pipeline Company, LLC ⁽²⁾	251		241		749		241


(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 September 30, 2016 and December 31, 2015 (i) Sandhill Group, LLC owed us $0.3 million and $0.3 million, respectively, for purchases of CO₂ and (ii) Poseidon Oil Pipeline Company, LLC owed us $1.5 million and $1.9 million, respectively, for services rendered.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Transactions with Unconsolidated Affiliates

Poseidon

As part of our Enterprise acquisition, we became the operator of Poseidon in the third quarter of 2015. We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three and nine months ended September 30, 2016 reflect $2.0 million and $5.9 million, respectively, of fees we earned through the provision of services under that agreement.

Deepwater Gateway

Deepwater Gateway, LLC, which became a wholly-owned subsidiary in the first quarter of 2016, no longer constitutes a related party.

12. Supplemental Cash Flow Information

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



	Nine Months Ended September 30,
	2016			2015
(Increase) decrease in:
Accounts receivable	$	11,029		$	72,372
Inventories	(26,215		)	(1,481		)
Deferred charges	(5,291		)	(7,256		)
Other current assets	5,184			(7,014		)
Increase (decrease) in:
Accounts payable	(27,213		)	(70,980		)
Accrued liabilities	(20,901		)	21,740
Net changes in components of operating assets and liabilities	(63,407		)	7,381

Payments of interest and commitment fees, net of amounts capitalized, were $125.1 million and $56.8 million for the nine months ended September 30, 2016 and September 30, 2015, respectively. We capitalized interest of $19.9 million and $11.9 million during the nine months ended September 30, 2016 and September 30, 2015.

At September 30, 2016 and September 30, 2015, we had incurred liabilities for fixed and intangible asset additions totaling $55.3 million and $50.2 million, respectively, that had not been paid at the end of the third 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.

13. 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.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 Consolidated Statements of Operations.

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

At September 30, 2016, 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)	1,058		—
Weighted average contract price per bbl	$	45.24	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	1,440		1,388
Weighted average contract price per bbl	$	44.77	$	44.96
Crude oil swaps:
Contract volumes (1,000 bbls)	—		60
Weighted average contract price per bbl	$	—	$	(1.88	)
Diesel futures:
Contract volumes (1,000 bbls)	18		—
Weighted average contract price per gal	$	1.41	$	—
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	105		45
Weighted average contract price per bbl	$	35.73	$	37.02
Crude oil options:
Contract volumes (1,000 bbls)	55		10
Weighted average premium received	$	1.55	$	0.36

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 September 30, 2016 and December 31, 2015:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	September 30, 2016			December 31, 2015
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	300		$	1,703
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(300		)	(388		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	1,315
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Current Assets - Other	$	4,924		$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(4,924		)	—
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,085	)	$	(388	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,085			388
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⁾	$	(8,097	)	$	(23	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	8,097			23
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—


(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 September 30, 2016, we had a net broker receivable of approximately $3.6 million (consisting of initial margin of $4.2 million and decreased by $0.6 million of variation margin). As of December 31, 2015, we had a net broker receivable of approximately $5.5 million (consisting of initial margin of $4.4 million increased by $1.1 million of variation margin). At September 30, 2016 and December 31, 2015, 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 September 30,					Nine Months Ended September 30,
		2016			2015		2016			2015
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	1,672		$	621	$	(8,279	)	$	(1,214	)
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	(262		)	11,559		(3,744		)	6,545
Total commodity derivatives		$	1,410		$	12,180	$	(12,023	)	$	5,331

14. 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 September 30, 2016 and December 31, 2015.



	Fair Value at							Fair Value at
	September 30, 2016							December 31, 2015
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	5,224		$	—	$	—	$	1,703		$	—	$	—
Liabilities	$	(9,182	)	$	—	$	—	$	(411	)	$	—	$	—

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 13 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 September 30, 2016 our senior unsecured notes had a carrying value of $1.8 billion and a fair value of $1.9 billion, compared to $1.8 billion and $1.5 billion, respectively, at December 31, 2015. 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.

Additionally, we recorded the estimated fair value of net assets acquired and liabilities assumed in connection with our Enterprise acquisition as of the acquisition date of July 24, 2015. The fair value measurements were primarily based on significant unobservable inputs (Level 3) developed using company-specific information. See Note 3 for further information associated with the values recorded in our Enterprise acquisition.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Additionally, the fair value measurements, using unobservable (Level 3) inputs, used in recording the estimated fair value of the net assets acquired and liabilities assumed of CHOPS and SEKCO (which we now own 100% interest in and consolidate given the respective 50% ownership interest acquired from Enterprise for each of these subsidiaries) as a result of our Enterprise acquisition were used to calculate the effects of the re-measurement of our pre-acquisition historical interest in CHOPS and SEKCO at fair value, based on accounting guidance involving step acquisitions as discussed in ASC 805-10-25.

15. 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.

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 8 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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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

September 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
ASSETS
Current assets:
Cash and cash equivalents	$	6	$	—	$	2,126		$	1,315		$	—		$	3,447
Other current assets	75		—		296,951			11,694			(391		)	308,329
Total current assets	81		—		299,077			13,009			(391		)	311,776
Fixed assets, at cost	—		—		4,630,100			77,585			—			4,707,685
Less: Accumulated depreciation	—		—		(485,827		)	(23,592		)	—			(509,419		)
Net fixed assets	—		—		4,144,273			53,993			—			4,198,266
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	11,734		—		393,117			135,283			(136,952		)	403,182
Advances to affiliates	2,565,346		—		—			66,110			(2,631,456		)	—
Equity investees	—		—		417,214			—			—			417,214
Investments in subsidiaries	2,620,102		—		90,214			—			(2,710,316		)	—
Total assets	$	5,197,263	$	—	$	5,668,941		$	268,395		$	(5,479,115	)	$	5,655,484
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	27,801	$	—	$	214,404		$	150		$	(136	)	$	242,219
Senior secured credit facility	1,167,000		—		—			—			—			1,167,000
Senior unsecured notes	1,811,633		—		—			—			—			1,811,633
Deferred tax liabilities	—		—		24,644			—			—			24,644
Advances from affiliates	—		—		2,631,455			—			(2,631,455		)	—
Other liabilities	—		—		185,481			179,191			(136,793		)	227,879
Total liabilities	3,006,434		—		3,055,984			179,341			(2,768,384		)	3,473,375
Partners’ capital, common units	2,190,829		—		2,612,957			97,774			(2,710,731		)	2,190,829
Noncontrolling interests	—		—		—			(8,720		)	—			(8,720		)
Total liabilities and partners’ capital	$	5,197,263	$	—	$	5,668,941		$	268,395		$	(5,479,115	)	$	5,655,484

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2015



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	6	$	—	$	8,288		$	2,601		$	—		$	10,895
Other current assets	50		—		285,313			10,422			(364		)	295,421
Total current assets	56		—		293,601			13,023			(364		)	306,316
Fixed assets, at cost	—		—		4,232,641			77,585			—			4,310,226
Less: Accumulated depreciation	—		—		(356,530		)	(21,717		)	—			(378,247		)
Net fixed assets	—		—		3,876,111			55,868			—			3,931,979
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	13,140		—		394,294			140,409			(125,977		)	421,866
Advances to affiliates	2,619,493		—		—			47,034			(2,666,527		)	—
Equity investees	—		—		474,392			—			—			474,392
Investments in subsidiaries	2,353,804		—		90,741			—			(2,444,545		)	—
Total assets	$	4,986,493	$	—	$	5,454,185		$	256,334		$	(5,237,413	)	$	5,459,599
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	35,338	$	—	$	267,294		$	—		$	(496	)	$	302,136
Senior secured credit facility	1,115,000		—		—			—			—			1,115,000
Senior unsecured notes	1,807,054		—		—			—			—			1,807,054
Deferred tax liabilities	—		—		22,586			—			—			22,586
Advances from affiliates	—		—		2,666,527			—			(2,666,527		)	—
Other liabilities	—		—		150,877			167,006			(125,811		)	192,072
Total liabilities	2,957,392		—		3,107,284			167,006			(2,792,834		)	3,438,848
Partners’ capital, common units	2,029,101		—		2,346,901			97,678			(2,444,579		)	2,029,101
Noncontrolling interests	—		—		—			(8,350		)	—			(8,350		)
Total liabilities and partners’ capital	$	4,986,493	$	—	$	5,454,185		$	256,334		$	(5,237,413	)	$	5,459,599

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 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	$	—		$	—	$	89,717		$	—		$	—		$	89,717
Onshore pipeline transportation services	—			—		9,002			4,997			—			13,999
Refinery services	—			—		45,262			2,981			(2,518		)	45,725
Marine transportation	—			—		55,285			—			—			55,285
Supply and logistics	—			—		255,324			—			—			255,324
Total revenues	—			—		454,590			7,978			(2,518		)	460,050
COSTS AND EXPENSES:
Offshore pipeline transportation operating costs	—			—		22,533			589			—			23,122
Onshore pipeline transportation operating costs	—			—		4,748			255			—			5,003
Refinery services operating costs	—			—		24,577			3,018			(2,518		)	25,077
Marine transportation costs	—			—		38,490			—			—			38,490
Supply and logistics costs	—			—		247,702			—			—			247,702
General and administrative	—			—		11,212			—			—			11,212
Depreciation and amortization	—			—		53,640			625			—			54,265
Total costs and expenses	—			—		402,902			4,487			(2,518		)	404,871
OPERATING INCOME	—			—		51,688			3,491			—			55,179
Equity in earnings of subsidiaries	66,811			—		28			—			(66,839		)	—
Equity in earnings of equity investees	—			—		12,488			—			—			12,488
Interest (expense) income, net	(34,710		)	—		3,595			(3,620		)	—			(34,735		)
Other income/(expense), net	—			—		—			—			—			—
Income before income taxes	32,101			—		67,799			(129		)	(66,839		)	32,932
Income tax expense	—			—		(949		)	—			—			(949		)
NET INCOME	32,101			—		66,850			(129		)	(66,839		)	31,983
Net loss attributable to noncontrolling interest	—			—		—			118			—			118
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	32,101		$	—	$	66,850		$	(11	)	$	(66,839	)	$	32,101

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2015



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	59,695		$	1,693		$	—		$	61,388
Onshore pipeline transportation services	—			—		14,130			5,779			—			19,909
Refinery services	—			—		42,464			2,608			(1,740		)	43,332
Marine transportation	—			—		60,536			—			—			60,536
Supply and logistics	—			—		387,169			—			—			387,169
Total revenues	—			—		563,994			10,080			(1,740		)	572,334
COSTS AND EXPENSES:
Offshore pipeline transportation operating costs	—			—		17,188			510			—			17,698
Onshore pipeline transportation operating costs	—			—		6,533			188			—			6,721
Refinery services operating costs	—			—		21,758			2,376			(1,771		)	22,363
Marine transportation costs	—			—		33,869			—			—			33,869
Supply and logistics costs	—			—		378,916			—			—			378,916
General and administrative	—			—		26,799			—			—			26,799
Depreciation and amortization	—			—		40,320			850			—			41,170
Total costs and expenses	—			—		525,383			3,924			(1,771		)	527,536
OPERATING INCOME	—			—		38,611			6,156			31			44,798
Equity in earnings of subsidiaries	392,769			—		2,284			—			(395,053		)	—
Equity in earnings of equity investees	—			—		14,260			—			—			14,260
Gain on basis step up on historical interest	—			—		335,260			—			—			335,260
Interest (expense) income, net	(29,576		)	—		3,728			(3,769		)	—			(29,617		)
Other income/(expense), net	21			—		(21		)	—			—			—
Income before income taxes	363,214			—		394,122			2,387			(395,022		)	364,701
Income tax (expense) benefit	—			—		(1,341		)	49			—			(1,292		)
NET INCOME	363,214			—		392,781			2,436			(395,022		)	363,409
Net loss attributable to noncontrolling interest	—			—		—			(195		)	—			(195		)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	363,214		$	—	$	392,781		$	2,241		$	(395,022	)	$	363,214

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 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	$	—		$	—	$	244,837		$	—		$	—		$	244,837
Onshore pipeline transportation services	—			—		32,872			15,528			—			48,400
Refinery services	—			—		129,671			5,499			(5,585		)	129,585
Marine transportation	—			—		159,930			—			—			159,930
Supply and logistics	—			—		701,688			—			—			701,688
Total revenues	—			—		1,268,998			21,027			(5,585		)	1,284,440
COSTS AND EXPENSES:
Offshore pipeline transportation operating costs	—			—		61,882			1,850			—			63,732
Onshore pipeline transportation operating costs	—			—		16,668			831			—			17,499
Refinery services operating costs	—			—		67,190			6,036			(5,585		)	67,641
Marine transportation costs	—			—		105,942			—			—			105,942
Supply and logistics costs	—			—		675,095			—			—			675,095
General and administrative	—			—		34,716			—			—			34,716
Depreciation and amortization	—			—		154,925			1,875			—			156,800
Total costs and expenses	—			—		1,116,418			10,592			(5,585		)	1,121,425
OPERATING INCOME	—			—		152,580			10,435			—			163,015
Equity in earnings of subsidiaries	195,674			—		(50		)	—			(195,624		)	—
Equity in earnings of equity investees	—			—		35,362			—			—			35,362
Interest (expense) income, net	(104,543		)	—		10,861			(10,975		)	—			(104,657		)
Income before income taxes	91,131			—		198,753			(540		)	(195,624		)	93,720
Income tax expense	—			—		(2,956		)	(3		)	—			(2,959		)
NET INCOME	91,131			—		195,797			(543		)	(195,624		)	90,761
Net loss attributable to noncontrolling interest	—			—		—			370			—			370
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	91,131		$	—	$	195,797		$	(173	)	$	(195,624	)	$	91,131

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2015



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
REVENUES:
Offshore pipeline transportation services	$	—		$	—	$	61,743		$	1,693		$	—		$	63,436
Onshore pipeline transportation services	—			—		39,874			18,036			—			57,910
Refinery services	—			—		133,055			10,579			(7,854		)	135,780
Marine transportation	—			—		180,501			—			—			180,501
Supply and logistics	—			—		1,317,891			—			—			1,317,891
Total revenues	—			—		1,733,064			30,308			(7,854		)	1,755,518
COSTS AND EXPENSES:
Offshore pipeline transportation operating costs	—			—		17,831			510			—			18,341
Onshore pipeline transportation operating costs	—			—		19,345			529			—			19,874
Refinery services operating costs	—			—		73,058			10,021			(7,854		)	75,225
Marine transportation costs	—			—		100,749			—			—			100,749
Supply and logistics costs	—			—		1,290,980			—			—			1,290,980
General and administrative	—			—		54,852			—			—			54,852
Depreciation and amortization	—			—		94,365			2,135			—			96,500
Total costs and expenses	—			—		1,651,180			13,195			(7,854		)	1,656,521
OPERATING INCOME	—			—		81,884			17,113			—			98,997
Equity in earnings of subsidiaries	480,953			—		5,770			—			(486,723		)	—
Equity in earnings of equity investees	—			—		48,440			—			—			48,440
Gain on basis step up on historical interest	—			—		335,260			—			—			335,260
Interest (expense) income, net	(66,655		)	—		11,329			(11,411		)	—			(66,737		)
Other income/(expense), net	(19,204		)	—		1,675			—			—			(17,529		)
Income before income taxes	395,094			—		484,358			5,702			(486,723		)	398,431
Income tax (expense) benefit	—			—		(3,275		)	133			—			(3,142		)
NET INCOME	395,094			—		481,083			5,835			(486,723		)	395,289
Net loss attributable to noncontrolling interest	—			—		—			(195		)	—			(195		)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	395,094		$	—	$	481,083		$	5,640		$	(486,723	)	$	395,094

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 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	$	122,884		$	—	$	310,723		$	6,781		$	(211,991	)	$	228,397
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(363,218		)	—			—			(363,218		)
Cash distributions received from equity investees - return of investment	—			—		16,652			—			—			16,652
Investments in equity investees	(298,051		)	—		—			—			298,051			—
Acquisitions	—			—		(25,394		)	—			—			(25,394		)
Intercompany transfers	54,148			—		—			—			(54,148		)	—
Repayments on loan to non-guarantor subsidiary	—			—		4,526			—			(4,526		)	—
Contributions in aid of construction costs	—			—		12,208			—			—			12,208
Proceeds from asset sales	—			—		3,303			—			—			3,303
Other, net	—			—		185			—			—			185
Net cash used in investing activities	(243,903		)	—		(351,738		)	—			239,377			(356,264		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	883,600			—		—			—			—			883,600
Repayments on senior secured credit facility	(831,600		)	—		—			—			—			(831,600		)
Debt issuance costs	(1,578		)	—		—			—			—			(1,578		)
Intercompany transfers	—			—		(35,144		)	(19,004		)	54,148			—
Issuance of common units for cash, net	298,051			—		298,051			—			(298,051		)	298,051
Distributions to partners/owners	(227,454		)	—		(227,454		)	—			227,454			(227,454		)
Other, net	—			—		(600		)	10,937			(10,937		)	(600		)
Net cash provided by financing activities	121,019			—		34,853			(8,067		)	(27,386		)	120,419
Net decrease in cash and cash equivalents	—			—		(6,162		)	(1,286		)	—			(7,448		)
Cash and cash equivalents at beginning of period	6			—		8,288			2,601			—			10,895
Cash and cash equivalents at end of period	$	6		$	—	$	2,126		$	1,315		$	—		$	3,447

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2015



	Genesis Energy, L.P. (Parent and Co-Issuer)			Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
Net cash provided by operating activities	$	(53,478	)	$	—	$	201,305		$	51,028		$	(6,727	)	$	192,128
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(359,504		)	—			—			(359,504		)
Cash distributions received from equity investees - return of investment	179,267			—		19,360			—			(179,267		)	19,360
Investments in equity investees	(633,761		)	—		(2,900		)	—			633,761			(2,900		)
Acquisitions	—			—		(1,517,428		)	—			—			(1,517,428		)
Intercompany transfers	(1,164,821		)	—		—			—			1,164,821			—
Repayments on loan to non-guarantor subsidiary	—			—		(1,077		)	—			1,077			—
Proceeds from asset sales	—			—		2,571			—			—			2,571
Other, net	—			—		(2,137		)	—			—			(2,137		)
Net cash used in investing activities	(1,619,315		)	—		(1,861,115		)	—			1,620,392			(1,860,038		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,168,850			—		—			—			—			1,168,850
Repayments on senior secured credit facility	(705,150		)	—		—			—			—			(705,150		)
Proceeds from issuance of senior unsecured notes	1,139,718			—		—			—			—			1,139,718
Repayment of senior unsecured notes	(350,000		)	—		—			—			—			(350,000		)
Debt issuance costs	(28,361		)	—		—			—			—			(28,361		)
Intercompany transfers	—			—		1,215,585			(50,764		)	(1,164,821		)	—
Issuance of common units for cash, net	633,759			—		633,759			—			(633,759		)	633,759
Distributions to partners/owners	(186,026		)	—		(186,026		)	—			186,026			(186,026		)
Distributions to noncontrolling interest	—			—		(560		)	—			—			(560		)
Other, net	—			—		1,786			1,111			(1,111		)	1,786
Net cash provided by financing activities	1,672,790			—		1,664,544			(49,653		)	(1,613,665		)	1,674,016
Net (decrease) increase in cash and cash equivalents	(3		)	—		4,734			1,375			—			6,106
Cash and cash equivalents at beginning of period	9			—		8,310			1,143			—			9,462
Cash and cash equivalents at end of period	$	6		$	—	$	13,044		$	2,518		$	—		$	15,568

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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, 2015.

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 $32.1 million, or $0.28 per common unit, during the three months ended September 30, 2016 (“2016 Quarter”) compared to net income attributable to Genesis Energy, L.P. of $363.2 million, or $3.38 per common unit, during the three months ended September 30, 2015 (“2015 Quarter”). This decrease principally relates to the $335 million non-cash gain we recognized during the 2015 Quarter resulting from a step up in basis to fair value of our historical interests in certain of our equity investees (CHOPS and SEKCO) as a result of our acquiring the remaining interest in those equity investees when we completed our Enterprise acquisition in July 2015. Exclusive of that 2015 non-cash gain, our net income attributable to Genesis Energy, L.P. of $32.1 million for the 2016 Quarter would be compared to net income attributable to Genesis Energy, L.P. of $28.0 million for the 2015 Quarter, representing an increase of $4.1 million or 15%.

That $4.1 million increase in our quarterly net income was principally due to contributions from the offshore Gulf of Mexico assets we acquired from Enterprise in July 2015. Those contributions were partially offset by an increase in interest expense due to an increase in our average outstanding indebtedness from acquired and constructed assets (primarily related to the financing of the offshore Gulf of Mexico assets we acquired from Enterprise), an increase in depreciation expense for assets acquired or placed into service (including those offshore Gulf of Mexico assets) and decreases in contributions from segments other than our Offshore Pipeline Transportation Segment.

Cash flow from operating activities was $124.7 million for the 2016 Quarter compared to $121.0 million for the 2015 Quarter.

Available Cash before Reserves was $95.0 million for the 2016 Quarter, a decrease of $1.3 million, or 1%, from the 2015 Quarter. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Segment Margin was $141.3 million for the 2016 Quarter, an increase of $0.6 million, or 0.4%, from the 2015 Quarter.

The increases in our net income (exclusive of the $335 million non-cash gain in the 2015 Quarter as discussed above) and Segment Margin resulted primarily from increases attributable to our Offshore Pipeline Transportation Segment partially offset by smaller decreases in our other segments.

Our diversified, yet increasingly integrated, businesses continued to perform in the 2016 Quarter within an acceptable range in spite of the ongoing dislocations in the energy sector, uncertainties in capital markets and the midstream space, and specific challenges, at the margin, on certain of our operations. Even if this challenging backdrop continues in future quarters, we would expect to see sequentially higher net income and Available Cash before Reserves due to a variety of factors, including increasing volumes out of the deepwater Gulf of Mexico, the end of certain refinery turnarounds, and the initiation of service, and the anticipated ramp up of volumes between now and the end of 2017, from some of our recent organic projects. In the aggregate, we believe our commercial operations are relatively stable in this challenging environment and we believe we have a reasonably clear line of sight of volume growth over the next four to six quarters. As a result, we feel comfortable that our financial results and condition will continue to strengthen in future periods.

Our primary objective continues to be to deliver the best value to our unitholders while never wavering from our commitment to safe and responsible operations. A lot has changed, we recognize, in how the market apparently values unit prices for MLPs or other midstream entities over the last year and a half to two years. Although the move to eliminate our IDRs almost six years ago and continuing to deliver double-digit growth in distributions on a year over year basis were rewarded historically, we believe the metrics demanded by the markets have changed during these recent tumultuous times.

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We now believe the best way to promote unit price appreciation under current conditions is to exercise strong financial discipline designed primarily to maintain and enhance our financial flexibility across the business cycle. Although we believe we would otherwise naturally restore our financial flexibility with cash flows from operations, we feel we can accelerate that process by issuing additional equity, lowering the future growth rate of quarterly distributions, or pursuing a combination of the two.

Consequently, on July 27, 2016, we closed a public offering of 8,000,000 common units generating net proceeds of approximately $298.0 million. As a practical matter, we would have issued such additional equity a year ago at the time of closing our Enterprise acquisition had markets been stronger at that point. This 2016 equity raise instantly improved our liquidity and credit metrics.

We believe our increased liquidity and even stronger balance sheet resulting from such actions should combine to give us the flexibility to continue to pursue acquisitions and/or organic projects that we feel are consistent with delivering long term value to all of our stakeholders. We also believe that our improved credit profile will significantly lower the future costs of refinancing our public debt when certain tranches become due beginning in 2021 or callable beginning in 2017.

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

Distribution Increase

In October 2016, we declared our forty-fifth consecutive increase in our quarterly distribution to our common unitholders. In November 2016, we will pay a distribution of $0.70 per unit related to the 2016 Quarter.

July 2016 Public Offering of Common Units

On July 27, 2016, we issued 8,000,000 Class A common units in a public offering at a price of $37.90 per unit. We received proceeds, net of underwriting discounts and offering costs, of $298.0 million from that offering. We used those proceeds to repay a portion of the borrowings outstanding under our revolving credit facility, allowing us greater financial flexibility to fund future activities.

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2016 Quarter decreased $112.3 million, or 20%, from the 2015 Quarter. Additionally, our costs and expenses decreased $122.7 million, or 23%, between the two periods.

A substantial majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products through our Supply and Logistics Segment. The significant decrease in our revenues and costs between the two third quarter periods is primarily attributable to decreases in market prices for such purchases and sales. 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 oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. The same correlation would be true in the case of higher crude oil and petroleum products prices.

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 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”.

Although prices of crude oil have partially recovered since December 31, 2015, prices were lower in the three and nine month periods ending on September 30, 2016 compared to the same periods in 2015. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased 3% to $44.94 per barrel in the third quarter of 2016, as compared to $46.43 per barrel in the third quarter of 2015. 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, producing minimal direct impact on Segment Margin from those operations. However, due to the indirect exposure to changes in prices discussed above and in the discussion surrounding our Supply and Logistics Segment, crude oil and petroleum product sales volumes decreased 28% in the 2016 quarter as compared to the 2015 quarter.

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We currently have two distinct, complementary types of operations-(i) our onshore-based refinery-centric crude oil and refined petroleum products transportation, supply and 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 approximately 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 nine months ended September 30, 2016 and September 30, 2015 was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Offshore pipeline transportation	86,557		70,943		$	249,457	$	121,241
Onshore pipeline transportation	10,603		14,984		38,370		43,670
Refinery services	20,526		20,692		61,586		60,073
Marine transportation	16,697		26,583		53,695		79,501
Supply and logistics	6,957		7,508		25,599		28,913
Total Segment Margin	$	141,340	$	140,710	$	428,707	$	333,398

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 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 and amortization, interest expense, certain non-cash items, the non-cash effects of our stock appreciation rights plan and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Total Segment Margin	$	141,340		$	140,710		$	428,707		$	333,398
Corporate general and administrative expenses	(10,420		)	(25,940		)	(32,269		)	(52,192		)
Depreciation and amortization	(54,265		)	(41,170		)	(156,800		)	(96,500		)
Interest expense	(34,735		)	(29,617		)	(104,657		)	(66,737		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(9,063		)	(7,962		)	(30,818		)	(25,383		)
Non-cash items not included in Segment Margin	1,779			1,316			(5,428		)	473
Cash payments from direct financing leases in excess of earnings	(1,586		)	(1,448		)	(4,645		)	(4,215		)
Gain on step up of historical basis	—			335,260			—			335,260
Loss on debt extinguishment	—			—			—			(19,225		)
Other, net	—			(6,643		)	—			(6,643		)
Income tax expense	(949		)	(1,292		)	(2,959		)	(3,142		)
Net income attributable to Genesis Energy, L.P.	$	32,101		$	363,214		$	91,131		$	395,094

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

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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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)						(in thousands)
Offshore crude oil pipeline revenue	$	69,759		$	47,431		$	199,391		$	49,479
Offshore natural gas pipeline revenue	19,957			13,957			45,445			13,957
Offshore pipeline operating costs, excluding non-cash expenses	(20,292		)	(17,698		)	(54,463		)	(18,341		)
Distributions from equity investments	20,880			21,791			64,502			71,541
Other	(3,747		)	5,462			(5,418		)	4,605
Offshore Pipeline Transportation Segment Margin ⁽¹⁾	$	86,557		$	70,943		$	249,457		$	121,241

Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	190,613			176,479			200,753			171,774
Poseidon	263,519			264,862			259,446			256,277
Odyssey	107,252			90,419			106,622			63,536
GOPL ⁽²⁾	6,287			17,049			5,839			14,028
Total crude oil offshore pipelines	567,671			548,809			572,660			505,615

SEKCO ⁽³⁾	82,022			78,008			73,225			56,962
Natural gas transportation volumes (MMBtus/d)	775,546			727,295			656,452			727,295

Volumetric Data net to our ownership interest ⁽⁴⁾:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	190,613			176,479			200,753			171,774
Poseidon	168,652			169,512			166,045			164,017
Odyssey	31,103			26,222			30,920			18,425
GOPL ⁽²⁾	6,287			17,049			5,839			14,028
Total crude oil offshore pipelines	396,655			389,262			403,557			368,244

SEKCO ⁽³⁾	82,022			78,008			73,225			56,962
Natural gas transportation volumes (MMBtus/d)	502,792			448,043			374,950			448,043

(1)

Segment Margin for the three and nine months ended September 30, 2016 includes approximately $21 million and $65 million, respectively, of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting. Segment Margin for the three months and nine months ended September 30, 2015 includes $22 million and $72 million, respectively, in similar distributions from our offshore pipeline joint ventures.


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

(3)

Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO’s transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude oil until January 2015. Volumes reported for the three months and nine months ended September 30, 2016 for SEKCO reflect the gradual commencement of throughput beginning in January of 2015. Even though our SEKCO volumes flow through both SEKCO and Poseidon, we include those volumes only once in the table above.


(4)	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.

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Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

Offshore Pipeline Transportation Segment Margin for the 2016 Quarter increased $15.6 million, or 22%, from the 2015 Quarter. This increase is primarily due to our acquisition from Enterprise, which closed on July 24, 2015. As a result of our Enterprise acquisition, we obtained interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines (including increasing our ownership interest in each of the Poseidon, SEKCO, and CHOPS pipelines) and six offshore hub platforms. The operating results of the offshore pipeline assets acquired from Enterprise continue to meet or exceed our expectations, with a net increase in volumes (compared to the third quarter of 2015) for the most significant of those offshore crude oil pipelines.

Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

Offshore Pipeline Transportation Segment Margin for the first nine months of 2016 increased $128.2 million, or 106%, from the first nine months of 2015. This increase is primarily due to our acquisition from Enterprise, which closed on July 24, 2015. As a result of our Enterprise acquisition, we obtained interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines (including increasing our ownership interest in each of the Poseidon, SEKCO, and CHOPS pipelines) and six offshore hub platforms. The operating results of the offshore pipeline assets acquired from Enterprise continue to meet or exceed our expectations, with a net increase in volumes (compared to the nine months ended September 30, 2015) for the most significant of those offshore crude oil pipelines.

Onshore Pipeline Transportation Segment

Operating results and volumetric data for our Onshore Pipeline Transportation Segment are presented below:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	8,102		$	11,926		$	28,917		$	32,464
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	5,117			5,882			15,856			18,358
Sales of onshore crude oil pipeline loss allowance volumes	790			1,172			2,678			3,775
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(4,984		)	(5,667		)	(16,712		)	(15,872		)
Payments received under direct financing leases not included in income	1,586			1,448			4,645			4,215
Other	(8		)	223			2,986			730
Segment Margin	$	10,603		$	14,984		$	38,370		$	43,670

Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	11,529			68,675			41,708			70,815
Jay	15,119			17,547			14,494			17,041
Mississippi	9,503			16,963			10,607			16,246
Louisiana	30,814			38,738			26,865			28,042
Wyoming	9,772			7,702			10,003			7,702
Onshore crude oil pipelines total	76,737			149,625			103,677			139,846

CO₂ pipeline (average Mcf/day):
Free State	88,026			145,947			101,157			167,805

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Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

Onshore Pipeline Transportation Segment Margin for the 2016 Quarter decreased $4.4 million, or 29%. Certain significant components and details of this change were as follows:

•

With respect to our onshore crude oil pipelines, tariff revenues decreased quarter to quarter principally due to a net decrease in throughput volumes of 72,888 barrels per day or 49%. This was primarily the result of decreased volumes on our Texas pipeline system, particularly delivery volumes to the Texas City refining market. We believe such lower volumes to historical customers will last indefinitely as those customers have made alternative arrangements as a result of our endeavors to expand, extend and repurpose our facilities into longer lived, higher value service. In addition, our Louisiana system experienced lower volumes between the respective quarters, as a major refinery customer emerged from a turnaround during the 2016 Quarter. As such, we anticipate a ramp up in such volumes during the fourth quarter. Volume variances on our other onshore pipeline systems had a less significant impact on the decrease in tariff revenues between the respective quarters due to a mix of tariff rates amongst these systems and less significant decreases in volumes. These factors, impacting both crude oil volumes and tariff revenues, resulted in a $3.8 million decrease in Segment Margin compared to the 2015 Quarter.

•

Although volumes on our Free State CO₂ pipeline system decreased 57,921 Mcf per day, or 40%, in the 2016 Quarter as compared to the 2015 Quarter due to lower levels of tertiary crude oil activities in Mississippi, that decrease had a much smaller effect on the contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which results in the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a base level on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

Onshore Pipeline Transportation Segment Margin for the first nine months of 2016 decreased $5.3 million, or 12%. Certain significant components and details of this change were as follows:

•

With respect to our onshore crude oil pipelines, tariff revenues decreased by $3.5 million period to period principally due to a net decrease in throughput volumes of 36,169 barrels per day, or 26%. This was primarily the result of decreased volumes on our Texas pipeline system, particularly delivery volumes to the Texas City refining market. We believe such lower volumes to historical customers will last indefinitely as those customers have made alternative arrangements as a result of our endeavors to expand, extend and repurpose our facilities into longer lived, higher value service. Volume variances on our other onshore pipeline systems had a less significant impact on the decrease in tariff revenues between the respective quarters due to a mix of tariff rates amongst these systems and less significant decreases in volumes. These factors, when combined with lower sales of pipeline loss allowance volumes, resulted in a $4.6 million decrease in Segment Margin compared to the nine months ended September 30, 2015.

•

Although volumes on our Free State CO₂ pipeline system decreased 66,648 Mcf per day, or 40%, in the first nine months of 2016 compared to the first nine months of 2015 due to lower levels of tertiary crude oil activities in Mississippi, that decrease had a much smaller effect on the contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which results in the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a base level on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

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Refinery Services Segment

Operating results for our Refinery Services Segment were as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Volumes sold (in Dry short tons "DST"):
NaHS volumes	34,299		30,721		96,116		95,654
NaOH (caustic soda) volumes	19,653		23,907		59,802		67,223
Total	53,952		54,628		155,918		162,877

Revenues (in thousands):
NaHS revenues	$	37,054	$	32,618	$	103,680	$	104,153
NaOH (caustic soda) revenues	9,872		11,329		28,816		33,217
Other revenues	1,143		1,791		3,941		5,589
Total external segment revenues	$	48,069	$	45,738	$	136,437	$	142,959

Segment Margin (in thousands)	$	20,526	$	20,692	$	61,586	$	60,073

Average index price for NaOH per DST ⁽¹⁾	$	661	$	563	$	618	$	576

(1) Source: IHS Chemical

Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

Refinery Services Segment Margin for the 2016 Quarter decreased $0.2 million, or 1%. Certain significant components and details of this change were as follows:


•	NaHS revenues increased 14% due primarily to an increase in NaHS sales volumes. This is principally related to an increase in sales volumes to our South American mining customers during the 2015 Quarter. Sales volumes between quarters to customers in South America can fluctuate due to the timing of third party vessels available to transport bulk deliveries.

•

The pricing in our sales contracts for NaHS typically includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which we are able to apply such adjustments may vary due to timing or other factors such as competitive pressures, which had a negative effect on margin realized from NaHS sales for the 2016 Quarter and partially offset the increase in NaHS sales volumes and revenues. We expect those other factors to continue.


•	Caustic soda revenues decreased 13% between the quarters primarily due to a reduction in our sales volumes. The impact on Segment Margin, compared to the 2015 Quarter, from these reduced caustic soda sales is approximately $1.0 million.

•

Average index prices for caustic soda increased to $661 per DST in the 2016 Quarter compared to $563 per DST during the 2015 Quarter. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. Typically, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. To the extent we are unable to pass these caustic soda price changes onto our customers, Segment Margin may be impacted. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

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Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

Refinery Services Segment Margin for the first nine months of 2016 increased $1.5 million, or 3%. Certain significant components and details of this change were as follows:

•

During the nine months ended September 30, 2016, we were able to realize more benefits from our favorable management of the purchasing (including economies of scale) and utilization of caustic soda in our (and our customers') operations and our logistics management capabilities, as compared to the nine months ended September 30, 2015. The fluctuation in NaHS revenues and volumes had a minimal impact on Segment Margin.


•	Caustic soda revenues decreased 13% primarily due to a reduction in our sales volumes. Fluctuation in caustic soda revenues and volumes had a minimal impact on Segment Margin for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015.

•

Average index prices for caustic soda increased to $618 per DST in the first nine months of 2016 compared to $576 per DST during the first nine months of 2015. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. Typically, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because the pricing in many of our sales contracts for NaHS typically includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which we are able to apply such adjustments may vary due to timing or other factors such as competitive pressures. To the extent we are unable to pass these caustic soda price changes onto our customers, Segment Margin may be impacted. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Marine Transportation Segment

Within our Marine Transportation Segment, we own a fleet of 82 barges (73 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues (in thousands):
Inland freight revenues	$	22,108		$	23,970		$	66,402		$	71,967
Offshore freight revenues	23,271			26,630			66,240			76,908
Other rebill revenues ⁽¹⁾	9,906			9,936			27,288			31,626
Total segment revenues	$	55,285		$	60,536		$	159,930		$	180,501

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	38,588		$	33,953		$	106,235		$	101,000

Segment Margin (in thousands)	$	16,697		$	26,583		$	53,695		$	79,501

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	87.6		%	97.6		%	91.4		%	97.7		%
Offshore Barge Utilization	96.2		%	99.9		%	91.2		%	99.8		%

(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.

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Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

Marine Transportation Segment Margin for the 2016 Quarter decreased $9.9 million, or 37%, from the 2015 Quarter. The decrease in Segment Margin is primarily due to a combination of lower utilization and lower day rates across our various marine asset classes, excepting the M/T American Phoenix which is under long term contract through September 2020. In our offshore barge fleet, as a number of our units have come off longer term contracts, we have chosen to primarily place them in spot service or short-term (less than a year) service, as we believe the day rates currently being offered by the market are at, or approaching, cyclical lows. In our inland fleet, we saw somewhat of a strengthening in utilization and stabilization in spot day rates towards the end of the quarter, especially in the black oil, or heavy, intermediate refined products trade, the trade to which we have almost exclusively committed our inland barges.

Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

Marine Transportation Segment Margin for the first nine months of 2016 decreased $25.8 million, or 32%, from the first nine months of 2015. The decrease in Segment Margin is primarily due to a combination of lower utilization and lower day rates across our various marine asset classes, excepting the M/T American Phoenix which is under long term contract through September 2020. In our offshore barge fleet, as a number of our units have come off longer term contracts, we have chosen to primarily place them in spot service or short-term (less than a year) service, as we believe the day rates currently being offered by the market are at, or approaching, cyclical lows. In our inland fleet, we saw somewhat of a strengthening in utilization and stabilization in spot day rates towards the end of the quarter, especially in the black oil, or heavy, intermediate refined products trade, the trade to which we have almost exclusively committed our inland barges.

Supply and Logistics Segment

Our Supply and Logistics Segment is focused on utilizing our knowledge of the crude oil and petroleum markets to provide crude oil and natural gas producers, refiners and other customers with a full suite of services. Our Supply and Logistics Segment owns and/or leases trucks, terminals, gathering pipelines, railcars, and rail loading and unloading facilities. It uses those assets, together with other modes of transportation owned by third parties and us, to service its customers and for its own account. These services include:


•	utilizing the fleet of trucks, trailers and railcars owned or leased by our Supply and Logistics Segment to transport products (primarily crude oil and petroleum products) for customers;


•	utilizing various modes of transportation owned by third parties and us to transport products (primarily crude oil and petroleum products) for our own account to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;


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


•	supplying petroleum products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets;


•	purchasing products from refiners, transporting 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;


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


•	industrial gas activities, including wholesale marketing of CO₂and processing of syngas through a joint venture.

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 and sulfur content, among others. Refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help refineries in our areas of operation identify crude oil sources meeting their requirements and to purchase the crude oil and transport it to refineries for sale. The imbalances and inefficiencies relative to meeting refiners’ requirements can provide opportunities for us to utilize our skills and assets to meet their demands. The pricing in the majority of our purchase contracts contains a market price component and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts sometimes contain a grade differential which considers the 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 petroleum products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets. 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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We utilize our fleet of trucks, trailers, railcars, and leased and owned storage capacity to service our crude oil and refining customers and to store and blend the intermediate and finished refined products.

Operating results from our Supply and Logistics Segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)						(in thousands)
Supply and logistics revenue	$	255,324		$	387,169		$	701,688		$	1,317,891
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(230,760		)	(354,551		)	(621,500		)	(1,215,242		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(17,607		)	(24,772		)	(54,677		)	(73,607		)
Other	—			(338		)	88			(129		)
Segment Margin	$	6,957		$	7,508		$	25,599		$	28,913

Volumetric Data (average barrels per day):
Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	64,292			89,516			66,725			94,571
Rail load/unload volumes ⁽¹⁾	13,091			37,767			13,344			24,043

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

Three Months Ended September 30, 2016 Compared with Three Months Ended September 30, 2015

Segment Margin for our Supply and Logistics Segment decreased by $0.6 million, or 7%, between the two three month periods.

The decrease in our Segment Margin between the two quarters is primarily due to 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. We have found it difficult to compete with certain participants in the market who are willing to lose money on 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 and is unlikely to come online. In addition, a portion of this decrease can be attributed to decreased rail volumes. While rail volumes were down compared to the 2015 Quarter, our results reflect the beginning of a ramp up as a major refinery customer supported by our Baton Rouge facilities emerged from a refinery turnaround during the 2016 Quarter and we expect this ramp up to continue into the fourth quarter. These decreases were partially offset by the improved performance of our now right-sized heavy fuel oil business after reducing volumes and related infrastructure to match new market realities resulting from the general lightening of refineries' crude slates which has resulted in a better supply/demand balance between heavy refined bottoms and domestic coker and asphalt requirements.

Nine Months Ended September 30, 2016 Compared with Nine Months Ended September 30, 2015

Segment Margin for our Supply and Logistics Segment decreased by $3.3 million, or 11%, between the first nine months of 2016 and the first nine months of 2015.

The decrease in our Segment Margin between the two nine-month periods is primarily due to 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. We have found it difficult to compete with certain participants in the market who are willing to lose money on 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 and is unlikely to come online. In addition, a portion of this decrease can be attributed to decreased rail volumes. While rail volumes were down compared to the nine months ended September 30, 2015, our results reflect the beginning of a ramp up as a major refinery customer supported by our Baton Rouge facilities emerged from a refinery turnaround during the third quarter of 2016 and we expect this ramp up to continue into the fourth quarter. These decreases were partially offset by the improved performance of our now right-sized heavy fuel oil business after reducing volumes and related infrastructure to match new market realities resulting from the general lightening of refineries' crude slates which has resulted in a better supply/demand balance between heavy refined bottoms and domestic coker and asphalt requirements.

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Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	7,692	$	11,742	$	26,068	$	32,056
Segment	1,918		860		3,364		2,639
Equity-based compensation plan expense	1,239		1,431		3,918		4,982
Third party costs related to business development activities and growth projects	363		12,766		1,366		15,175
Total general and administrative expenses	$	11,212	$	26,799	$	34,716	$	54,852

Total general and administrative expenses decreased $15.6 million and $20.1 million between the three and nine month periods primarily due to higher third party costs, primarily financing, legal and accounting, related to business development and growth activities (primarily related to third party costs incurred for business development activities surrounding the Enterprise acquisition as previously discussed) and employee related costs relating to our annual bonus program incurred during the 2015 periods.

Depreciation and amortization expense



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in thousands)				(in thousands)
Depreciation expense	$	46,909	$	33,716	$	135,428	$	78,265
Amortization of intangible assets	6,122		5,554		18,154		13,745
Amortization of CO2 volumetric production payments	1,234		1,900		3,218		4,490
Total depreciation and amortization expense	$	54,265	$	41,170	$	156,800	$	96,500

Total depreciation and amortization expense increased $13.1 million and $60.3 million between the three and nine month periods primarily as a result of acquiring assets and placing constructed assets' in service during calendar 2015 (including the offshore pipelines and services assets acquired as a result of our Enterprise acquisition) and 2016.

Interest expense, net



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	11,076		$	6,888		$	31,117		$	15,054
Interest expense, senior unsecured notes	28,609			25,155			85,828			58,717
Amortization of debt issuance costs and discount	2,571			2,303			7,563			4,853
Capitalized interest	(7,521		)	(4,729		)	(19,851		)	(11,887		)
Net interest expense	$	34,735		$	29,617		$	104,657		$	66,737

Net interest expense increased $5.1 million and $37.9 million between the three and nine month periods primarily due to an increase in our average outstanding indebtedness from acquired and constructed assets, primarily related to additional debt outstanding as a result of financing our Enterprise acquisition. In July 2015, we issued an additional $750 million of aggregate principal amount of 6.75% senior unsecured notes to fund a portion of the purchase price for our Enterprise acquisition. Capitalized interest costs increased $2.8 million and $8.0 million over the three and nine month periods due to our growth capital expenditures for projects still under construction when compared to the prior year period.

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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.

Other

Net income for the three and nine months ended September 30, 2015 included a $335 million non-cash gain we recognized during the 2015 Quarter resulting from a step up in basis to fair value of our historical interests in certain of our equity investees (CHOPS and SEKCO) as a result of our acquiring the remaining interest in those equity investees when we completed our Enterprise acquisition in July 2015.

Liquidity and Capital Resources

General

As of September 30, 2016, we had $527.0 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 September 30, 2016, our long-term debt totaled $3.0 billion, consisting of $1.2 billion outstanding under our credit facility (including $48.0 million borrowed under the inventory sublimit tranche), a $350.0 million carrying amount of senior unsecured notes due on February 15, 2021, a $400.0 million carrying amount of senior unsecured notes due on May 15, 2023, a $350.0 million carrying amount of senior unsecured notes due on June 15, 2024, and a $750.0 million carrying amount of senior unsecured notes 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

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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 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 September 30, 2016, 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 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 12 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the nine months ended September 30, 2016 and September 30, 2015.

The increase in operating cash flow for the nine months ended September 30, 2016 compared to the same period in 2015 was primarily due to increases in earnings, including net income before depreciation and amortization. This primarily results from the contributions of the offshore Gulf of Mexico assets we acquired from Enterprise. This increase was partially offset by increases in working capital needs. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our working capital and, therefore, our operating cash flows between periods as the cost to acquire a barrel of oil or petroleum products will require more or less cash. Net cash flows provided by our operating activities for the nine months ended September 30, 2016 were $228.4 million compared to $192.1 million for the nine months ended September 30, 2015.

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 nine months ended September 30, 2016 and September 30, 2015 is as follows:



	Nine Months Ended September 30,
	2016		2015
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets	$	1,198	$	615
Onshore pipeline transportation assets	7,180		4,958
Refinery services assets	1,645		1,528
Marine transportation assets	11,358		24,719
Supply and logistics assets	2,298		6,807
Information technology systems	404		322
Total maintenance capital expenditures	24,083		38,949
Growth capital expenditures:
Offshore pipeline transportation assets	$	7,777	$	377
Onshore pipeline transportation assets	149,797		150,459
Refinery services assets	—		40
Marine transportation assets	51,570		15,432
Supply and logistics assets	99,406		129,761
Information technology systems	6,398		1,115
Total growth capital expenditures	314,948		297,184
Total capital expenditures for fixed and intangible assets	339,031		336,133
Capital expenditures for acquisitions, net of liabilities assumed:
Acquisition of offshore pipelines ⁽¹⁾	—		1,518,515
Acquisition of remaining interest in Deepwater Gateway ⁽²⁾	26,200		—
Total business combinations capital expenditures	26,200		1,518,515
Capital expenditures related to equity investees	—		2,900
Total capital expenditures	$	365,231	$	1,857,548


(1)	Amount represents our purchase price for our Enterprise acquisition.


(2)	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.

Growth Capital Expenditures

We anticipate spending approximately $65.0 million, inclusive of capitalized interest, during the remainder of 2016 for projects currently under construction. The most significant of our projects are described below.

Houston Area Crude Oil Pipeline and Terminal Infrastructure

We are constructing new, and expanding 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 are constructing a new crude oil pipeline that will deliver 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 will ultimately connect to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal will initially include approximately 750,000 barrels of crude oil tankage. As a part of this project, we are also making 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 will allow additional optionality to Houston and Baytown area refineries, including the Exxon-Mobil Baytown refinery, its largest refinery in the U.S.A., and provide additional delivery outlets for other crude oil pipelines. We expect these assets to become operational by the end of 2016.

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Wyoming Crude Oil Pipeline

In the third quarter of 2015, we completed construction of a new 60 mile crude oil pipeline to transport crude oil from new receipt point stations in Campbell County and Converse County, Wyoming to our existing Pronghorn Rail Facility. This new crude oil pipeline has an initial capacity of approximately 45,000 barrels per day and is supplied by truck volumes and third party gathering infrastructure in the Powder River Basin.

We also constructed a new 75 mile pipeline from our Pronghorn Rail Facility to a delivery point at our new Guernsey Station in Platte County, Wyoming. This Pronghorn to Guernsey pipeline has an initial capacity of approximately 45,000 barrels per day and will allow for connectivity to additional downstream pipeline markets at Guernsey, including regional refineries and Cushing, Oklahoma via the Pony Express Pipeline. This pipeline became operational in the first quarter of 2016.

Baton Rouge Terminal

We constructed a new crude oil, intermediates and refined products import/export terminal in Baton Rouge that will be located near the Port of Greater Baton Rouge and will be pipeline-connected to that port's existing deepwater docks on the Mississippi River. We constructed approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. In addition, we constructed a new pipeline from the terminal that will allow for deliveries to existing Exxon Mobil facilities in the area, as well as connect our previously constructed 17 mile line to the terminal allowing for receipts from the Scenic Station Rail Facility. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. Our Baton Rouge Terminal and related facilities became operational early in the fourth quarter of 2016.

Raceland Rail Facility

The Raceland Rail Facility, a new crude oil unit train unloading facility located in Raceland, Louisiana and capable of unloading up to two unit trains per day, will be connected to existing midstream infrastructure that will provide direct pipeline access to the Louisiana refining markets. It is expected to be operational by the end of 2016.

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 19 of those barges and 12 of those push boats through September 30, 2016. We expect to take delivery of those remaining vessels periodically through 2016 and 2017.

Maintenance Capital Expenditures

Our decrease in maintenance capital expenditures for the nine months ended September 30, 2016 as compared to September 30, 2015 primarily relates to our Marine Transportation Segment, where construction of new marine push boats, as completed in 2015, to replace older boats resulted in higher spending during 2015. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before reserves.

Distributions to Unitholders

On November 14, 2016, we will pay a distribution of $0.70 per common unit totaling $83 million with respect to the 2016 Quarter to common unitholders of record on October 28, 2016. This is the forty-fifth consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 9 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 September 30,
	2016			2015
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	32,101		$	363,214
Depreciation and amortization	54,265			41,170
Cash received from direct financing leases not included in income	1,586			1,448
Cash effects of sales of certain assets	120			343
Effects of distributable cash generated by equity method investees not included in income	9,063			7,962
Cash effects of legacy stock appreciation rights plan	(86		)	(50		)
Non-cash legacy stock appreciation rights plan expense	(113		)	(553		)
Expenses related to acquiring or constructing growth capital assets	363			12,766
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value	(571		)	(192		)
Maintenance capital utilized	(1,885		)	(1,044		)
Non-cash tax expense	649			992
Gain on step up of historical basis	—			(335,260		)
Other items, net	(480		)	5,512
Available Cash before Reserves	95,012			96,308



	Three Months Ended September 30,
	2016			2015
	(in thousands)
Cash Flows from Operating Activities	$	124,725		$	121,026
Adjustments to reconcile net cash flow provided by operating activities to Available Cash before Reserves:
Maintenance capital utilized	(1,885		)	(1,044		)
Proceeds from asset sales	120			343
Amortization and writeoff of debt issuance costs, including premiums and discounts	(2,571		)	(1,941		)
Effects of available cash of equity method investees not included in operating cash flows	4,801			7,870
Net changes in components of operating assets and liabilities not included in calculation of Available Cash before Reserves	(26,834		)	(42,420		)
Non-cash effect of equity based compensation expense	(2,047		)	(2,246		)
Expenses related to acquiring or constructing assets that provide new sources of cash flow	363			12,766
Other items, net	$	(1,660	)	$	1,954
Available Cash before Reserves	95,012			96,308

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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 10 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 (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 unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Our Segment Margin definition also includes the non-income portion of payments received under direct financing leases.

A reconciliation of total Segment Margin to net income is included in our segment disclosure in Note 10 to our Unaudited Condensed Consolidated Financial Statements.

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.

We define Available Cash before Reserves as net income as adjusted for specific items, the most significant of which are the addition of certain non-cash gains or charges (including depreciation and amortization), the substitution of distributable

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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), the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows and the subtraction of maintenance capital utilized, which is described in detail below.

Recent Change in Circumstances and Disclosure Format

We have implemented a modified format relating to maintenance capital requirements because of our expectation that our future maintenance capital expenditures may change 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 new 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.

Historically, substantially all of our maintenance capital expenditures have been (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.

Prospectively, we believe 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 future 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 new 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

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

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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 have not historically used 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. Further, we do not have the actual comparable calculations for our prior periods, and we may not have the information necessary to make such calculations for such periods. And, even if we could locate and/or re-create the information necessary to make such calculations, we believe it would be unduly burdensome to do so in comparison to the benefits derived.

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, 2015.

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, 2015, 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, including the assets we acquired in the Enterprise acquisition;


•	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;

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


•	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 revolving credit facility 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, 2015. These risks may also be specifically described in our 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. 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, 2015. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 13 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 third quarter of 2016 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, 2015. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

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, 2015. For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2015, 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.

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.

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 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 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 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).
*	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:	November 3, 2016	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer