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, 2017~~March 31, 2020

¨☐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



Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common units	GEL	NYSE

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 (§232.405 of this chapter) during the preceding 12 months (or for 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding as of ~~November 3, 2017.~~May 6, 2020.

GENESIS ENERGY, L.P.

TABLE OF CONTENTS



		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~~Comprehensive Income	5
	Unaudited Condensed Consolidated Statements of ~~Cash Flows~~Partners’ Capital	6
	~~Notes to~~ Unaudited Condensed Consolidated ~~Financial~~ Statements of Cash Flows	7
	~~1. Organization and Basis of Presentation and Consolidation~~	7
	~~2. Recent Accounting Developments~~Notes to Unaudited Condensed Consolidated Financial Statements	8
	~~3. Acquisition~~1. Organization and ~~Divestiture~~Basis of Presentation and Consolidation	8
	2. Recent Accounting Developments	9
	3. Revenue Recognition	9
	4. ~~Inventories~~Lease Accounting	10
	5. ~~Fixed Assets~~	11
	~~6. Equity Investees~~Inventories	12
	6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations	13
	7. ~~Intangible Assets~~Equity Investees	14
	8. ~~Debt~~Intangible Assets	15
	9. ~~Partners' Capital, Mezzanine Equity and Distributions~~Debt	1516
	10. ~~Net Income Per Common Unit~~
	~~11. Business Segment Information~~Partners' Capital, Mezzanine Capital and Distributions	1917
	11. Net Income (Loss) Per Common Unit	20
	12. ~~Transactions with Related Parties~~Business Segment Information	21
	13. ~~Supplemental Cash Flow Information~~Transactions with Related Parties	22
	14. ~~Derivatives~~Supplemental Cash Flow Information	2324
	15. ~~Fair-Value Measurements~~Derivatives	2624
	16. ~~Commitments and Contingencies~~Fair-Value Measurements	27
	17. ~~Condensed Consolidating Financial Information~~Commitments and Contingencies	29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3830
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	5850
Item 4.	Controls and Procedures	5850
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	5951
Item 1A.	Risk Factors	5951
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5951
Item 3.	Defaults upon Senior Securities	5951
Item 4.	Mine Safety Disclosures	5951
Item 5.	Other Information	5951
Item 6.	Exhibits	5952
SIGNATURES		6154

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)


	September 30, 2017			December 31, 2016			March 31, 2020			December 31, 2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,694		$	7,029		$	18,137		$	29,128
Restricted cash							23,372			27,277
Accounts receivable - trade, net	437,039			224,682			315,645			417,002
Inventories	98,558			98,587			70,161			65,137
Other	45,533			29,271			69,565			54,530
Total current assets	590,824			359,569			496,880			593,074
FIXED ASSETS, at cost	5,522,292			4,763,396			5,567,710			5,540,596
Less: Accumulated depreciation	(681,900		)	(548,532		)	(1,311,219		)	(1,246,121		)
Net fixed assets	4,840,392			4,214,864			4,256,491			4,294,475
MINERAL LEASEHOLDS, net	622,756			—
MINERAL LEASEHOLDS, net of accumulated depletion							554,862			555,825
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	127,248			132,859			105,251			107,702
EQUITY INVESTEES	383,191			408,756			327,942			334,523
INTANGIBLE ASSETS, net of amortization	187,441			204,887			136,071			138,927
GOODWILL	325,046			325,046			301,959			301,959
RIGHT OF USE ASSETS, net							175,889			177,071
OTHER ASSETS, net of amortization	60,736			56,611			79,113			94,085
TOTAL ASSETS	$	7,137,634		$	5,702,592		$	6,434,458		$	6,597,641
LIABILITIES AND CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	203,717		$	119,841		$	151,868		$	218,737
Accrued liabilities	160,294			140,962			172,941			196,758
Total current liabilities	364,011			260,803			324,809			415,495
SENIOR SECURED CREDIT FACILITY	1,372,500			1,278,200			977,400			959,300
SENIOR UNSECURED NOTES, net of debt issuance costs	2,358,049			1,813,169			2,463,171			2,469,937
DEFERRED TAX LIABILITIES	26,399			25,889			12,125			12,640
OTHER LONG-TERM LIABILITIES	256,462			204,481			366,281			393,850
Total liabilities	4,377,421			3,582,542			4,143,786			4,251,222

MEZZANINE CAPITAL:
Series A Convertible Preferred Units, 22,249,494 issued and outstanding at September 30, 2017	691,708			—
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at March 31, 2020 and December 31, 2019							790,115			790,115
Redeemable noncontrolling interests, 130,000 preferred units issued and outstanding at March 31, 2020 and December 31, 2019, respectively							129,219			125,133

PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 117,979,218 units issued and outstanding at September 30, 2017 and December 31, 2016, respectively	2,077,393			2,130,331
Common unitholders, 122,579,218 units issued and outstanding at March 31, 2020 and December 31, 2019							1,382,126			1,443,320
Accumulated other comprehensive loss							(8,431		)	(8,431		)
Noncontrolling interests	(8,888		)	(10,281		)	(2,357		)	(3,718		)
Total partners' capital	2,068,505			2,120,050			1,371,338			1,431,171
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL	$	7,137,634		$	5,702,592		$	6,434,458		$	6,597,641

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

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,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
REVENUES:
Offshore pipeline transportation services	80,671			89,717			243,437			244,837
Offshore pipeline transportation													$	78,429		$	78,317
Sodium minerals and sulfur services	109,765			45,725			197,879			129,585			243,390			275,486
Marine transportation	48,534			55,285			152,038			159,930			62,346			56,650
Onshore facilities and transportation	247,144			269,323			714,974			750,088			155,758			209,556
Total revenues	486,114			460,050			1,308,328			1,284,440			539,923			620,009
COSTS AND EXPENSES:
Onshore facilities and transportation product costs	202,047			230,229			582,535			620,620			111,952			168,105
Onshore facilities and transportation operating costs	23,982			22,476			80,160			71,974			18,248			19,652
Marine transportation operating costs	35,789			38,490			111,980			105,942			42,937			43,733
Sodium minerals and sulfur services operating costs	79,365			25,077			133,335			67,641			205,233			218,708
Offshore pipeline transportation operating costs	18,690			23,122			54,682			63,732			18,661			18,458
General and administrative	19,409			11,212			38,723			34,716			9,373			11,686
Depreciation, depletion and amortization	63,732			54,265			176,453			156,800			74,357			77,638
Gain on sale of assets	—			—			(26,684		)	—
Total costs and expenses	443,014			404,871			1,151,184			1,121,425			480,761			557,980
OPERATING INCOME	43,100			55,179			157,144			163,015			59,162			62,029
Equity in earnings of equity investees	13,044			12,488			34,805			35,362			14,159			12,997
Interest expense	(47,388		)	(34,735		)	(122,117		)	(104,657		)	(54,965		)	(55,701		)
Other expense	(2,276		)	—			(2,276		)	—
Other income (expense)													10,258			(2,976		)
Income before income taxes	6,480			32,932			67,556			93,720			28,614			16,349
Income tax expense	(320		)	(949		)	(878		)	(2,959		)
Income tax benefit (expense)													365			(402		)
NET INCOME	6,160			31,983			66,678			90,761			28,979			15,947
Net loss attributable to noncontrolling interests	152			118			457			370			16			7
Net income attributable to redeemable noncontrolling interests													(4,086		)	—
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	6,312		$	32,101		$	67,135		$	91,131		$	24,909		$	15,954
Less: Accumulated distributions attributable to Series A Convertible Preferred Units	(5,469		)	—			(5,469		)	—
NET INCOME AVAILABLE TO COMMON UNITHOLDERS	$	843		$	32,101		$	61,666		$	91,131
NET INCOME PER COMMON UNIT (Note 10):
Less: Accumulated distributions attributable to Class A Convertible Preferred Units													(18,684		)	(18,415		)
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS													$	6,225		$	(2,461	)
NET INCOME (LOSS) PER COMMON UNIT (Note 11):
Basic and Diluted	$	0.01		$	0.28		$	0.51		$	0.81		$	0.05		$	(0.02	)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	122,579			115,718			121,198			111,906			122,579			122,579

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

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)



	Three Months Ended March 31,
	2020			2019
Net income	$	28,979		$	15,947
Other comprehensive income:
Change in benefit plan liability	—			—
Total Comprehensive income	28,979			15,947
Comprehensive loss attributable to noncontrolling interests	16			7
Comprehensive income attributable to redeemable noncontrolling interests	$	(4,086	)	$	—
Comprehensive income attributable to Genesis Energy, L.P.	$	24,909		$	15,954

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

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Accumulated Other Comprehensive Loss			Total
Partners’ capital, January 1, 2020	122,579	$	1,443,320		$	(3,718	)	$	(8,431	)	$	1,431,171
Net income (loss)	—	24,909			(16		)	—			24,893
Cash distributions to partners	—	(67,419		)	—			—			(67,419		)
Cash contributions from noncontrolling interests	—	—			1,377			—			1,377
Distributions to Class A Convertible Preferred unitholders	—	(18,684		)	—			—			(18,684		)
Partners' capital, March 31, 2020	122,579	$	1,382,126		$	(2,357	)	$	(8,431	)	$	1,371,338
	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Accumulated Other Comprehensive Income			Total
Partners’ capital, January 1, 2019	122,579	$	1,690,799		$	(11,204	)	$	939		$	1,680,534
Net income (loss)	—	15,954			(7		)	—			15,947
Cash distributions to partners	—	(67,419		)	—			—			(67,419		)
Cash contributions from noncontrolling interests	—	—			610			—			610
Distributions to Class A Convertible Preferred unitholders	—	(18,020		)	—			—			(18,020		)
Partners' capital, March 31, 2019	122,579	$	1,621,314		$	(10,601	)	$	939		$	1,611,652

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

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF ~~PARTNERS’ CAPITAL~~CASH FLOWS

(In thousands)

Number of
Common Units
Partners’ Capital Noncontrolling Interest Total
Partners’ capital, January 1, 2017 117,979
$ 2,130,331
$ (10,281 ) $ 2,120,050
Net income (loss) —
67,135
(457 ) 66,678
Cash distributions to partners —
(260,586 ) —
(260,586 )
Cash contributions from noncontrolling interests —
—
1,850
1,850
Issuance of common units for cash, net 4,600
140,513
—
140,513
Partners' capital, September 30, 2017 122,579
$ 2,077,393
$ (8,888 ) $ 2,068,505

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



	Three Months Ended March 31,
	2020			2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	28,979		$	15,947
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization	74,357			77,638
Amortization and write-off of debt issuance costs and discount	11,527			2,682
Amortization of unearned income and initial direct costs on direct financing leases	(2,929		)	(3,139		)
Payments received under direct financing leases	5,167			5,167
Equity in earnings of investments in equity investees	(14,159		)	(12,997		)
Cash distributions of earnings of equity investees	13,505			12,400
Non-cash effect of long-term incentive compensation plans	(5,027		)	1,565
Deferred and other tax liabilities	(515		)	252
Unrealized (gains) losses on derivative transactions	(31,118		)	5,666
Other, net	2,231			5,640
Net changes in components of operating assets and liabilities (Note 14)	7,534			3,200
Net cash provided by operating activities	89,552			114,021
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(38,001		)	(29,612		)
Cash distributions received from equity investees - return of investment	7,060			5,425
Proceeds from asset sales	61			358
Net cash used in investing activities	(30,880		)	(23,829		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	393,500			187,500
Repayments on senior secured credit facility	(375,400		)	(215,600		)
Proceeds from issuance of senior unsecured notes due 2028	750,000			—
Repayment of senior unsecured notes due 2022	(750,000		)	—
Debt issuance costs	(13,295		)	—
Contributions from noncontrolling interests	1,377			610
Distributions to common unitholders	(67,419		)	(67,419		)
Distributions to preferred unitholders	(18,684		)	—
Other, net	6,353			5,621
Net cash used in financing activities	(73,568		)	(89,288		)
Net increase (decrease) in cash, restricted cash, and cash equivalents	(14,896		)	904
Cash, restricted cash and cash equivalents at beginning of period	56,405			10,300
Cash, restricted cash and cash equivalents at end of period	$	41,509		$	11,204

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

~~GENESIS ENERGY, L.P.~~

~~UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(In thousands)~~

Nine Months Ended
September 30,
2017 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 66,678
$ 90,761
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization 176,453
156,800
Provision for leased items no longer in use 12,589
—
Gain on sale of assets (26,684 ) —
Amortization of debt issuance costs and discount 8,154
7,563
Amortization of unearned income and initial direct costs on direct financing leases (10,374 ) (10,856 )
Payments received under direct financing leases 15,501
15,501
Equity in earnings of investments in equity investees (34,805 ) (35,362 )
Cash distributions of earnings of equity investees 45,854
49,528
Non-cash effect of equity-based compensation plans (5,524 ) 6,102
Deferred and other tax liabilities 508
2,058
Unrealized loss on derivative transactions 3,040
742
Other, net (7,338 ) 8,967
Net changes in components of operating assets and liabilities (Note 13)
(26,262 ) (63,407 )
Net cash provided by operating activities 217,790
228,397
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets (182,653 ) (363,218 )
Cash distributions received from equity investees - return of investment 14,517
16,652
Acquisitions (1,325,759 ) (25,394 )
Contributions in aid of construction costs 124
12,208
Proceeds from asset sales 39,204
3,303
Other, net —
185
Net cash used in investing activities (1,454,567 ) (356,264 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility 1,247,700
883,600
Repayments on senior secured credit facility (1,153,400 ) (831,600 )
Proceeds from issuance of senior unsecured notes 550,000
—
Proceeds from issuance of Series A convertible preferred units, net 729,958
—
Debt issuance costs (17,808 ) (1,578 )
Issuance of common units for cash, net 140,513
298,051
Contributions from noncontrolling interests 1,850
—
Distributions to common unitholders (260,586 ) (227,454 )
Other, net 1,215
(600 )
Net cash provided by financing activities 1,239,442
120,419
Net increase (decrease) in cash and cash equivalents 2,665
(7,448 )
Cash and cash equivalents at beginning of period 7,029
10,895
Cash and cash equivalents at end of period $ 9,694
$ 3,447

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States ~~Wyoming~~ and the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our soda ash ~~businesses,~~business (our "Alkali Business"), 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.

On September 1, 2017, we acquired Tronox Limited’s (“Tronox’s”) trona and trona-based exploring, mining, processing, producing, marketing and selling business (the "Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into transition service agreements to facilitate the transition of operations and uninterrupted services for both employees and customers. We will report the results of our Alkali Business in our renamed sodium minerals and sulfur services segment, which will include our Alkali Business as well as our existing refinery services operations.

In the fourth quarter of 2016, we reorganized our operating segments as a result of the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates resources. Due to the increasingly integrated nature of our onshore operations, the results of our onshore pipeline transportation segment, formerly reported under its own segment, is now reported in our onshore facilities and transportation segment. The onshore facilities and transportation segment was formerly named as our supply and logistics segment. This segment was renamed in the second quarter of 2017 to more accurately describe the nature of its operations. These changes are consistent with the increasingly integrated nature of our onshore operations. We will report the results of the Alkali Business in our renamed sodium minerals and sulfur services segment, which will include the Alkali Business as well as our existing refinery services operations.

~~As a result of the above changes, we~~ currently manage our businesses through ~~four~~the following 4 divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

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

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

Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing of high sulfur (or ~~“sour”~~"sour") gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or ~~“NaHS”~~"NaHS", commonly pronounced "nash");


•	Onshore facilities and transportation, which include terminalling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO_2;2; and

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

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”~~(the "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”~~("GAAP") have been condensed or omitted pursuant to such rules and regulations. However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file

with the SEC pursuant to the Securities Exchange Act of 1934, including the Consolidated Financial Statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2019 (our "Annual Report").

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.

COVID-19 Update

In March 2020, the World Health Organization categorized COVID-19 as a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and Infrastructure Security Agency ("CISA") and we have continued to operate our assets during this pandemic.

We considered the impact of COVID-19 on the assumptions and estimates reflected in our financial statements. We noted, other than the impact of general macroeconomic conditions, there were no material adverse effects from the pandemic on our results for the three months ended March 31, 2020. See further discussion on COVID-19 in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2. Recent Accounting Developments

Recently ~~Issued~~Adopted

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 transition method. In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved early adoption of the standard, but not before the original effective date of December 15, 2016. Our process of evaluating the impact of this guidance on each type of revenue contract entered into with customers is ongoing, but nearing completion. This process includes regular involvement from our implementation team in determining any significant impact on accounting treatment, processes, internal controls, and disclosures. While we do not believe there will be a material impact to our revenues upon adoption based on our preliminary assessment, we continue to evaluate the impacts of our pending adoption of this guidance until finalized conclusions are determined, particularly involving contracts within our sodium minerals and sulfur services segment including those within our recently acquired Alkali Business. Though we have not finalized our conclusions, we currently plan to apply the modified retrospective transition approach.

In July 2015, the FASB issued guidance modifying the accounting for inventory. Under this guidance, the measurement principle for inventory will change from lower of cost or market value to lower of cost or net realizable value. The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted ~~this~~ guidance under ASC Topic 326, Financial Instruments - Credit Losses ("ASC 326"), as of January 1, ~~2017 with no material~~2020 . The standard changed the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities are required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. We performed an assessment at our adoption date, January 1, 2020, which consisted of reviewing current and historical information pertaining to our trade accounts receivable and existing contract assets. Our assessment resulted in an immaterial impact onto 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~~statements as 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 date and for the three months ended March 31, 2020.

During the first quarter of ~~this guidance~~2020, the SEC amended the financial disclosure requirements for guarantors and issuers of guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X to ~~have a material impact on our~~go in effect January 4, 2021. The amendment simplifies the disclosure requirements and permits the amended disclosures to be provided outside the footnotes in audited annual or unaudited interim consolidated financial ~~statements.~~statements in all filings. As permitted by the amendment, we have early adopted the amendment and included the required summarized financial information in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

3. ~~Acquisition~~Revenue Recognition

Revenue from Contracts with Customers

The following tables reflect the disaggregation of our revenues by major category for the three months ended March 31, 2020 and ~~Divestiture~~2019, respectively:

~~Acquisition~~

~~Alkali Business~~



	Three Months Ended March 31, 2020
	Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities and Transportation		Consolidated
Fee-based revenues	$	78,429	$	—	$	62,346	$	40,990	$	181,765
Product Sales	—		215,366		—		114,768		330,134
Refinery Services	—		28,024		—		—		28,024
	$	78,429	$	243,390	$	62,346	$	155,758	$	539,923

~~On September 1, 2017,~~



	Three Months Ended March 31, 2019
	Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services		Marine Transportation		Onshore Facilities & Transportation		Consolidated
Fee-based revenues	$	78,317	$	—	$	56,650	$	38,012	$	172,979
Product Sales	—		257,843		—		171,544		429,387
Refinery Services	—		17,643		—		—		17,643
	$	78,317	$	275,486	$	56,650	$	209,556	$	620,009

The Company recognizes revenue upon the satisfaction of its performance obligations under its contracts. The timing of revenue recognition varies for our different revenue streams. In general, the timing includes recognition of revenue over time as services are being performed as well as recognition of revenue at a point in time, for delivery of products.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Contract Assets and Liabilities

The table below depicts our contract asset and liability balances at December 31, 2019 and March 31, 2020:



	Contract Assets				Contract Liabilities
	Current		Non-Current		Current		Non-Current
Balance at December 31, 2019	$	21,912	$	54,232	$	2,896	$	23,170
Balance at March 31, 2020	33,672		37,277		2,983		22,376

Transaction Price Allocations to Remaining Performance Obligations

We are required to disclose the amount of our transaction prices that are allocated to unsatisfied performance obligations as of March 31, 2020. We are exempted from disclosing performance obligations with a duration of one year or less, revenue recognized related to performance obligations where the consideration corresponds directly with the value provided to customers, and contracts with variable consideration that is allocated wholly to an unsatisfied performance obligation or promise to transfer a good or service that is part of a series in accordance with ASC 606.

The majority of our contracts qualify for one of these expedients or exemptions. For the remaining contract types that involve revenue recognition over a long-term period with long-term fixed consideration (adjusted for indexing as required), we ~~acquired~~determined our allocations of transaction price that relate to unsatisfied performance obligations. For our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long term period. Therefore, we have allocated the ~~Alkali Business~~remaining contract value to future periods.

The following chart depicts how we expect to recognize revenues for approximately $1.325 billion (inclusive of approximately $100 million in working capital). The Alkali Business produces natural soda ash, also known as sodium carbonate (Na2CO3), as basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent andfuture periods related to these contracts:



	Offshore Pipeline Transportation		Onshore Facilities and Transportation
Remainder of 2020	$	54,873	$	43,220
2021	58,623		20,269
2022	69,134		4,283
2023	58,540		—
2024	52,812		—
Thereafter	154,899		—
Total	$	448,881	$	67,772

4. Lease Accounting

Lessee Arrangements

We lease a variety of ~~chemicals~~transportation equipment (including trucks, trailers, and ~~other industrial products. To finance that transaction~~railcars), terminals, land and ~~the related costs, we used proceeds~~facilities, and office space and equipment. Lease terms vary and can range from (i) a $550.0 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance discount and underwriting fees, (ii) a $750 million private placement of Classshort term (under 12 months) to long term (greater than 12 months). A ~~Convertible Preferred units in September 2017, generating net proceeds of $726.2 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand.~~

~~We have reflected the financial results~~majority of our ~~Alkali Business in our sodium minerals and sulfur services segment from~~leases contain options to extend the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Those preliminary fair values were developed by management with the assistance of a third-party

valuation firm and are subject to change pending a final valuation report and final determination of working capital acquired and other purchase price adjustments. We expect to finalize the purchase price allocation for this transaction during the fourth quarter of 2017.

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

Accounts receivable 138,291
Inventories 31,944
Other current assets 13,947
Fixed assets 617,878
Mineral leaseholds 623,137
Accounts payable (51,534 )
Other current liabilities (29,870 )
Other long-term liabilities (18,793 )
Total Purchase Price $ 1,325,000

Fixed assets identified in connection with our valuation and preliminary purchase price allocation include the related facilities, machinery and equipment associated with the Alkali Business, principallylease at our ~~Green River, Wyoming operations. These assets will be depreciated under~~sole discretion. We considered these options when determining the ~~straight line method~~lease terms used to derive our right of use asset and ~~have an average useful life~~associated lease liability. Leases with a term of ~~approximately 15 years. Mineral leaseholds include the trona reserves at our Green River, Wyoming facility and~~less than 12 months are ~~depleted over their useful lives as determined by the units of production method. Other long-term liabilities include various items including assumed employee benefit plan obligations.~~

Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017, the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Revenues $ 66,003
66,003
Net income $ 10,654
10,654

The table below presents selected unaudited pro forma financial information incorporating the historical results of our Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2016 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 Tronox trona and trona-based exploring, mining, processing, producing, marketing and selling business 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 Alkali Business acquisition been completed on January 1, 2016. Pro forma net income includes the effects of distributions on preferred units and interest expense on incremental borrowings. The dilutive effect of Series A Preferred Units is calculated using the if-converted method.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Pro forma consolidated financial operating results:
Revenues $ 615,275
$ 653,749
$ 1,829,389
$ 1,872,939
Net Income Attributable to Genesis Energy, L.P. 10,978
31,400
59,314
78,113
Net Income Available to Common Unitholders (5,276 ) 15,943
10,939
31,853
Basic and diluted earnings per common unit:
As reported net income per common unit $ 0.01
$ 0.28
$ 0.51
$ 0.81
Pro forma net income per common unit $ (0.04 ) $ 0.14
$ 0.09
$ 0.28

As relating to the Alkali Business acquisition, we have incurred approximately $10.4 million in acquisition related costs through September 30, 2017. Such costs are included as "General and Administrative costs"recorded on our Unaudited Condensed Consolidated ~~Statement~~Balance Sheets. Lease expenses are recognized on a straight line basis over the lease term.

Our Right of Use Assets, net balance includes our unamortized initial direct costs associated with certain of our transportation equipment leases. Additionally, it includes our unamortized prepaid rents, our deferred rents, and our previously classified intangible asset associated with a favorable lease. Our lease liability includes our remaining provision for each period presented for our cease-use provision for railcars no longer in use.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Lessor Arrangements

We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties.

Operating Leases

We act as a lessor in our revenue contracts associated with the M/T American Phoenix, within the marine transportation segment, and on our Free State pipeline system, included in our onshore facilities and transportation segment. These revenues are recorded within its respective segment's revenues in the Unaudited Condensed Consolidated Statements of Operations. Our lease revenues for these arrangements (inclusive of fixed and variable consideration) are reflected in the table below for the three months ended March 31, 2020 and 2019, respectively:



	Three Months Ended March 31,
	2020		2019
M/T American Phoenix	$	6,643	$	6,660
Free State Pipeline	1,923		1,634

Direct Finance Lease

Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008. These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028, we will convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment.

The following table details the fixed lease payments we will receive for our lessor arrangements as of March 31, 2020:



	Operating Leases				Direct Financing Lease
Maturity of Lessor Receipts	Marine Transportation		Onshore Facilities and Transportation		Onshore Facilities and Transportation
Remainder of 2020	$	13,394	$	900	$	15,501
2021	—		1,200		20,668
2022	—		1,200		20,668
2023	—		1,200		20,668
2024	—		1,200		20,668
Thereafter	—		4,100		72,336
Total Lease Receipts	13,394		9,800		170,509
Less: Interest	—		—		(55,733		)
Total Net Lease Receipts	$	13,394	$	9,800	$	114,776

The present value of our lease receivables for our direct finance lease includes a current portion of $9.5 million, which is recorded in other current assets on the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2020.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Inventories

The major components of inventories were as follows:



	March 31, 2020		December 31, 2019
Petroleum products	$	3,645	$	2,721
Crude oil	3,133		5,271
Caustic soda	5,821		5,965
NaHS	13,473		10,845
Raw materials - Alkali operations	5,999		6,238
Work-in-process - Alkali operations	8,399		8,579
Finished goods, net - Alkali operations	17,779		14,168
Materials and supplies, net - Alkali operations	11,912		11,350
Total	$	70,161	$	65,137

September 30,
2017 December 31,
2016
Petroleum products $ 2,618
$ 11,550
Crude oil 46,035
73,133
Caustic soda 5,381
4,593
NaHS 11,176
9,304
Raw materials - Alkali Operations 4,560
—
Work-in-process - Alkali Operations 4,751
—
Finished goods, net - Alkali Operations 14,197
—
Materials and supplies, net - Alkali Operations 9,840
—
Other —
7
Total $ 98,558
$ 98,587

Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories ~~were not recorded~~was adjusted $3.5 million below cost as of ~~September 30, 2017 and~~March 31, 2020, with 0 such adjustment as of December 31, ~~2016.~~2019.

1012

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5.6. Fixed Assets, ~~and~~ Mineral Leaseholds, and Asset Retirement Obligations

Fixed Assets

Fixed assets, net consisted of the following:



	March 31, 2020			December 31, 2019
Crude oil pipelines and natural gas pipelines and related assets	$	2,892,342		$	2,891,489
Alkali facilities, machinery, and equipment	594,263			591,547
Onshore facilities, machinery, and equipment	641,135			640,376
Transportation equipment	19,662			19,864
Marine vessels	994,730			979,171
Land, buildings and improvements	238,992			238,451
Office equipment, furniture and fixtures	22,659			22,645
Construction in progress	122,036			115,162
Other	41,891			41,891
Fixed assets, at cost	5,567,710			5,540,596
Less: Accumulated depreciation	(1,311,219		)	(1,246,121		)
Net fixed assets	$	4,256,491		$	4,294,475

September 30,
2017 December 31,
2016
Crude oil pipelines and natural gas pipelines and related assets $ 3,004,618
$ 2,901,202
Alkali facilities, machinery, and equipment 617,878
—
Onshore facilities, machinery, and equipment 757,874
427,658
Transportation equipment 17,995
17,543
Marine vessels 898,582
863,199
Land, buildings and improvements 103,774
55,712
Office equipment, furniture and fixtures 9,681
9,654
Construction in progress 58,069
440,225
Other 53,821
48,203
Fixed assets, at cost 5,522,292
4,763,396
Less: Accumulated depreciation (681,900 ) (548,532 )
Net fixed assets $ 4,840,392
$ 4,214,864

Mineral Leaseholds

Our Mineral Leaseholds, as relating to our ~~recently acquired~~ Alkali Business, consist of the following:



	March 31, 2020			December 31, 2019
Mineral leaseholds	$	566,019		$	566,019
Less: Accumulated depletion	(11,157		)	(10,194		)
Mineral leaseholds, net of accumulated depletion	$	554,862		$	555,825

September 30,
2017
Mineral leaseholds 623,137
Less: Accumulated depletion (381 )
Mineral leaseholds, net $ 622,756

Our depreciation and depletion expense for the periods presented was as follows:



	Three Months Ended March 31,
	2020		2019
Depreciation expense	$	69,242	$	71,672
Depletion expense	963		1,319

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Depreciation expense $ 57,117
$ 46,909
$ 157,438
$ 135,428
Depletion Expense 381
—
381
—

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Asset Retirement Obligations

We record ~~AROs~~asset retirement obligations ("AROs") in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations.

The following table presents information regarding our AROs since December 31, ~~2016:~~2019:



ARO liability balance, December 31, 2019	$	175,081
Accretion expense	2,233
Changes in estimate	(800		)
Settlements	(6,986		)
ARO liability balance, March 31, 2020	$	169,528

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

ARO liability balance, December 31, 2016 $ 213,726
Accretion expense 8,257
Change in estimate 7,875
Acquisitions 2,444
Divestitures (7,649 )
Settlements (21,252 )
Other 240
ARO liability balance, September 30, 2017 $ 203,641

Of the ARO balances disclosed above, ~~$19.3~~$13.8 million and ~~$22.4~~$26.6 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively. The remainder of the ARO liability as of ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016~~2019 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~~estimate of accretion expense for the periods indicated:



Remainder of	2020	$	7,029
	2021	$	9,402
	2022	$	9,412
	2023	$	10,075
	2024	$	10,786

Remainder of 2017 $ 2,741
2018 $ 9,686
2019 $ 8,782
2020 $ 9,378
2021 $ 10,014

Certain of our unconsolidated affiliates have AROs recorded at ~~September 30, 2017~~March 31, 2020 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Unaudited Condensed Consolidated Financial Statements.

6.7. 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, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, the unamortized excess cost amounts totaled ~~$386.3~~$347.0 million and ~~$398.1~~$350.9 million, respectively. We amortize the excess cost as a reduction in equity ~~earnings in a manner similar to depreciation.~~earnings.

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



	Three Months Ended March 31,
	2020			2019
Genesis’ share of operating earnings	$	18,032		$	16,870
Amortization of excess purchase price	(3,873		)	(3,873		)
Net equity in earnings	$	14,159		$	12,997
Distributions received	$	20,565		$	17,825

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Genesis’ share of operating earnings $ 16,986
$ 16,444
$ 46,631
$ 47,281
Amortization of excess purchase price (3,942 ) (3,956 ) (11,826 ) (11,919 )
Net equity in earnings $ 13,044
$ 12,488
$ 34,805
$ 35,362
Distributions received $ 20,180
$ 21,551
$ 60,371
$ 66,180

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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



	March 31, 2020			December 31, 2019
BALANCE SHEET DATA:
Assets
Current assets	$	20,112		$	30,307
Fixed assets, net	183,268			187,091
Other assets	2,014			2,113
Total assets	$	205,394		$	219,511
Liabilities and equity
Current liabilities	$	15,135		$	15,558
Other liabilities	236,659			245,976
Equity	(46,400		)	(42,023		)
Total liabilities and equity	$	205,394		$	219,511

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30,
2017 December 31,
2016
BALANCE SHEET DATA:
Assets
Current assets $ 18,638
$ 17,111
Fixed assets, net 221,123
232,736
Other assets 1,282
861
Total assets $ 241,043
$ 250,708
Liabilities and equity
Current liabilities $ 20,683
$ 20,727
Other liabilities 231,469
219,644
Equity (11,109 ) 10,337
Total liabilities and equity $ 241,043
$ 250,708



	Three Months Ended March 31,
	2020		2019
INCOME STATEMENT DATA:
Revenues	$	32,892	$	31,052
Operating income	$	23,606	$	22,305
Net income	$	21,583	$	19,850

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
INCOME STATEMENT DATA:
Revenues $ 30,597
$ 31,219
$ 88,003
$ 90,658
Operating income $ 22,334
$ 23,107
$ 63,159
$ 68,166
Net income $ 20,739
$ 21,921
$ 58,754
$ 64,670

Poseidon's ~~revolving credit facility~~Revolving Credit Facility

Borrowings under Poseidon’s revolving credit facility, which was amended and restated in ~~February 2015,~~March 2019, are primarily used to fund spending on capital projects. The ~~February 2015~~March 2019 credit facility is non-recourse to Poseidon’s owners and secured by substantially all of Poseidon's ~~assets.~~assets and has a maturity date of March 2024. The ~~February 2015~~March 2019 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 Condensed Consolidated Financial Statements.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

7.8. Intangible Assets

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



	March 31, 2020						December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Marine contract intangibles	$	27,800	$	24,392	$	3,408	$	27,800	$	23,033	$	4,767
Offshore pipeline contract intangibles	158,101		38,832		119,269		158,101		36,752		121,349
Other	35,551		22,157		13,394		34,291		21,480		12,811
Total	$	221,452	$	85,381	$	136,071	$	220,192	$	81,265	$	138,927

September 30, 2017 December 31, 2016

Gross
Carrying
Amount

Accumulated
Amortization

Carrying
Value

Gross
Carrying
Amount

Accumulated
Amortization

Carrying
Value
Sodium minerals and sulfur services:
Customer relationships $ 94,654
$ 91,809
$ 2,845
$ 94,654
$ 89,756
$ 4,898
Licensing agreements 38,678
35,947
2,731
38,678
34,204
4,474
Segment total 133,332
127,756
5,576
133,332
123,960
9,372
Onshore Facilities & Transportation:
Customer relationships 35,430
34,731
699
35,430
33,676
1,754
Intangibles associated with lease 13,260
4,815
8,445
13,260
4,459
8,801
Segment total 48,690
39,546
9,144
48,690
38,135
10,555
Marine contract intangibles 27,000
10,350
16,650
27,000
6,300
20,700
Offshore pipeline contract intangibles 158,101
18,029
140,072
158,101
11,788
146,313
Other 28,747
12,748
15,999
28,569
10,622
17,947
Total $ 395,870
$ 208,429
$ 187,441
$ 395,692
$ 190,805
$ 204,887

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



	Three Months Ended March 31,
	2020		2019
Amortization of intangible assets	$	4,116	$	4,289

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Amortization of intangible assets $ 5,879
$ 6,122
$ 17,623
$ 18,154

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



Remainder of	2020	$	11,563
	2021	$	10,576
	2022	$	10,416
	2023	$	10,147
	2024	$	9,823

Remainder of 2017 $ 5,919
2018 $ 21,506
2019 $ 17,171
2020 $ 16,237
2021 $ 10,627

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8.9. Debt

Our obligations under debt arrangements consisted of the following:



	March 31, 2020						December 31, 2019
	Principal		Unamortized Discount and Debt Issuance Costs ⁽¹⁾		Net Value		Principal		Unamortized Discount and Debt Issuance Costs ⁽¹⁾		Net Value
Senior secured credit facility	$	977,400	$	—	$	977,400	$	959,300	$	—	$	959,300
6.750% senior unsecured notes due 2022	—		—		—		750,000		9,349		740,651
6.000% senior unsecured notes due 2023	400,000		3,290		396,710		400,000		3,557		396,443
5.625% senior unsecured notes due 2024	349,200		3,699		345,501		350,000		3,923		346,077
6.500% senior unsecured notes due 2025	550,000		6,715		543,285		550,000		7,020		542,980
6.250% senior unsecured notes due 2026	446,600		5,970		440,630		450,000		6,214		443,786
7.750% senior unsecured notes due 2028	750,000		12,955		737,045		—		—		—
Total long-term debt	$	3,473,200	$	32,629	$	3,440,571	$	3,459,300	$	30,063	$	3,429,237

September 30, 2017 December 31, 2016
Principal
Unamortized Discount and Debt Issuance Costs ⁽¹⁾
Net Value Principal Unamortized Discount and Debt Issuance Costs (1) Net Value
Senior secured credit facility $ 1,372,500
$ —
$ 1,372,500
$ 1,278,200
$ —
$ 1,278,200
5.750% senior unsecured notes due February 2021 350,000
3,399
346,601
350,000
4,163
345,837
6.750% senior unsecured notes due August 2022 750,000
16,889
733,111
750,000
19,296
730,704
6.000% senior unsecured notes due May 2023 400,000
5,958
394,042
400,000
6,758
393,242
5.625% senior unsecured notes due June 2024 350,000
5,941
344,059
350,000
6,614
343,386
6.500% senior unsecured notes due October 2025 550,000
9,764
540,236
—
—
—
Total long-term debt $ 3,772,500
$ 41,951
$ 3,730,549
$ 3,128,200
$ 36,831
$ 3,091,369


(1)	Unamortized debt issuance costs associated with our senior secured credit facility (included in Other Long Term Assets on the Unaudited Condensed Consolidated Balance Sheet) were ~~$15.2~~$6.8 million and ~~$10.7~~$7.6 million as of ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively.

As of ~~September 30, 2017~~March 31, 2020, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Senior Secured Credit Facility

~~In July 2017, we amended our credit agreement to, among other things, make certain technical amendments related to the financing of our acquisition of the Alkali Business.~~

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 interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At March 31, 2020, the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Eurodollar rate borrowings.

•Letter of credit ~~fees~~fee rates range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At March 31, 2020, our letter of credit rate was 2.75%.

•We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee rates on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio. At March 31, 2020, our commitment fee rate on the unused committed amount was 0.50%.

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

On March 25, 2020, we amended our credit agreement. This amendment, among other things, (i) sets the maximum Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) at 3.25 to 1.00 throughout the remaining term of the facility, and (ii) allows us to purchase certain of our outstanding senior unsecured notes, subject to certain customary conditions.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

At ~~September 30, 2017,~~March 31, 2020, we had ~~$1.4 billion~~$977.4 million borrowed under our $1.7 billion credit facility, with ~~$38.7~~$7.7 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 ~~$12.8~~$1.1 million was outstanding at ~~September 30, 2017.~~March 31, 2020. 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 March 31, 2020 was $721.5 million, subject to compliance with covenants.

As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries (as defined below in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations), and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Genesis Alkali Holdings Company, LLC ("Alkali Holdings") and Genesis Energy, L.P., to the extent agreed to in the services agreement between Genesis Energy, L.P. and Alkali Holdings dated as of September ~~30, 2017 was $314.7 million.~~23, 2019 (the "Services Agreement").

Senior Unsecured Note ~~Issuance~~Issuances, Redemption and Extinguishment

On ~~August 14, 2017,~~January 16, 2020, we issued ~~$550~~$750.0 million in aggregate principal amount of ~~6.50%~~our 7.75% senior unsecured notes due ~~October 1, 2025.~~February 15, 2028 (the “2028 Notes”). Interest payments are due ~~April~~February 1 and ~~October~~August 1 of each year with the initial interest payment due ~~April~~on August 1, ~~2018.~~2020. That issuance generated net proceeds of ~~$540.1~~$736.7 million net of issuance costs incurred. The net proceeds were used to ~~fund~~purchase $527.9 million of our existing 6.75% senior unsecured notes due August 1, 2022 (the “2022 Notes”), including the related accrued interest and tender premium on those notes, and the remaining proceeds at the time were used to repay a portion of the ~~purchase price~~borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for ~~our acquisition~~redemption of the ~~Alkali Business.~~remaining $222.1 million of our 2022 Notes, and they were redeemed on February 16, 2020. We incurred a total loss of approximately $23.5 million relating to the extinguishment of our 2022 senior unsecured notes, inclusive of our transactions costs and the write-off of the related unamortized debt issuance costs and discount, which is recorded as "Other income (expense)" in our Unaudited Consolidated Statements of Operations for the three months ended March 31, 2020.

9.10. Partners’ Capital, Mezzanine ~~Equity~~Capital and Distributions

At ~~September 30, 2017~~March 31, 2020, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units.

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

Distributions

We paid or will pay the following distributions to our common unitholders in ~~2016~~2019 and ~~2017~~2020:


Distribution For	Date Paid		Per Unit Amount		Total Amount		Date Paid		Per Unit Amount		Total Amount
2016
2019
1^st Quarter	May 13, 2016		$	0.6725	$	73,961	May 15, 2019		$	0.5500	$	67,419
2^nd Quarter	August 12, 2016		$	0.6900	$	81,406	August 14, 2019		$	0.5500	$	67,419
3^rd Quarter	November 14, 2016		$	0.7000	$	82,585	November 14, 2019		$	0.5500	$	67,419
4^th Quarter	February 14, 2017		$	0.7100	$	83,765	February 14, 2020		$	0.5500	$	67,419
2017
2020
1^st Quarter	May 15, 2017		$	0.7200	$	88,257	May 15, 2020	⁽¹⁾	$	0.1500	$	18,387
2^nd Quarter	August 14, 2017		$	0.7225	$	88,563
3^rd Quarter	November 14, 2017	⁽¹⁾	$	0.5000	$	61,290

(1) This distribution was declared on April 8, 2020 and will be paid to unitholders of record as of ~~October 31, 2017.~~May 1, 2020.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Class A Convertible Preferred Units

~~On September 1, 2017,~~At March 31, 2020 we ~~sold $750 million of~~had 25,336,778 Class A ~~convertible preferred units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”~~Convertible Preferred Units (our "Class A Convertible Preferred Units") ~~to two initial purchasers.~~outstanding. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our preferred units are a new class of security that ranksClass A Convertible Preferred Units rank senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our ~~preferred units~~Class A Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those ~~preferred units.~~Class A Convertible Preferred Units.

Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the ~~holders~~existence of redemption provisions upon a deemed liquidation event that is outside our ~~preferred units~~control. Therefore, we present them as temporary equity in the ~~applicable distribution~~mezzanine section of the Unaudited Consolidated Balance Sheet. Because our Class A Convertible Preferred Units are not currently redeemable and we do not have plans or expect any events that constitute a change of control in our partnership agreement, we present our Class A Convertible Preferred Units at their initial carrying amount. However, we would be required to adjust that carrying amount in cash, preferred units, or any combination thereof. If we elect to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We have elected to pay the distribution amount attributable to the quarter ended on September 30, 2017 in preferred units. For each quarter ending after March 1, 2019, we must pay all distribution amounts in respect of our preferred units in cash.

From time to time after September 1, 2020, we will have the right to cause the conversion of all or a portion of outstanding preferred units into our common units, subject to certain conditions; provided, however,if it becomes probable that we would be required to redeem our Class A Convertible Preferred Units.

Initial and Subsequent Measurement

We initially recognized our Class A Convertible Preferred Units at their issuance date fair value, net of issuance costs. We will not be ~~permitted~~required to ~~convert more than 7,416,498~~adjust the carrying amount of our ~~preferred units in any consecutive twelve-month period. At any time after September 1, 2020, if~~Class A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we ~~have fewer than 592,768~~would adjust the carrying amount of our ~~preferred units outstanding, we will have the right to convert each outstanding preferred unit into our common units at a conversion rate equal~~Class A Convertible Preferred Units to the ~~greater~~redemption value over a period of ~~(i)~~time comprising the ~~then-applicable conversion rate~~date the feature first becomes probable and ~~(ii)~~ the ~~quotient~~date the units can first be redeemed. Our Class A Convertible Preferred Units contain a distribution Rate Reset Election (as defined in Note 15) option. This Rate Reset Election is bifurcated and accounted for separately as an embedded derivative and recorded at fair value at each reporting period. Refer to Note 15 and Note 16 for additional discussion.

Class A Convertible Preferred Unit distributions are recognized on the date in which they are declared. Paid-in-kind ("PIK") distributions were declared and issued as follows:



Distribution For	Date Issued	Number of Units₍₁₎	Total Amount
2019
1^st Quarter	May 15, 2019	364,180	$	12,277

(1) Subsequent to the first quarter of ~~(a)~~2019, all distributions have been and will be paid in cash.

Net Income Attributable to Genesis Energy, L.P. is reduced by Class A Convertible Preferred Unit distributions that accumulated during the ~~Issue Price~~period. Net income attributable to Genesis Energy, L.P. was reduced by $18.7 million and ~~(b) 95% of the volume-weighted average price of our common units~~$18.4 million for the ~~30-trading day period ending prior to the date that we notify the holders of our outstanding preferred units of such conversion.~~three months ended March 31, 2020 and March 31, 2019.

Upon certain events involving certain changes of control in which more than 90% of the consideration payable to the holders of our common units is payable in cash, our preferred units will automatically convert into common units at a conversion ratio equal to the greater of (a) the then applicable conversion rate and (b) the quotient of (i) the product of (A) the sum of (1) the Issue Price and (2) any accrued and accumulated but unpaid distributions on our preferred units, and (B) a premium factor (ranging from 115% to 101% depending on when such transaction occurs) plus a prorated portion of unpaid partial distributions, and (ii) the volume weighted average price of the common units for the 30 trading days prior to the execution of definitive documentation relating to such change of control.

In connection with other change of control events that do not meet the 90% cash consideration threshold described above, each holder of our preferred units may elect to (a) convert all of its preferred units into our common units at the then applicable conversion rate, (b) if we are not the surviving entity (or if we are the surviving entity, but our common units will

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~cease~~We paid or will pay the following cash distributions to ~~be listed), require us to use commercially reasonable efforts to cause the surviving entity~~our Class A Convertible Preferred unitholders in any such transaction to issue a substantially equivalent security (or if we are unable to cause such substantially equivalent securities to be issued, to convert its preferred units into common units in accordance with clause (a) above or exchanged in accordance with clause (d) below or convert at a specified conversion rate), (c) if we are the surviving entity, continue to hold our preferred units or (d) require us to exchange our preferred units for cash or, if we so elect, our common units valued at 95% of the volume-weighted average price of our common units for the 30 consecutive trading days ending2019 and 2020:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2019
1^st Quarter	May 15, 2019		$	0.2458	$	6,138
2^nd Quarter	August 14, 2019		$	0.7374	$	18,684
3^rd Quarter	November 14, 2019		$	0.7374	$	18,684
4^th Quarter	February 14, 2020		$	0.7374	$	18,684
2020
1^st Quarter	May 15, 2020	⁽¹⁾	$	0.7374	$	18,684

(1) This distribution was declared on ~~the fifth trading day immediately preceding the closing date of such change of control, at a price per unit equal to the sum of (i) the product of (x) 101%~~April 8, 2020 and ~~(y) the Issue Price plus (ii) accrued and accumulated but unpaid distributions and (iii) a prorated portion of unpaid partial distributions.~~

For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a one-time election to reset the quarterly distribution amount (a “Rate Reset Election”) to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 10% of the Issue Price. To become effective, the Rate Reset Election requires approval of holders of at least a majority of our then outstanding preferred units and such majority must include each of our initial purchasers (or any affiliate to whom they have transferred their preferred units) if such initial purchaser (including its affiliates) holds at least 25% of the then outstanding preferred units.

Upon the occurrence of a Rate Reset Election, we may redeem our preferred units for cash, in whole or in part (subject to certain minimum value limitations) for an amount per preferred unit equal to such preferred unit’s liquidation value (equal to the Issue Price plus any accrued and accumulated but unpaid distributions, plus a prorated portion of certain unpaid partial distributions in respect of the immediately preceding quarter and the current quarter) multiplied by (i) 110%, prior to September 1, 2024, and (ii) 105% thereafter. Each holder of our preferred units may elect to convert all or any portion of its preferred units into common units initially on a one-for-one basis (subject to customary adjustments and an adjustment for accrued and accumulated but unpaid distributions and limitations) at any time after September 1, 2019 (or earlier upon a change of control, liquidation, dissolution or winding up), provided that any conversion is for at least $50 million or such lesser amount if such conversion relates to all of a holder’s remaining preferred units or has otherwise been approved by us.

If we fail to pay in full any preferred unit distribution amount after March 1, 2019 in respect of any two quarters, whether or not consecutive, then until we pay such distributions in full, we will not be permitted to (a) declare or make any distributions (subject to a limited exceptions for pro rata distributions on our preferred units and parity securities), redemptions or repurchases of any of our limited partner interests that rank junior to or pari passu with our preferred units with respect to rights upon distribution and/or liquidation (including our common units), or (b) issue any such junior or parity securities. If we fail to pay in full any preferred unit distribution after March 1, 2019 in respect of any two quarters, whether or not consecutive, then the preferred unit distribution amount will be ~~reset~~paid to unitholders of record as of May 1, 2020.

Redeemable Noncontrolling Interests

On September 23, 2019, we, through a ~~cash amount per preferred unit equal to the amount that would be payable per quarter if~~subsidiary, Alkali Holdings, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a ~~preferred unit accrued interest on the Issue Price at an annualized rate equal to the then-current annualized distribution rate plus 200 basis points until such default is cured.~~

~~In addition to their right to veto a Rate Reset Election under~~Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain circumstances, we have granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our preferred units; (ii) the rightinvestment fund entities affiliated with GSO Capital Partners LP (collectively "GSO") purchased $55,000,000 and committed to purchase up to ~~50%~~approximately $350,000,000 of ~~any parity securities on substantially~~preferred units in Alkali Holdings, the ~~same terms offered~~entity that holds our trona and trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the net proceeds from the Alkali Holdings preferred units to ~~other purchasers~~fund up to 100% of the anticipated cost of expansion of the Granger facility. As of March 31, 2020, we have received cash of $122.9 million for ~~so long as an initial purchaser (including its affiliates) owns at least 11,124,747~~the $130 million of Alkali Holdings preferred units issued to date net of issuance costs, which was inclusive of our transaction related expenses and one-time commitment fee.

On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year.

Accounting for Redeemable Noncontrolling Interests

Classification

The Alkali Holdings preferred units issued and ~~(iii)~~outstanding are accounted for as a redeemable noncontrolling interest in the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019.

~~The Rate Reset Election of these preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value~~mezzanine section on our Unaudited Condensed Consolidated Balance ~~Sheet. See further information in~~ ~~Note 14. The~~Sheet due to the redemption features for a change of control.

Initial and Subsequent Measurement

We recorded the Alkali Holdings preferred units ~~themselves~~at their issuance date fair value, net of issuance costs. The fair value as of March 31, 2020 represents the carrying amount based on the issued and outstanding Alkali Holdings preferred units most probable redemption event on the six year anniversary of the closing, which is the predetermined internal rate of return measure accreted using the effective interest method to the redemption value as of the reporting date. Net Income Attributable to Genesis Energy, L.P. for the three months ended March 31, 2020 includes $4.1 million of adjustments, of which $3.3 million was allocated to the PIK distributions on the outstanding Alkali Holdings preferred units and $0.8 million was attributable to redemption accretion value adjustments. We elected to pay distributions for the period ended March 31, 2020 in-kind to our Alkali Holdings preferred unitholders. These PIK distributions increase the unitholders liquidation preference on each Alkali Holdings preferred unit.

As of the reporting date, there are ~~classified as mezzanine~~no triggering, change of control, early redemption or monetization events that are probable that would require us to revalue the Alkali Holdings preferred units.

If the Alkali Holdings preferred units were redeemed on the reporting date of March 31, 2020, the redemption amount would be equal to $192.5 million, which would be the multiple of invested capital metric applied to the Alkali Holdings preferred units outstanding plus the make-whole amount on the undrawn minimum Alkali Holdings preferred units.

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table shows the change in our ~~Unaudited Condensed Consolidated Balance Sheet.~~redeemable noncontrolling interest balance from December 31, 2019 to March 31, 2020:



Balance as of December 31, 2019	$	125,133
PIK distributions	3,294
Redemption accretion	792
Balance as of March 31, 2020	$	129,219

~~10.~~11. Net Income (Loss) Per Common Unit

Basic net income per common unit is computed by dividing net income, after considering income attributable to our ~~Series A~~ preferred unitholders, by the weighted average number of common units outstanding.

The dilutive effect of ~~the Series~~our Class A Convertible Preferred ~~units~~Units is calculated using the if-converted method. Under the if-converted method, ~~the Series A Preferred~~these units are assumed to be converted at the beginning of the period (beginning with their

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated during the period are added back to the numerator for purposes of the if-converted calculation. For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, the effect of the assumed conversion of the ~~22,249,494 Series~~25,336,778 Class A ~~convertible preferred units~~Convertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.

The following table reconciles net income and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts):



	Three Months Ended March 31,
	2020			2019
Net Income Attributable to Genesis Energy L.P.	$	24,909		$	15,954
Less: Accumulated distributions attributable to Class A Convertible Preferred Units	(18,684		)	$	(18,415	)
Net Income (Loss) Available to Common Unitholders	$	6,225		$	(2,461	)

Weighted Average Outstanding Units	122,579			122,579

Basic and Diluted Net Income (Loss) per Common Unit	$	0.05		$	(0.02	)

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net Income Attributable to Genesis Energy L.P. $ 6,312
32,101
$ 67,135
$ 91,131
Less: Accumulated distributions attributable to Series A Convertible Preferred Units (5,469 ) —
(5,469 ) —
Net Income Available to Common Unitholders $ 843
$ 32,101
$ 61,666
$ 91,131

Weighted Average Outstanding Units 122,579
115,718
121,198
111,906

Basic and Diluted Net Income per Common Unit $ 0.01
$ 0.28
$ 0.51
$ 0.81

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~11.~~12. Business Segment Information

In the fourth quarter of 2016, we reorganized our operating segments as a result of the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates resources. The results of our onshore pipeline transportation segment, formerly reported under its own segment, are now reported in our onshore facilities and transportation segment. The onshore facilities and transportation segment was formerly named our supply and logistics segment. This segment was renamed in the second quarter of 2017 to more accurately describe the nature of its operations. This change is consistent with the increasingly integrated nature of our onshore operations.

On September 1, 2017, we acquired Tronox’s Alkali Business for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into transition service agreements to facilitate the transition of operations and uninterrupted services for both employees and customers. We will report the results of our Alkali Business in our renamed sodium minerals and sulfur services segment, which will include our Alkali Business as well as our existing refinery services operations.

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

We currently manage our businesses through ~~four~~4 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;

Sodium minerals and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing high sulfur (or “sour”) gas streams ~~as part of refining operations~~for refineries to remove the sulfur, and selling the related by-product, NaHS;


•	Onshore facilities and transportation – terminalling, blending, storing, marketing and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and CO₂.;and

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

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

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation, depletion 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~~long-term incentive compensation plan and includes the non-income portion of payments received under direct financing leases.

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

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

Segment information for the periods presented below was as follows:


	Offshore Pipeline Transportation			Sodium Minerals & Sulfur Services			Marine Transportation		Onshore Facilities & Transportation			Total		Offshore Pipeline Transportation		Sodium Minerals & Sulfur Services			Onshore Facilities & Transportation			Marine Transportation		Total
Three Months Ended September 30, 2017
Segment margin (a)	$	78,228		$	30,031		$	12,649	$	25,606		$	146,514
Capital expenditures (b)	$	2,356		$	1,330,947		$	23,831	$	26,578		$	1,383,712
Revenues:
External customers	$	80,671		$	111,756		$	46,084	$	247,603		$	486,114
Intersegment (c)	—			(1,991		)	2,450		(459		)	—
Total revenues of reportable segments	$	80,671		$	109,765		$	48,534	$	247,144		$	486,114
Three Months Ended September 30, 2016
Segment margin (a)	$	86,557		$	20,526		$	16,697	$	17,560		$	141,340
Capital expenditures (b)	$	3,977		$	488		$	26,937	$	85,348		$	116,750
Revenues:
External customers	$	89,717		$	48,069		$	53,573	$	268,691		$	460,050
Intersegment (c)	—			(2,344		)	1,712		632			—
Total revenues of reportable segments	$	89,717		$	45,725		$	55,285	$	269,323		$	460,050
Nine Months Ended September 30, 2017
Three Months Ended March 31, 2020
Segment Margin (a)	$	243,528		$	63,864		$	39,768	$	71,999		$	419,159	$	85,246	$	36,941		$	28,099		$	19,002	$	169,288
Capital expenditures (b)	$	8,498		$	1,331,892		$	44,496	$	115,663		$	1,500,549	$	1,027	$	14,975		$	1,157		$	14,232	$	31,391
Revenues:
External customers	$	244,653		$	204,237		$	143,599	$	715,839		$	1,308,328	$	78,429	$	245,535		$	156,799		$	59,160	539,923
Intersegment (c)	(1,216		)	(6,358		)	8,439		(865		)	—		—		(2,145		)	(1,041		)	3,186		—
Total revenues of reportable segments	$	243,437		$	197,879		$	152,038	$	714,974		$	1,308,328	$	78,429	$	243,390		$	155,758		$	62,346	$	539,923
Nine Months Ended September 30, 2016
Three Months Ended March 31, 2019
Segment Margin (a)	$	249,457		$	61,586		$	53,695	$	63,969		$	428,707	$	76,390	$	58,639		$	25,603		$	12,932	$	173,564
Capital expenditures (b)	$	35,175		$	1,645		$	62,928	$	258,681		$	358,429	$	458	$	22,706		$	775		$	9,228	$	33,167
Revenues:
External customers	$	242,672		$	136,437		$	155,197	$	750,134		$	1,284,440	$	78,317	$	277,349		$	211,025		$	53,318	620,009
Intersegment (c)	2,165			(6,852		)	4,733		(46		)	—		—		(1,863		)	(1,469		)	3,332		—
Total revenues of reportable segments	$	244,837		$	129,585		$	159,930	$	750,088		$	1,284,440	$	78,317	$	275,486		$	209,556		$	56,650	$	620,009

Total assets by reportable segment were as follows:


	September 30, 2017		December 31, 2016		March 31, 2020		December 31, 2019
Offshore pipeline transportation	$	2,507,540	$	2,575,335	$	2,267,552	$	2,306,946
Sodium minerals and sulfur services	1,826,815		395,043		1,994,957		2,019,905
Onshore facilities and transportation	1,939,355		1,875,403		1,370,309		1,457,190
Marine transportation	811,870		813,722		761,482		772,383
Other assets	52,054		43,089		40,158		41,217
Total consolidated assets	7,137,634		5,702,592		$	6,434,458	$	6,597,641

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


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

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~


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

Reconciliation of total Segment Margin to net ~~income:~~income attributable to Genesis Energy, L.P:



	Three Months Ended March 31,
	2020			2019
Total Segment Margin	$	169,288		$	173,564
Corporate general and administrative expenses	(6,492		)	(11,100		)
Depreciation, depletion, amortization and accretion	(75,978		)	(79,937		)
Interest expense	(54,965		)	(55,701		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(6,406		)	(4,828		)
Other non-cash items⁽²⁾	33,261			(6,091		)
Cash payments from direct financing leases in excess of earnings	(2,238		)	(2,028		)
Loss on extinguishment of debt⁽³⁾	(23,480		)	—
Differences in timing of cash receipts for certain contractual arrangements ⁽⁴⁾	(4,490		)	2,287
Non-cash provision for leased items no longer in use	130			190
Redeemable noncontrolling interest redemption value adjustments ⁽⁵⁾	(4,086		)	—
Income tax benefit (expense)	365			(402		)
Net income attributable to Genesis Energy, L.P.	$	24,909		$	15,954

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Total Segment Margin $ 146,514
$ 141,340
$ 419,159
$ 428,707
Corporate general and administrative expenses (18,230 ) (10,420 ) (33,694 ) (32,269 )
Depreciation, depletion, amortization and accretion (66,436 ) (57,103 ) (184,213 ) (168,491 )
Interest expense (47,388 ) (34,735 ) (122,117 ) (104,657 )
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾
(7,136 ) (9,063 ) (25,566 ) (30,818 )
Non-cash items not included in Segment Margin (4,788 ) 993
(6,218 ) (3,366 )
Cash payments from direct financing leases in excess of earnings (1,751 ) (1,586 ) (5,127 ) (4,645 )
Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾
5,847
3,624
11,694
9,629
Gain on sale of assets —
—
26,684
—
Non-cash provision for leased items no longer in use

—
—
(12,589 ) —
Income tax expense (320 ) (949 ) (878 ) (2,959 )
Net income attributable to Genesis Energy, L.P. $ 6,312
$ 32,101
$ 67,135
$ 91,131


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


(2)	~~Certain~~ The 2020 Quarter includes a $32.5 million unrealized gain from the valuation of the embedded derivative associated with our Class A Convertible Preferred units and the 2019 Quarter includes a $3.0 million unrealized loss from the valuation of the embedded derivative. Refer to Note 16 for details.


(3)	Refer to Note 9 for details surrounding the extinguishment of our 2022 notes.


(4)	Includes the difference in timing of cash ~~payments received~~receipts from customers ~~under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in~~during the period and the revenue we recognize in ~~which such payments are received.~~accordance with GAAP on our related contracts.

(5) Includes PIK distributions attributable to the period and accretion on the redemption feature.

~~12.~~13. Transactions with Related Parties

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2020		2019
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	750	$	878	$	2,153	$	2,366
Revenues from services and fees to Poseidon Oil Pipeline Company, LLC ⁽²⁾	3,170		1,979		9,236		5,935
Revenues from services and fees to Poseidon⁽¹⁾									$	3,147	$	3,165
Revenues from product sales to ANSAC	31,774		—		31,774		—		73,079		90,679
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	165	$	495	$	495	$	165	$	165
Charges for services from Poseidon Oil Pipeline Company, LLC (2)	254		251		744		749
Charges for services from Poseidon⁽¹⁾									254		247
Charges for services from ANSAC	454		—		454		—		832		1,057


(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, 2017~~ ~~and~~ ~~December 31, 2016~~ ~~(i) Sandhill Group, LLC owed us $0.2 million and $0.2 million, respectively, for purchases of CO~~₂~~, and~~ ~~(ii) Poseidon Oil Pipeline Company, LLC owed us $2.0 million and $1.6 million, respectively, for services rendered.~~

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~Transactions~~

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

Poseidon

At March 31, 2020 and December 31, 2019 Poseidon owed us $1.7 million and $2.4 million, respectively, for services rendered.

We are the operator of Poseidon and provide management, administrative and pipeline operator services to Poseidon under an Operation and Management ~~Agreement .~~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, 2017~~March 31, 2020 and March 31, 2019 reflect ~~the $2.1~~$2.3 million and ~~$6.3~~$2.2 million, respectively of fees we earned through the provision of services under that agreement.

ANSAC

We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. ~~(ANSAC)~~("ANSAC"), an organization whose purpose is promoting and increasing the use and sale of natural soda ash and other refined or processed sodium products produced in the U.S. and consumed in specified countries outside of the U.S. Members sell products to ANSAC to satisfy ANSAC’s sales commitments to its customers. ANSAC passes its costs through to its ~~members.~~members using a pro rata calculation based on sales. Those costs include sales and marketing, employees, office supplies, professional fees, travel, rent, and certain other costs. Those transactions do not necessarily represent arm's length transactions and may not represent all costs we would otherwise incur if we operated ~~the~~our Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport.

ANSAC is considered a variable interest entity (VIE) because we experience certain risks and rewards from our relationship with it. As we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC. The ANSAC membership agreement provides that in the event an ANSAC member exits or the ANSAC cooperative is dissolved, the exiting members are obligated for their respective portion of the residual net assets or deficit of the cooperative. As of March 31, 2020, such amount is not estimable.

Net ~~sales~~Sales to ANSAC were ~~$31.8~~$73.1 million during the ~~period September 1, 2017 to September 30, 2017.~~three months ended March 31, 2020 and were $90.7 million during the three months ended March 31, 2019. The costs charged to us by ANSAC, included in operating costs, were ~~$0.5~~$0.8 million during the ~~period September 1, 2017 to~~ ~~September 30, 2017~~.three months ended March 31, 2020 and were $1.1 million during the three months ended March 31, 2019.

Receivables from and payables to ANSAC as of ~~September 30, 2017~~March 31, 2020 and December 31, 2019 are as follows:



	March 31,		December 31,
	2020		2019
Receivables:
ANSAC	$	66,256	$	68,075
Payables:
ANSAC	$	832	$	2,103

September 30,
2017
Receivables:
ANSAC $ 59,406

Payables:
ANSAC $ 1,317

~~13.~~

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

14. Supplemental Cash Flow Information

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



	Three Months Ended March 31,
	2020			2019
(Increase) decrease in:
Accounts receivable	$	101,405		$	18,170
Inventories	(5,024		)	(6,616		)
Deferred charges	2,783			(4,092		)
Other current assets	(3,746		)	(5,067		)
Increase (decrease) in:
Accounts payable	(62,365		)	5,226
Accrued liabilities	(25,519		)	(4,421		)
Net changes in components of operating assets and liabilities	$	7,534		$	3,200

Nine Months Ended
September 30,
2017 2016
(Increase) decrease in:
Accounts receivable $ (79,938 ) $ 11,029
Inventories 31,973
(26,215 )
Deferred charges (293 ) (5,291 )
Other current assets (2,769 ) 5,184
Increase (decrease) in:
Accounts payable 32,896
(27,213 )
Accrued liabilities (8,131 ) (20,901 )
Net changes in components of operating assets and liabilities (26,262 ) (63,407 )

Payments of interest and commitment fees were ~~$126.9~~$33.7 million and ~~$125.1~~$39.5 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~September 30, 2016,~~March 31, 2019, respectively. We capitalized interest of ~~$13.8~~$0.5 million and ~~$19.9~~$0.7 million during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~September 30, 2016.~~March 31, 2019, respectively.

At ~~September 30, 2017~~March 31, 2020 and ~~September 30, 2016,~~March 31, 2019, we had incurred liabilities for fixed and intangible asset additions totaling ~~$25.7~~$17.2 million and ~~$55.3~~$13.1 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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.

~~14.~~15. Derivatives

Commodity Derivatives

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

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

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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Additionally, we enter into swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales.

At March 31, 2020, we entered into the following outstanding derivative commodity contracts 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)	19		—
Weighted average contract price per bbl	$	37.01	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	248		217
Weighted average contract price per bbl	$	28.54	$	27.89
Natural gas swaps:
Contract volumes (10,000 MMBTU)	503		—
Weighted average price differential per MMBTU	$	0.37	$	—
Natural gas futures:
Contract volumes (10,000 MMBTU)	90		545
Weighted average contract price per MMBTU	$	1.72	$	2.43
Crude oil options:
Contract volumes (1,000 bbls)	55		10
Weighted average premium received/paid	$	3.71	$	9.52

Sell (Short)
Contracts

Buy (Long)
Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls) 694
—
Weighted average contract price per bbl $ 48.03
$ —

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls) 482
322
Weighted average contract price per bbl $ 50.17
$ 50.76
Diesel futures:
Contract volumes (1,000 bbls) 11
11
Weighted average contract price per bbl $ 1.71
$ 1.76
NYM RBOB Gas futures:
Contract volumes (42,000 gallons) —
4
Weighted average contract price per gallon $ —
$ 1.59
Fuel oil futures:
Contract volumes (1,000 bbls) 175
70
Weighted average contract price per bbl $ 48.10
$ 48.51
Crude oil options:
Contract volumes (1,000 bbls) 50
20
Weighted average premium received $ 0.63
$ 0.19

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, 2017~~March 31, 2020 and December 31, ~~2016~~2019:

Fair Value of Derivative Assets and Liabilities


	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value						Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	September 30, 2017			December 31, 2016			Unaudited Condensed Consolidated Balance Sheets Location	March 31, 2020			December 31, 2019
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	503		$	443		Current Assets - Other	$	1,303		$	207
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(503		)	(443		)	Current Assets - Other	(1,303		)	(207		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	—		$	—			$	—		$	—
Natural Gas Swap (undesignated hedge)								Current Assets - Other	511			1,382
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Current Assets - Other	$	43		$	3,321		Current Assets - Other	$	298		$	4
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(43		)	(3,321		)	Current Assets - Other	(298		)	(4		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	—		$	—			$	—		$	—
Liability Derivatives:
Preferred Distribution Rate Reset Election ⁽²⁾	Other long-term liabilities	(36,726		)	—			Other long-term liabilities	(18,970		)	(51,515		)
Natural Gas Swap (undesignated hedge)								Current Liabilities - Accrued Liabilities	(167		)	—
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,167	)	$	(1,772	)	Current Assets - Other ⁽¹⁾	$	(3,601	)	$	(2,079	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,167			1,772			Current Assets - Other ⁽¹⁾	3,446			1,064
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	—		$	—			$	(155	)	$	(1,015	)
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(2,643	)	$	(9,506	)	Current Assets - Other ⁽¹⁾	$	(8	)	$	(50	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	2,459			7,589			Current Assets - Other ⁽¹⁾	8			50
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives		$	(184	)	$	(1,917	)		$	—		$	—


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

(2) Refer to Note 910 and Note 1516 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.

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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, 2017~~March 31, 2020, we had a net broker receivable of approximately ~~$3.1~~$1.9 million (consisting of initial margin of ~~$2.4~~$1.0 million increased by ~~$0.7~~$0.9 million of variation margin). As of December 31, ~~2016~~2019, we had a net broker receivable of approximately $~~5.6~~0.9 million (consisting of initial margin of $~~5.1~~0.8 million increased by $~~0.5~~0.1 million of variation margin). At

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~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2017~~March 31, 2020 and December 31, ~~2016~~2019, 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.

Preferred Distribution Rate Reset Election

A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our ~~preferred units~~Class A Convertible Preferred Units may make a ~~Rate~~one-time election to reset the quarterly distribution amount (a "Rate Reset ~~Election~~Election") to a cash amount per ~~preferred unit~~Class A Convertible Preferred Unit equal to the amount that would be payable per quarter if a ~~preferred unit~~Class A Convertible Preferred Unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than ~~10%~~110% of the Issue Price. The Rate Reset Election of ~~the preferred units~~our Class A Convertible Preferred Units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Unaudited Condensed Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other ~~Expense~~Income (Expense) in our Unaudited Condensed Consolidated Statement of Operations. At ~~September 30, 2017,~~March 31, 2020, the fair value of this embedded derivative was a liability of ~~$36.7~~$19.0 million. See Note 910 for additional information regarding our ~~Series~~Class A ~~preferred units~~Convertible Preferred Units and the Rate Reset Election.

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended March 31,
		2020			2019
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Onshore facilities and transportation product costs	$	729		$	(742	)
Contracts not considered hedges under accounting guidance	Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs	(1,375		)	(6,692		)
Total commodity derivatives		$	(646	)	$	(7,434	)

Natural Gas Swap Liability	Sodium minerals and sulfur services operating costs	$	(432	)	$	1,519

Preferred Distribution Rate Reset Election	Other income (expense)	$	32,545		$	(2,976	)

Amount of Gain (Loss) Recognized in Income
Unaudited Condensed Consolidated Statements of Operations Location Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance Onshore facilities and transportation product costs $ (3,399 ) $ 1,672
$ 8,433
$ (8,279 )
Contracts not considered hedges under accounting guidance Onshore facilities and transportation product costs (1,329 ) (262 ) 650
(3,744 )
Total commodity derivatives $ (4,728 ) $ 1,410
$ 9,083
$ (12,023 )

Preferred Distribution Rate Reset Election Other expense $ (2,276 ) $ —
$ (2,276 ) $ —

~~15.~~16. 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

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(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.

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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, 2017~~March 31, 2020 and December 31, ~~2016.~~2019.



	Fair Value at									Fair Value at
	March 31, 2020									December 31, 2019
Recurring Fair Value Measures	Level 1			Level 2			Level 3			Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	1,601		$	511		$	—		$	211		$	1,382	$	—
Liabilities	$	(3,609	)	$	(167	)	$	—		$	(2,129	)	$	—	$	—
Preferred Distribution Rate Reset Election	$	—		$	—		$	(18,970	)	$	—		$	—	$	(51,515	)

Fair Value at Fair Value at
September 30, 2017 December 31, 2016
Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Commodity derivatives:
Assets $ 546
$ —
$ —
$ 3,764
$ —
$ —
Liabilities $ (3,810 ) $ —

$ (11,278 ) $ —
$ —
Preferred Distribution Rate Reset Election $ —
$ —
$ (36,726 ) $ —
$ —
$ —

Rollforward of Level 3 Fair Value Measurements

The following table provides a reconciliation of changes in fair value at the beginning and ending balances for our derivatives classified as level 3:



	Three Months Ended March 31,
	2020
Balance as of December 31, 2019	$	(51,515	)
Unrealized gain for the period included in earnings	32,545
Balance as of March 31, 2020	$	(18,970	)

Three Months Ended September 30, Nine Months Ended September 30,
2017 2017
Beginning Balance — —
Initial valuation of Preferred Distribution Rate Reset Election (34,450) (34,450)
Net Loss for the period included in earnings (2,276) (2,276)
Ending Balance (36,726) (36,726)

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. The fair value of the swaps contracts was determined using market price quotations and a pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at March 31, 2020.

The fair value of the embedded derivative feature is based on a valuation model that estimates the fair value of ~~the convertible preferred units~~our Class A Convertible Preferred Units with and without a Rate Reset Election. This model contains inputs, including our common unit price ~~a ten year history of~~relative to the issuance price, the current dividend yield, credit spread, default probabilities, equity volatility and timing estimates which involve management judgment. Our equity volatility rate used to value our embedded derivative feature was 50% at March 31, 2020. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. ~~We report~~During the 2020 Quarter, we recorded an unrealized ~~gains and losses associated with this embedded derivative~~gain of $32.5 million in ~~our~~Other income (expense) on the Unaudited Condensed Consolidated Statements of Operations ~~as Other income (expense), net.~~due to the significant changes in the energy industry credit markets and our common unit price during the period.

See Note 1415 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, 2017~~March 31, 2020 our senior unsecured notes had a carrying value of $2.5 billion and fair value of ~~$2.4~~$1.8 billion compared to ~~$1.8~~a carrying value and fair value of $2.5 billion ~~and $1.9 billion, respectively,~~ at December 31, ~~2016.~~2019. 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.

~~16.~~

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GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

17. Commitments and Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to aid in monitoring compliance and detecting and addressing releases of crude oil from our pipelines or other facilities and from our mining operations relating to our Alkali Business; 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.

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

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

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~17. Condensed Consolidating Financial Information~~

Our $2.4 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.~~

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Unaudited Condensed Consolidating Balance Sheet~~

~~September 30, 2017~~

Genesis
Energy, L.P.
(Parent and
Co-Issuer)

Genesis
Energy Finance
Corporation
(Co-Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
ASSETS
Current assets:
Cash and cash equivalents $ 6
$ —
$ 8,960
$ 728
$ —
$ 9,694
Other current assets 75
—
569,457
11,836
(238 ) 581,130
Total current assets 81
—
578,417
12,564
(238 ) 590,824
Fixed assets, at cost —
—
5,444,707
77,585
—
5,522,292
Less: Accumulated depreciation —
—
(655,808 ) (26,092 ) —
(681,900 )
Net fixed assets —
—
4,788,899
51,493
—
4,840,392
Mineral Leaseholds —
—
622,756
—
—
622,756
Goodwill —
—
325,046
—
—
325,046
Other assets, net 15,229
—
382,916
128,306
(151,026 ) 375,425
Advances to affiliates 3,889,517
—
—
82,479
(3,971,996 ) —
Equity investees —
—
383,191
—
—
383,191
Investments in subsidiaries 2,666,281
—
81,135
—
(2,747,416 ) —
Total assets $ 6,571,108
$ —
$ 7,162,360
$ 274,842
$ (6,870,676 ) $ 7,137,634
LIABILITIES AND CAPITAL
Current liabilities $ 34,731
$ —
$ 321,339
$ 8,092
$ (151 ) $ 364,011
Senior secured credit facility 1,372,500
—
—
—
—
1,372,500
Senior unsecured notes 2,358,049
—
—
—
—
2,358,049
Deferred tax liabilities —
—
26,399
—
—
26,399
Advances from affiliates —
—
3,971,992
—
(3,971,992 ) —
Other liabilities 36,727
—
183,552
187,057
(150,874 ) 256,462
Total liabilities 3,802,007
—
4,503,282
195,149
(4,123,017 ) 4,377,421
Mezzanine Capital:
Series A Convertible Preferred Units 691,708
—
—
—
—
691,708
Partners’ capital, common units 2,077,393
—
2,659,078
88,581
(2,747,659 ) 2,077,393
Noncontrolling interests —
—
—
(8,888 ) —
(8,888 )
Total liabilities, mezzanine capital and partners’ capital $ 6,571,108
$ —
$ 7,162,360
$ 274,842
$ (6,870,676 ) $ 7,137,634

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Unaudited Condensed Consolidating Balance Sheet~~

~~December 31, 2016~~

Genesis
Energy, L.P.
(Parent and
Co-Issuer)

Genesis
Energy Finance
Corporation
(Co-Issuer)

Guarantor
Subsidiaries

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

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Unaudited Condensed Consolidating Statement of Operations~~

~~Three Months Ended September 30, 2017~~

Genesis
Energy, L.P.
(Parent and
Co-Issuer)

Genesis
Energy Finance
Corporation
(Co-Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
REVENUES:
Offshore pipeline transportation services $ —
$ —
$ 80,671
$ —
$ —
$ 80,671
Sodium minerals and sulfur services —
—
109,292
2,069
(1,596 ) 109,765
Marine transportation —
—
48,534
—
—
48,534
Onshore facilities and transportation —
—
242,547
4,597
—
247,144
Total revenues —
—
481,044
6,666
(1,596 ) 486,114
COSTS AND EXPENSES:
Onshore facilities and transportation —
—
225,716
313
—
226,029
Marine transportation costs —
—
35,789
—
—
35,789
Sodium minerals and sulfur services operating costs —
—
78,869
2,092
(1,596 ) 79,365
Offshore pipeline transportation operating costs —
—
17,928
762
—
18,690
General and administrative —
—
19,409
—
—
19,409
Depreciation and amortization —
—
63,107
625
—
63,732
Gain on sale of assets —
—
—
—
—
—
Total costs and expenses —
—
440,818
3,792
(1,596 ) 443,014
OPERATING INCOME —
—
40,226
2,874
��
43,100
Equity in earnings of subsidiaries 55,971
—
(388 ) —
(55,583 ) —
Equity in earnings of equity investees —
—
13,044
—
—
13,044
Interest (expense) income, net (47,383 ) —
3,450
(3,455 ) —
(47,388 )
Other expense (2,276 ) —
—
—
—
(2,276 )
Income before income taxes 6,312
—
56,332
(581 ) (55,583 ) 6,480
Income tax benefit (expense) —
—
(322 ) 2
—
(320 )
NET INCOME 6,312
—
56,010
(579 ) (55,583 ) 6,160
Net loss attributable to noncontrolling interest —
—
—
152
—
152
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 6,312
$ —
$ 56,010
$ (427 ) $ (55,583 ) $ 6,312
Less: Accumulated distributions attributable to Series A Convertible Preferred Units (5,469 ) —
—
—
—
(5,469 )
NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 843
$ —
$ 56,010
$ (427 ) $ (55,583 ) $ 843

~~Table of Contents~~

~~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
Sodium minerals and sulfur services —
—
45,262
2,981
(2,518 ) 45,725
Marine transportation —
—
55,285
—
—
55,285
Onshore facilities and transportation —
—
264,326
4,997
—
269,323
Total revenues —
—
454,590
7,978
(2,518 ) 460,050
COSTS AND EXPENSES:
Onshore facilities and transportation costs —
—
252,450
255
—
252,705
Marine transportation costs —
—
38,490
—
—
38,490
Sodium minerals and sulfur services
operating costs
—
—
24,577
3,018
(2,518 ) 25,077
Offshore pipeline transportation operating costs —
—
22,533
589
—
23,122
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 expense —
—
—
—
—
—
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
Less: Accumulated distributions attributable to Series A Convertible Preferred Units —
—
—
—
—
—
NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 32,101
$ —
$ 66,850
$ (11 ) $ (66,839 ) $ 32,101

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Unaudited Condensed Consolidating Statement of Operations~~

~~Nine Months Ended September 30, 2017~~

Genesis
Energy, L.P.
(Parent and
Co-Issuer)

Genesis
Energy Finance
Corporation
(Co-Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
REVENUES:
Offshore pipeline transportation services $ —
$ —
$ 243,437
$ —
$ —
$ 243,437
Sodium minerals and sulfur services —
—
197,321
5,968
(5,410 ) 197,879
Marine transportation —
—
152,038
—
—
152,038
Onshore facilities and transportation —
—
700,908
14,066
—
714,974
Total revenues —
—
1,293,704
20,034
(5,410 ) 1,308,328
COSTS AND EXPENSES:
Onshore facilities and transportation costs —
—
661,842
853
—
662,695
Marine transportation costs —
—
111,980
—
—
111,980
Sodium minerals and sulfur services
operating costs
—
—
132,608
6,137
(5,410 ) 133,335
Offshore pipeline transportation operating costs —
—
52,396
2,286
—
54,682
General and administrative —
—
38,723
—
—
38,723
Depreciation and amortization —
—
174,578
1,875
—
176,453
Gain on sale of assets —
—
(26,684 ) —
—
(26,684 )
Total costs and expenses —
—
1,145,443
11,151
(5,410 ) 1,151,184
OPERATING INCOME —
—
148,261
8,883
—
157,144
Equity in earnings of subsidiaries 191,471
—
(1,033 ) —
(190,438 ) —
Equity in earnings of equity investees —
—
34,805
—
—
34,805
Interest (expense) income, net (122,060 ) —
10,436
(10,493 ) —
(122,117 )
Other expense (2,276 ) —
—
—
—
(2,276 )
Income before income taxes 67,135
—
192,469
(1,610 ) (190,438 ) 67,556
Income tax expense —
—
(880 ) 2
—
(878 )
NET INCOME 67,135
—
191,589
(1,608 ) (190,438 ) 66,678
Net loss attributable to noncontrolling interest —
—
—
457
—
457
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ 67,135
$ —
$ 191,589
$ (1,151 ) $ (190,438 ) $ 67,135
Less: Accumulated distributions attributable to Series A Convertible Preferred Units (5,469 ) —
—
—
—
$ (5,469 )
NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 61,666
$ —
$ 191,589
$ (1,151 ) $ (190,438 ) $ 61,666

~~Table of Contents~~

~~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
Sodium minerals and sulfur services —
—
129,671
5,499
(5,585 ) 129,585
Marine transportation —
—
159,930
—
—
159,930
Onshore facilities and transportation —
—
734,560
15,528
—
750,088
Total revenues —
—
1,268,998
21,027
(5,585 ) 1,284,440
COSTS AND EXPENSES:
Onshore facilities and transportation costs —
—
691,763
831
—
692,594
Marine transportation costs —
—
105,942
—
—
105,942
Sodium minerals and sulfur services operating costs —
—
67,190
6,036
(5,585 ) 67,641
Offshore pipeline transportation operating costs —
—
61,882
1,850
—
63,732
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 )
Other expense —
—
—
—
—
—
Income before income taxes 91,131
—
198,753
(540 ) (195,624 ) 93,720
Income tax (expense) benefit —
—
(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
Less: Accumulated distributions attributable to Series A Convertible Preferred Units —
—
—
—
—
$ —
NET INCOME AVAILABLE TO COMMON UNIT HOLDERS $ 91,131
$ —
$ 195,797
$ (173 ) $ (195,624 ) $ 91,131

~~Table of Contents~~

~~GENESIS ENERGY, L.P.~~

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~Unaudited Condensed Consolidating Statement of Cash Flows~~

~~Nine Months Ended September 30, 2017~~

Genesis
Energy, L.P.
(Parent and
Co-Issuer)

Genesis
Energy Finance
Corporation
(Co-Issuer)

Guarantor
Subsidiaries

Non-Guarantor
Subsidiaries
Eliminations
Genesis
Energy, L.P.
Consolidated
Net cash provided by operating activities $ 142,721
$ —
$ 333,709
$ (8,346 ) $ (250,294 ) $ 217,790
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets —
—
(182,653 ) —
—
(182,653 )
Cash distributions received from equity investees - return of investment —
—
14,517
—
—
14,517
Investments in equity investees (140,513 ) —
—
—
140,513
—
Acquisitions —
—
(1,325,759 ) —
—
(1,325,759 )
Intercompany transfers (1,238,585 ) —
—
—
1,238,585
—
Repayments on loan to non-guarantor subsidiary —
—
(159 ) —
159
—
Contributions in aid of construction costs —
—
124
—
—
124
Proceeds from asset sales —
—
39,204
—
—
39,204
Other, net —
—
—
—
—
—
Net cash used in investing activities (1,379,098 ) —
(1,454,726 ) —
1,379,257
(1,454,567 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility 1,247,700
—
—
—
—
1,247,700
Repayments on senior secured credit facility (1,153,400 ) —
—
—
—
(1,153,400 )
Proceeds from issuance of senior unsecured notes 550,000
—
—
—
—
550,000
Proceeds from issuance of Series A convertible preferred units, net

729,958
—
—
—
—
729,958
Debt issuance costs (17,808 ) —
—
—
—
(17,808 )
Intercompany transfers —
—
1,242,475
(3,890 ) (1,238,585 ) —
Issuance of common units for cash, net 140,513
—
140,513
—
(140,513 ) 140,513
Distributions to common unitholders (260,586 ) —
(260,586 ) —
260,586
(260,586 )
Contributions from noncontrolling interest —
—
—
1,850
—
1,850
Other, net —
—
1,215
10,451
(10,451 ) 1,215
Net cash used in financing activities 1,236,377
—
1,123,617
8,411
(1,128,963 ) 1,239,442
Net increase in cash and cash equivalents —
—
2,600
65
—
2,665
Cash and cash equivalents at beginning of period 6
—
6,360
663
—
7,029
Cash and cash equivalents at end of period $ 6
$ —
$ 8,960
$ 728
$ —
$ 9,694

~~Table of Contents~~

~~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 common unitholders (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

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

The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2019.

Included in Management’s Discussion and Analysis of Financial Condition and Results of Operations are the following sections:

Overview

Results of Operations

Liquidity and Capital Resources

Guarantor Summarized Financial Information

Non-GAAP Financial Measures

Commitments and Off-Balance Sheet Arrangements

Forward Looking Statements

Overview

On September 1, 2017, we completed the $1.325 billion accretive acquisition of Tronox Limited’s (“Tronox’s”) trona and trona-based exploring, mining, processing, producing, marketing and selling business (the "Alkali Business"). Our Alkali Business is the largest producer in the world of natural soda ash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of convertible preferred units, a $550 million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into a transition service agreement to facilitate the transition of operations and uninterrupted services for both employees and customers.

We recently made the strategic decision to re-set our quarterly distribution and provided a plan for visible, achievable long term distribution growth and a clear path forward to deleveraging. These steps, along with the future stable and repeatable cash flows from our recently completed acquisition of the Alkali Business as well as the anticipated ramp from our recent strategic investments, we believe further enhance our financial flexibility to opportunistically pursue accretive organic projects and acquisitions should they present themselves. In this context, however, we would reiterate, we currently have no plans to access the equity capital markets in the immediate future, including under our “at the market” equity program, which in fact has never been used. Overall, we believe these actions to strengthen our balance sheet and enhance our financial flexibility are the best actions we can take to allow us to generate strong total returns for our unitholders in the years ahead.

Our quarterly results were negatively impacted by a number of events, such as Hurricane Harvey (a 1,000-year hurricane), the planned regulatory dry-docking of our M/T American Phoenix as required every five years, some extended turnarounds at several offshore hubs, and turnarounds at several facilities in Alberta. Notwithstanding these negatives, our legacy businesses are performing as expected, and we are seeing increased contributions from our recently completed organic projects in the Baton Rouge corridor, in and around Texas City and in Wyoming. Additionally, the quarter reflects only one month of contribution from our recently acquired soda ash operations, which performance is exceeding our expectations.

~~Earlier this year, we announced and discussed our intent to market certain non-strategic assets with targeted proceeds of $50-$75 million. While not yet fully recognized in our~~ reported results, we have to date consummated sales for total cash proceeds of approximately $76 million, representing in the aggregate a GAAP gain of approximately $40 million and at an implied multiple to us of in excess of 30 times, none of which directly flows through our non-GAAP measures of EBITDA or Available Cash. We continue to evaluate other non-strategic assets in our portfolio, although there can be no assurances of additional transactions.

~~We reported net income attributable~~Net Income Attributable to Genesis Energy, L.P. of ~~$6.3~~$24.9 million ~~or $0.01 per common unit,~~ during the three months ended ~~September 30, 2017~~March 31, 2020 (“~~2017~~2020 Quarter”) compared to ~~net income attributable~~Net Income Attributable to Genesis Energy, L.P. of ~~$32.1~~$16.0 million ~~or $0.28 per common unit,~~ during the three months ended ~~September 30, 2016~~March 31, 2019 (“~~2016~~2019 Quarter”). Net Income Attributable to Genesis Energy, L.P. in the 2020 Quarter benefited from:

(i) an unrealized gain from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $32.5 million compared to an unrealized loss of $3.0 million during the 2019 quarter recorded in other income ~~was negatively affected by approximately $25.2~~(expense); (ii) lower general and administrative expenses of $2.3 million ~~or $0.21 per unit,~~primarily due to the assumptions used to value our long term incentive compensation plans during the 2020 Quarter; and (iii) lower depreciation, depletion and amortization expense of $3.3 million. These increases were offset by: (i) the transaction costs and ~~financing expenses, as well as an increase in interest expense, primarily driven by our acquisition~~write-off of the ~~Alkali Business~~unamortized issuance costs and discount associated with the extinguishment of our 2022 Notes of $23.5 million during the ~~quarter. For~~2020 Quarter included in Other income (expense); (ii) lower segment margin during the ~~2017~~2020 Quarter of $4.3 million; and (iii) $4.1 million of our ~~operating results include one month of activity related~~Net Income during the 2020 Quarter being attributed to ~~the Alkali Business for the month of September.~~our redeemable noncontrolling interests.

Cash flow from operating activities was ~~$33.8~~$89.6 million for the ~~2017~~2020 Quarter compared to ~~$124.7~~$114.0 million for the ~~2016~~2019 Quarter. ~~Cash flows from operating activities for~~This decrease is primarily attributable to transaction costs incurred during the ~~2017~~2020 Quarter ~~were also negatively affected by certain non-recurring costs~~

~~described above as well as an increase in net working capital that is not necessarily meaningful to~~associated with the ~~underlying performance~~tender and redemption of ~~the~~ our ~~businesses.~~2022 Notes.

Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") to our common unitholders was ~~$91.8~~$81.8 million for the ~~2017~~2020 Quarter, a decrease of ~~$3.2~~$14.1 million, or ~~3.4%~~14.7%, from the ~~2016~~2019 Quarter. Available Cash before Reserves for the 2020 Quarter is inclusive of the $18.7 million declared cash distribution to our Class A Convertible Preferred Unitholders that is attributable to the 2020 Quarter and will be paid on May 15, 2020. Available Cash before Reserves for the 2019 Quarter is inclusive of the $6.1 million cash distribution attributable to the period that was paid on May 15, 2019. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Segment Margin (as defined below in "Non-GAAP Financial Measures") was ~~$146.5~~$169.3 million for the ~~2017~~2020 Quarter, ~~an increase~~a decrease of ~~$5.2~~$4.3 million, or ~~3.7%~~2%, from the ~~2016~~2019 Quarter.

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

See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.

Distribution

In ~~October 2017,~~April 2020, we declared our quarterly distribution to our common unitholders ~~$0.50~~of $0.15 per ~~units~~unit related to the ~~2017 Quarter, which will be paid in November 2017.~~

2020 Quarter. With respect to our Class A Convertible Preferred Units, we ~~have~~ declared a ~~payment-in-kind ("PIK") of the~~ quarterly distribution, which will result in the issuance of an additional 162,234 Class A Convertible Preferred Units. This PIK amount, as pro-rated based on the period these units were outstanding, equates to acash distribution of ~~$0.2458~~$0.7374 per Class A Convertible Preferred Unit (or $2.9496 on an annualized basis) for ~~the 2017 Quarter, or $2.9496 annualized.~~each Class A Convertible Preferred Unit held of record. These distributions will be payable on ~~November 14, 2017~~May 15, 2020 to unitholders ~~holders~~ of record at the close of business on ~~November 3, 2017.~~May 1, 2020.

~~Segment Reporting Change~~

COVID-19 and Market Update

~~Beginning~~transportation sectors, are considered critical and essential by the Department of Homeland Security's CISA and we have continued to operate our assets during this pandemic.

We have designated an internal management team to provide resources, updates, and support to our entire workforce during this pandemic, while maintaining a focus to ensure the safety and well-being of our employees, the families of our employees, and the communities in which our businesses operate. We will continue to act in the ~~fourth quarter~~best interests of ~~2016,~~our employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or local authorities as we ~~started reporting~~actively monitor the situation.

COVID-19 has caused commodity prices to decline due to, among other things, reduced industrial activity and travel restrictions that are expected to continue in the near future. Additionally, actions taken by OPEC and other oil exporting nations beginning in early March 2020 have caused additional significant declines and volatility in the price of oil and gas. These low and volatile commodity prices are expected to continue at least for the near-term and possibly longer, reflecting fears of a global recession and potential further global economic damage from COVID-19, including factory shutdowns, travel bans, closings of schools and stores, and cancellations of conventions and similar events, resulting in, among other things, reduced fuel demand, lower manufacturing activity, and high inventories of oil, natural gas, and petroleum products, which could further negatively impact oil, natural gas, and petroleum products and industrial products.

We noted, other than the impact of general macroeconomic conditions, there were no material adverse effects from the pandemic on our results for the three months ended March 31, 2020. Although the potential future limitations and impact of COVID-19 are unknown at this time, and although we tend to experience less demand for certain of our services and products when commodity prices decrease significantly over extended periods of time (and we expect a similar impact on ~~a comparative basis~~demand when global restrictions are in ~~four~~place limiting the economy and industrial product use), we believe the fundamentals of our underlying businesses continue to remain strong and, given the current industry environment and capital market behavior, we have continued our focus on de-leveraging our balance sheet, which includes the reduction of our distribution to common unitholders. Finally, given the current operating environment, we are prudently looking at several initiatives to identify and implement cost reductions across our various business segments. ~~Due to~~During April 2020, we also amended our agreements with GSO associated with the ~~increasingly integrated nature~~expansion of our ~~onshore operations,~~Granger soda ash facility to, among other things, extend the results of our onshore pipeline transportation segment, formerly reported under its own segment, is now reported in our onshore facilities and transportation segment. The onshore facilities and transportation segment also now includes what was formerly reported in our supply and logistics segment. This segment was renamed in the second quarter of 2017 to more accurately describe the nature of its operations. We will report the resultsconstruction timeline of the ~~Alkali Business in our renamed sodium minerals and sulfur services segment, which will include the Alkali Business~~project by as ~~well~~much as ~~our existing refinery services operations.~~one year.

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

Results of Operations

Revenues and Costs and Expenses

Our revenues for the ~~2017~~2020 Quarter ~~increased $26.1~~decreased $80.1 million, or ~~5.7%~~13%, from the ~~2016 Quarter, which includes the effects of one month of revenue contributed by the Alkali Business. Additionally,~~2019 Quarter. In addition, our total costs and expenses ~~(excluding interest) increased $38.1~~as presented on the Unaudited Condensed Consolidated Statements of Operations decreased $77.2 million, or ~~9.4%~~14%, between those two periods. This includes approximately $10.2 million of third party financing, legal and accounting costs primarily attributable to the acquisition of the Alkali Business in the 2017 Quarter. Excluding these items, costs and expenses would have increased $27.9 million between the two periods.

A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products ~~through~~in our crude oil marketing business, which is included in the onshore facilities and transportation segment, and revenues and costs associated with our Alkali Business, which is included in the sodium minerals and sulfur services segment. The decrease in our revenues and costs ~~in this segment~~ between ~~those two quarterly periods~~the 2020 Quarter and the 2019 Quarter is primarily attributable toto: (i) decreases in crude oil and petroleum product prices and, to an extent, sales volumes; and (ii) negative impacts of contractual export pricing and soda ash volumes ~~as discussed further below. In general, we do not expect fluctuations~~ in our Alkali Business.

As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased 15.8% to $46.17 per barrel in the 2020 Quarter, as compared to $54.85 per barrel in the 2019 Quarter. Additionally, impacts from COVID-19 along with actions taken by OPEC and ~~natural~~other oil exporting nations beginning in early March 2020 have caused additional significant price declines and volatility in oil and gas prices. These low and volatile commodity prices are expected to ~~materially affect our net income, Available Cash before Reserves or Segment Margin~~continue at least for the near term and possibly longer. We would expect changes in crude oil prices to ~~the same extent they~~continue to proportionately affect our revenues and ~~costs.~~costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin, Net Income, and Available Cash before Reserves. We have limited our direct commodity price exposure related to crude oil and petroleum products through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin.

~~As discussed throughout this document and throughout our Annual Report on Form 10-K,~~ However, we do have some indirect exposure to certain changes in prices for ~~crude~~ oil, natural gas, and petroleum products, particularly if they are significant and extended. We tend to experience more demand for certain of our services when commodity prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when commodity 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~~" Risks Related to Our ~~Business”.~~Business."

~~Prices of crude oil have slightly recovered since the 2016 Quarter. The average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") increased 7.3%~~As it relates to ~~$48.21 per barrel in the 2017 Quarter, as compared to $44.94 per barrel in the 2016 Quarter. We would expect changes in crude oil prices to continue to proportionately affect~~our Alkali Business, our revenues ~~and costs attributable to our purchase~~are derived from the extraction of trona, as well as the activities surrounding the processing and sale of ~~crude oil~~natural soda ash and ~~petroleum~~other alkali specialty products, ~~producing minimal~~including sodium sesquicarbonate (S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an industry-diverse and worldwide customer base. Our selling prices are contracted at various times throughout the year and for different durations. Typically, our selling prices for volumes sold internationally and through ANSAC are contracted for the current year (in most cases, annually) in the prior December and January of the current year, and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. Our sales volumes can fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer demand and economic growth. Positive or negative changes to our revenue, through fluctuations in sales volumes or selling prices, can have a direct impact onto Segment Margin, ~~from those operations. However,~~Net Income and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the ~~indirect exposure to changes~~fact that a portion of our costs are fixed in ~~prices discussed above, the factors addressed~~nature. Our costs, of which some are variable in ~~our onshore facilities~~nature and ~~transportation segment discussion below, and the fact the crude oil prices have remained low for an extended period of time as compared~~others are fixed in nature, relate primarily to the ~~five year period before 2015,~~processing and producing of soda ash (and other alkali specialty products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during the 2020 Quarter as noted above, we had negative effects to our revenues (with a lesser impact to costs) due to lower export pricing and lower sales volumes of soda ash during the 2020 Quarter due to lower economic and market demand. For additional information, see our segment-by-segment analysis below.

In addition to our crude oil marketing business and ~~petroleum product sales volumes have continued~~Alkali Business discussed above, we continue to ~~decline, including a 19.0% decrease~~operate in ~~the 2017 Quarter as compared to the 2016 Quarter.~~

~~Within~~ our ~~legacy business we have two distinct, complementary types of operations-~~other core businesses including: (i) our onshore-based refinery-centric crude oil and refined petroleum products transportation, facilities, logistics, and handling operations, focusing predominantly on refinery-centric customers (as opposed to producers), and (ii) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large reservoir, long-lived crude oil and natural gas ~~properties.~~properties; (ii) our sulfur services business, which is one of the leading producers and marketers of NaHS in North and South America; and (iii) our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S., which focus on providing a suite of services primarily to refiners. Refiners are the shippers of ~~over 80%~~approximately 98% of the volumes transported on our onshore crude pipelines, and refiners contract for ~~over 85%~~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~~Their 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~~relatively low commodity price ~~environment.~~environments. Given these facts, we do not expect changes in commodity prices to impact our ~~net income,~~Net Income, Available Cash before Reserves or Segment Margin derived from our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil and petroleum products.

A portion of our revenues and costs are derived from the sale of natural soda ash, which has significant cost advantages over any synthetic production methods. We believe the significant cost advantage in the production of natural soda ash compared to synthetically produced soda ash will remain for the foreseeable future. Natural soda ash accounts for approximately 25% of the world's production and therefore given these facts, we believe we are able to somewhat mitigate the effects of market specific factors on Net Income, Available Cash before Reserves and Segment Margin in the soda ash market in which we operate. Additionally, changes in certain of our operating costs between the respective quarters, such as those associated with our sodium minerals and sulfur services, offshore pipeline and marine transportation segments, are not correlated with crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.

Segment Margin

The contribution of each of our segments to total Segment Margin in the ~~three~~2020 Quarter and ~~nine months ended September 30, 2017 and September 30, 2016~~the 2019 Quarter was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2020		2019
	(in thousands)				(in thousands)				(in thousands)
Offshore pipeline transportation	78,228		86,557		$	243,528	$	249,457	$	85,246	$	76,390
Sodium minerals and sulfur services	30,031		20,526		63,864		61,586		36,941		58,639
Onshore facilities and transportation	25,606		17,560		71,999		63,969		28,099		25,603
Marine transportation	12,649		16,697		39,768		53,695		19,002		12,932
Total Segment Margin	$	146,514	$	141,340	$	419,159	$	428,707	$	169,288	$	173,564

We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees and certain litigation expenses that are not deducted to determine our Pro Forma Adjusted EBITDA under our revolving credit facility. Our Segment Margin definition also includes the non-income portion of payments received under direct financing leases and eliminates non-cash revenues, expenses, gains, losses and charges (such as depreciation and amortization, unrealized gain or loss on derivative transactions not designated as hedges for accounting purposes,after eliminating gain or loss on sale of ~~non-surplus~~ assets, ~~and equity based compensation expense~~plus or minus applicable Select Items. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is ~~not settled in cash). Our reconciliation~~important to the evaluation of ~~total Segment Margin to net income reflects that Segment Margin (as defined~~

above) excludes corporate general and administrative expenses, non-cash gains and charges, depreciation, amortization and accretion, interest expense, certain non-cash items, and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes.our core operating results. See "Non-GAAP Financial Measures" for further discussion surrounding total Segment Margin.

A reconciliation of total Segment Margin to ~~net income~~Net Income Attributable to Genesis Energy, L.P. for the periods presented is as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
Total Segment Margin	$	146,514		$	141,340		$	419,159		$	428,707		$	169,288		$	173,564
Corporate general and administrative expenses	(18,230		)	(10,420		)	(33,694		)	(32,269		)	(6,492		)	(11,100		)
Depreciation, depletion, amortization and accretion	(66,436		)	(57,103		)	(184,213		)	(168,491		)	(75,978		)	(79,937		)
Interest expense	(47,388		)	(34,735		)	(122,117		)	(104,657		)	(54,965		)	(55,701		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(7,136		)	(9,063		)	(25,566		)	(30,818		)	(6,406		)	(4,828		)
Non-cash items not included in Segment Margin	(4,788		)	993			(6,218		)	(3,366		)
Other non-cash items ⁽²⁾													33,261			(6,091		)
Cash payments from direct financing leases in excess of earnings	(1,751		)	(1,586		)	(5,127		)	(4,645		)	(2,238		)	(2,028		)
Gain on sale of assets	—			—			26,684			—
Non-cash provision for leased items no longer in use	—			—			(12,589		)	—			130			190
Differences in timing of cash receipts for certain contractual arrangements ₍₂₎	5,847			3,624			11,694			9,629
Income tax expense	(320		)	(949		)	(878		)	(2,959		)
Net income attributable to Genesis Energy, L.P.	$	6,312		$	32,101		$	67,135		$	91,131
Differences in timing of cash receipts for certain contractual arrangements ⁽³⁾													(4,490		)	2,287
Loss on debt extinguishment ⁽⁴⁾													(23,480		)	—
Redeemable noncontrolling interest redemption value adjustments ⁽⁵⁾													(4,086		)	—
Income tax benefit (expense)													365			(402		)
Net Income Attributable to Genesis Energy, L.P.													$	24,909		$	15,954


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


(2)	The 2020 Quarter includes a $32.5 million unrealized gain from the valuation of the embedded derivative associated with our Class A Convertible Preferred units and the 2019 Quarter includes a $3.0 million unrealized loss from the valuation of the embedded derivative.


(3)	Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts.

~~(1)~~


(4)	Includes our transaction costs associated with the tender of $527.9 million and redemption of $222.1 million of our 2022 Notes in the first quarter of 2020, along with the write-off of our unamortized issuance costs and discount associated with these notes.

(5) Includes PIK distributions attributable to the ~~quarter~~period and ~~received during or promptly following such quarter.~~accretion on the redemption feature.

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

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,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
	(in thousands)						(in thousands)						(in thousands)
Offshore crude oil pipeline revenue	$	67,506		$	69,759		$	204,585		$	199,391
Offshore natural gas pipeline revenue	13,164			19,957			38,852			45,445
Offshore crude oil pipeline revenue, excluding non-cash revenues													$	69,581		$	64,194
Offshore natural gas pipeline revenue, excluding non-cash revenues													13,337			10,933
Offshore pipeline operating costs, excluding non-cash expenses	(15,979		)	(20,292		)	(46,859		)	(54,463		)	(17,732		)	(16,079		)
Distributions from equity investments ⁽¹⁾	19,535			20,880			59,100			64,502			20,060			17,342
Other	(5,998		)	(3,747		)	(12,150		)	(5,418		)
Offshore pipeline transportation Segment Margin	$	78,228		$	86,557		$	243,528		$	249,457		$	85,246		$	76,390

Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	203,697			190,613			220,374			200,753			242,182			241,754
Poseidon	257,093			263,519			258,031			259,446			279,181			253,469
Odyssey	135,787			107,252			122,433			106,622			149,440			151,877
GOPL ⁽²⁾	8,317			6,287			8,166			5,839
GOPL ⁽³⁾													7,249			8,337
Total crude oil offshore pipelines	604,894			567,671			609,004			572,660			678,052			655,437

Natural gas transportation volumes (MMBtus/d)	467,095			775,546			516,974			656,452			416,564			419,999

Volumetric Data net to our ownership interest ⁽³⁾:
Volumetric Data net to our ownership interest ⁽²⁾:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	203,697			190,613			220,374			200,753			242,182			241,754
Poseidon	164,540			168,652			165,140			166,045			178,676			162,220
Odyssey	39,378			31,103			35,506			30,920			43,338			44,044
GOPL ⁽²⁾	8,317			6,287			8,166			5,839
GOPL ⁽³⁾													7,249			8,337
Total crude oil offshore pipelines	415,932			396,655			429,186			403,557			471,445			456,355

Natural gas transportation volumes (MMBtus/d)	189,778			502,792			237,328			374,950			147,067			160,957


(1)	Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in ~~2017~~2020 and ~~2016,~~2019, respectively.


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


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


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

Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared with Three Months Ended ~~September 30, 2016~~

Offshore Pipeline Transportation Segment Margin for the 2017 Quarter decreased $8.3 million, or 10%, from the 2016 Quarter. The 2017 Quarter was negatively impacted by both anticipated and unanticipated downtime at several major fields, including weather related downtime, affecting certain of our deepwater Gulf of Mexico customers and thus certain of our key crude oil and natural gas assets, including our Poseidon pipeline and certain associated laterals which we own. While such downtime was temporary, we expect additional downtime relating to weather and maintenance involving certain customers' fields during the fourth quarter of 2017. The quarter also reflects the effects of a contractual step down to a lower transportation rate for a certain lateral which we own that will be in place going forward. In addition, the 2016 Quarter benefited from the temporary diversion of certain natural gas volumes from third party gas pipelines to one of our gas pipelines and related facilities due to disruptions at onshore processing facilities where such volumes typically flow.

~~Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016~~March 31, 2019

Offshore pipeline transportation Segment Margin for the first ~~nine~~three months of ~~2017 decreased $5.9~~2020 increased $8.9 million, or 2%12%, from the first ~~nine~~three months of ~~2016. The first nine months of 2017 was negatively impacted by both anticipated and unanticipated downtime at several major fields, including weather related downtime, affecting certain of~~2019, primarily due to higher volumes on our ~~deepwater Gulf of Mexico customers and thus certain of our key~~ crude oil pipeline systems. These increased volumes are primarily the result of first oil flow from the Buckskin and ~~natural gas assets, including~~Hadrian North production fields during the second quarter of 2019, both of which are fully dedicated to our SEKCO pipeline, and further downstream, our Poseidon oil pipeline system. Additionally, during the second half of 2019, we entered into agreements to move sixty thousand barrels per day on either CHOPS or Poseidon that are delivered to us by a third-party pipeline that has insufficient capacity. These agreements contain ship-or-pay provisions, have terms as long as five years and ~~certain associated laterals which we own. While such~~required no additional capital on our part.

We expect to see these increased volumes, outside of any unplanned downtime ~~was temporary,~~or our normal planned maintenance activities during the year, throughout 2020 as our newer projects continue to ramp. Additionally, we expect additional downtime relating to weather and maintenance involving certain customers' fields during the fourth quarter of 2017. The nine months ended September 30, 2017 also reflects the effects of a contractual step down to a lower transportation rate for a certain lateral which we own that will be in place going forward. In addition, the nine months ended September 30, 2016 benefitedvolumes throughout 2020 from the ~~temporary diversion of certain natural gas volumes~~recently announced production dedication from ~~third party gas pipelines~~Katmai and our previously contracted Atlantis Phase III development, which are both scheduled to ~~one of our gas pipelines and related facilities due to disruptions at onshore processing facilities where such volumes typically flow.~~come on-line during 2020.

Sodium Minerals and Sulfur Services Segment

Operating results for our sodium minerals and sulfur services segment were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2020		2019
Volumes sold:
NaHS volumes (Dry short tons "DST")	30,381		34,299		95,575		96,116		30,082		35,743
Soda Ash volumes (short tons sold) ⁽²⁾	336,000		—		336,000		—		822,247		870,529
NaOH (caustic soda) volumes (dry short tons sold) ⁽³⁾	21,746		19,653		55,962		59,802		16,303		20,802
Total	388,127		53,952		487,537		155,918

Revenues (in thousands):
NaHS revenues	$	33,702	$	37,054	$	105,209	$	103,680
NaHS revenues, excluding non-cash revenues									$	33,191	$	42,948
NaOH (caustic soda) revenues	11,145		9,872		29,511		28,816		7,441		11,813
Revenues associated with Alkali Business	65,554		—		65,554		—		176,236		203,330
Other revenues	1,355		1,143		3,963		3,941		643		1,616
Total external segment revenues	$	111,756	$	48,069	$	204,237	$	136,437
Total external segment revenues, excluding non-cash revenues⁽¹⁾									$	217,511	$	259,707

Segment Margin (in thousands)	$	30,031	$	20,526	$	63,864	$	61,586	$	36,941	$	58,639

Average index price for NaOH per DST ⁽¹⁾	$	647	$	496	$	613	$	453
Average index price for NaOH per DST⁽²⁾									$	648	$	717

(1) Totals are for external revenues and costs prior to intercompany elimination upon consolidation.

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

~~(2) Includes sales volumes from September 1, 2017, the date on which we acquired the Alkali Business.~~

~~(3) Caustic soda sales volumes also include volumes sold for the month of September from our new Alkali Business.~~

Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared with Three Months Ended ~~September 30, 2016~~March 31, 2019

Sodium minerals and sulfur services Segment Margin for the 2017 Quarter increased $9.5 million, or 46%. This increase is principally due to the inclusion of one month's contribution from the Alkali Business. This was partially offset by the results of our refinery services business and related NaHS and caustic soda activities. The 2017 Quarter results for these activities were in line with our expectations and include the effects of previously disclosed commercial discussions with certain of our host refineries and several NaHS customers, which resulted in extending the term and tenor of a large number of contractual relationships.

~~Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016~~

Sodium minerals and sulfur services Segment Margin for the first ~~nine~~three months of ~~2017 increased $2.3~~2020 decreased $21.7 million, or ~~4%.~~37% from the first three months of 2019. This ~~increase~~decrease is ~~principally~~primarily due to lower volumes and pricing in our Alkali Business and lower NaHS volumes in our refinery services business. During the ~~inclusion~~2020 Quarter, we experienced lower export pricing due to supply and demand imbalances that existed at the time of ~~one month's contribution from~~our re-contracting phase in December 2019 and January 2020, which is expected to continue, to some extent, for the ~~Alkali Business.~~rest of 2020 and until we re-contract such pricing at the end of the year for 2021 volumes. This was ~~partially offset by~~coupled with lower domestic sales of soda ash during the 2020 Quarter. We expect to see lower soda ash sales volumes in the next few quarters as a result of COVID-19 and until restrictions are lifted globally. In our refinery services business, we experienced a decline in NaHS volumes during the 2020 Quarter due to lower demand from certain of our domestic mining and pulp and paper customers. Costs impacting the results of our ~~refinery~~sodium minerals and sulfur services ~~business~~segment include costs associated with processing and ~~related~~producing soda ash (and other alkali specialty products), NaHS and ~~caustic soda~~marketing and selling activities. ~~The nine months ended September 30, 2017 results for these~~In addition, costs include activities ~~were in line~~associated with ~~our expectations~~mining and ~~include the effects of previously disclosed commercial discussions with certain of our host refineries~~extracting trona ore (including energy costs and ~~several NaHS customers, which resulted in extending the term and tenor of a large number of contractual relationships.~~employee compensation).

Onshore Facilities and Transportation Segment

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

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

~~transporting CO2~~


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

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

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

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

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

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

We also use our terminal facilities to take advantage of contango market conditions, to gather and market crude oil, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products. When we purchase and store crude oil during periods of contango, we attempt to limit direct commodity price risk by simultaneously entering into a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. In April 2020, crude oil price markets were in contango, so we anticipate that opportunities will exist to profit from this strategy for at least the next quarter.

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

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
	(in thousands)						(in thousands)						(in thousands)
Gathering, marketing, and logistics revenue	$	229,002		$	255,324		$	663,988		$	701,688		$	135,307		$	191,531
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines	17,261			13,219			48,606			44,773
Crude oil and CO₂ pipeline tariffs and revenues from direct financing leases of CO₂ pipelines													19,861			17,095
Payments received under direct financing leases not included in income	1,751			1,586			5,127			4,645			2,238			2,028
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(202,157		)	(230,760		)	(583,123		)	(621,500		)	(111,494		)	(167,378		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(21,199		)	(22,591		)	(64,799		)	(71,389		)
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses													(18,493		)	(18,718		)
Other	948			782			2,200			5,752			680			1,045
Segment Margin	$	25,606		$	17,560		$	71,999		$	63,969		$	28,099		$	25,603

Volumetric Data (average barrels per day):
Volumetric Data (average barrels per day unless otherwise noted):
Onshore crude oil pipelines:
Texas	45,329			11,529			28,418			41,708			84,499			42,981
Jay	13,716			15,119			14,480			14,494			10,013			11,483
Mississippi	8,104			9,503			8,478			10,607			6,409			5,916
Louisiana ⁽¹⁾	130,862			30,814			115,436			26,865			162,736			95,824
Wyoming	22,204			9,772			19,816			10,003
Onshore crude oil pipelines total	220,215			76,737			186,628			103,677			263,657			156,204

CO₂ pipeline (average Mcf/day):
Free State	68,363			88,026			73,042			101,157			134,834			105,991

Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	52,082			64,292			49,255			66,725			26,118			33,752
Rail load/unload volumes ⁽²⁾	42,221			13,091			55,010			13,344
Rail unload volumes													94,040			85,090

(1) Total daily volume for the three months ~~and nine months~~ ended ~~September 30, 2017 includes 66,048 and 54,974~~March 31, 2020 include 44,322 barrels per day ~~respectively~~ of intermediate refined products associated with our Port of Baton Rouge Terminal ~~pipelines which became operational in the fourth quarter of 2016. Additionally, this includes 19,574 and 6,925 barrels per day~~pipelines. Total daily volume for the three months ~~and nine months~~ ended ~~September 30, 2017 respectively~~March 31, 2019 includes 52,302 barrels per day of ~~crude oil~~intermediate refined products associated with our ~~new Raceland Pipeline which became fully operational in the second quarter~~Port of ~~2017.~~

~~(2) Indicates total barrels for either loading or unloading at all rail facilities.~~Baton Rouge Terminal pipelines.

Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared with Three Months Ended ~~September 30, 2016~~March 31, 2019

Onshore facilities and transportation Segment Margin for ~~our onshore facilities and transportation segment~~the first three months of 2020 increased by ~~$8.0~~$2.5 million, or ~~46%~~10%, ~~between~~from the ~~two~~first three ~~month periods. In the 2017 Quarter, this~~months of 2019. This increase is primarily ~~attributable~~due to ~~the ramp up in~~increased volumes on our Texas and Louisiana crude oil pipeline systems, and slightly increased overall volumes at our rail unload facilities. During the 2020 Quarter, we were able to recognize incremental margin on the increased volumes on our Texas system as our main customer utilized all of its prepaid transportation credits during 2019. Additionally, our pipeline, rail and terminal ~~infrastructure on our recently completed infrastructure~~assets in the Baton Rouge ~~corridor. In addition, relative to~~corridor had significantly higher volumes during the ~~2016~~2020 Quarter ~~we experienced an increase in volumes on our Texas pipeline system~~ as the ~~repurposing~~2019 Quarter was negatively impacted by production curtailments imposed by the government of ~~our Houston area crude oil pipeline and expansion of our terminal infrastructure became operational in the second quarter of 2017.~~

~~Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016~~

Segment Margin for our onshore facilities and transportation segment increased by $8.0 million, or 13%, between the first nine months of 2017 and the first nine months of 2016. The nine months of 2017 include the effects of the ramp up in volumes on our pipeline, rail and terminal infrastructure on our recently completed infrastructure in the Baton Rouge corridor. This was principallyAlberta. These increases were partially offset by lower ~~demand for~~volumes at our ~~services~~Raceland rail facility during the 2020 Quarter. Due to the significant decline in ~~our historical back-to-back, or buy/sell,~~ crude oil ~~marketing business associated with aggregating~~prices and ~~trucking crude oil from producers' leases to local or regional re-sale points. In addition,~~ the ~~first nine months~~collapse in the differential of 2017 were negatively impacted by lower volumes on our Texas pipeline system, as the repurposing of our Houston area crude oil pipeline and expansion of our terminal infrastructure did not became operational until the second quarter of 2017 while the first nine months of 2016 included historical volumes on our legacy Texas pipeline system assets priorWestern Canadian Select (WCS) to the ~~repurposing project for~~Gulf Coast, which has made crude-by-rail to the ~~majority~~Gulf Coast uneconomic, we are currently anticipating volume throughput at our Baton Rouge facilities will be below our minimum take-or-pay levels throughout the rest of 2020 and we would expect to recognize our minimum volume commitment in segment margin during the ~~period.~~related periods.

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 8691 barges ~~(77~~(82 inland and 9 offshore) with a combined transportation capacity of ~~3.0~~3.2 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,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
Revenues (in thousands):
Inland freight revenues	$	19,666		$	22,108		$	61,725		$	66,402		$	27,572		$	25,126
Offshore freight revenues	17,468			23,271			54,912			66,240			21,091			18,300
Other rebill revenues ⁽¹⁾	11,400			9,906			35,401			27,288			13,683			13,224
Total segment revenues	$	48,534		$	55,285		$	152,038		$	159,930		$	62,346		$	56,650

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	35,885		$	38,588		$	112,270		$	106,235
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses													$	43,344		$	43,718

Segment Margin (in thousands)	$	12,649		$	16,697		$	39,768		$	53,695		$	19,002		$	12,932

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	90.8		%	87.6		%	90.5		%	91.4		%	93.4		%	96.6		%
Offshore Barge Utilization	99.3		%	96.2		%	98.4		%	91.2		%	99.4		%	96.3		%

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

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

Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared with Three Months Ended ~~September 30, 2016~~March 31, 2019

Marine ~~Transportation~~transportation Segment Margin for the ~~2017 Quarter decreased $4.0~~first three months of 2020 increased $6.1 million, or ~~24%~~47%, from the ~~2016 Quarter. The decrease~~first three months of 2019. During the 2020 Quarter, in ~~Segment Margin is primarily due to lower day~~our offshore barge operation, we benefited from the continual improving rates ~~on our inland~~in the spot and ~~offshore fleets (which offset higher~~short term markets along with reported utilization ~~as adjusted for planned dry docking time)~~level of 99.4%. ~~The M/T American Phoenix was also undergoing planned regulatory dry docking inspections for approximately one month during the 2017 Quarter, which negatively impacted Segment Margin.~~ In our inland ~~fleet, weaker demand~~business, we continued to ~~apply pressure on our~~see increased day rates throughout the period which ~~we expect to continue into~~more than offset the ~~fourth quarter. In our offshore barge fleet, as a number of our units have come off longer term contracts, we~~slightly lower utilization reported. We have continued to ~~choose to primarily place them in spot service or short-term~~enter into short term contracts (less than a year) ~~service, as~~in both the inland and offshore markets because we ~~continue to~~ believe the day rates currently being offered by the market ~~are at, or approaching,~~have yet to fully recover from their cyclical lows.

~~Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016~~

Marine transportation Segment Margin for the first nine months of 2017 decreased $13.9 million, or 26%, from the first nine months of 2016. The decrease in Segment Margin is primarily due to lower day rates on our inland and offshore fleets (which offset higher utilization as adjusted for planned dry docking time). The M/T American Phoenix was also undergoing planned regulatory dry docking inspections for approximately one month during the 2017 Quarter, which negatively impacted Segment Margin. In our inland fleet, weaker demand continued to apply pressure on our rates, which we expect to continue into the fourth quarter. In our offshore barge fleet, as a number of our units have come off longer term contracts, we have continued to choose to primarily place them in spot service or short-term (less than a year) service, as we continue to believe the day rates currently being offered by the market are at, or approaching, cyclical lows.

Other Costs, Interest, and Income Taxes

General and administrative expenses


	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
	2017			2016		2017			2016		2020			2019
	(in thousands)					(in thousands)					(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	7,456		$	7,692	$	24,735		$	26,068	$	10,793		$	9,480
Segment	3,233			1,918		4,809			3,364		1,065			1,159
Equity-based compensation plan expense	(1,875		)	1,239		(2,330		)	3,918
Long-term incentive compensation expense											(2,485		)	930
Third party costs related to business development activities and growth projects	10,595			363		11,509			1,366		—			117
Total general and administrative expenses	$	19,409		$	11,212	$	38,723		$	34,716	$	9,373		$	11,686

Total general and administrative expenses ~~increased $8.2~~decreased by $2.3 million ~~and $4.0 million between~~during the ~~three and nine month periods~~2020 period primarily ~~attributable~~due to ~~the third party financing, legal and accounting costs surrounding our acquisition of the Alkali Business in the 2017 Quarter. This was partially offset by~~ the effects of changes in assumptions used to value our ~~equity based~~long-term incentive compensation ~~awards that are tied to our unit price.~~awards. This was partially offset by overall increases in corporate general and administrative expenses.

Depreciation, depletion, and amortization expense


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2020		2019
	(in thousands)				(in thousands)				(in thousands)
Depreciation and depletion expense	$	57,498	$	46,909	$	157,819	$	135,428	$	70,205	$	72,991
Amortization of intangible assets	5,879		6,122		17,623		18,154
Amortization expense									4,152		4,289
Amortization of CO2 volumetric production payments	355		1,234		1,011		3,218		—		358
Total depreciation, depletion and amortization expense	$	63,732	$	54,265	$	176,453	$	156,800	$	74,357	$	77,638

Three Months Ended March 31, 2020 Compared with Three Months Ended March 31, 2019

Total depreciation, depletion, and amortization expense ~~increased $9.5~~decreased $3.3 million during the 2020 Quarter. This decrease is primarily due to the 2019 Quarter including an increase in depreciation charges associated with one of our non-core gas offshore assets in which the abandonment timing was accelerated, and ~~$19.7 million between the three~~a slight decrease in amortization expense. This was partially offset by an overall increase in our depreciable asset base due to our continued growth and ~~nine month periods primarily as a result of~~maintenance capital expenditures and placing ~~additional~~new assets into service ~~including those acquired as a part of the Alkali Business in the 2017 Quarter.~~during 2019 and 2020.

Interest expense, net


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2020			2019
	(in thousands)						(in thousands)						(in thousands)
Interest expense, senior secured credit facility (including commitment fees)	$	13,150		$	11,076		$	37,307		$	31,117		$	10,745		$	14,158
Interest expense, senior unsecured notes	33,276			28,609			90,495			85,828			42,358			39,547
Amortization of debt issuance costs and discount	2,894			2,571			8,154			7,563			2,391			2,682
Capitalized interest	(1,932		)	(7,521		)	(13,839		)	(19,851		)	(529		)	(686		)
Net interest expense	$	47,388		$	34,735		$	122,117		$	104,657		$	54,965		$	55,701

Three Months Ended March 31, 2020 Compared with Three Months Ended March 31, 2019

Net interest expense ~~increased $12.7~~decreased $0.7 million ~~and $17.5 million between~~during the ~~three and nine month periods~~2020 Quarter primarily due to ~~an increase~~a lower average outstanding balance and interest rate on our revolving credit facility during the period. The decline in our ~~average outstanding indebtedness from acquired and constructed assets, including~~interest rate during the ~~financing~~2020 Quarter is due to the decrease in LIBOR rates during the period, which is one of the ~~acquisition~~main drivers of interest expense on our credit facility. These decreases were partially offset by higher interest expense during the ~~Alkali Business from Tronox in the 2017 Quarter. In addition, capitalized~~period on our senior unsecured notes. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest ~~decreased as result of certain~~at 7.75% and we purchased and extinguished $527.9 million of our ~~large organic growth projects being completed~~$750 million 2022 Notes that accrued interest at 6.75% on January 15, 2020 through our tender offer and ~~placed into service during previous quarters in 2017.~~we redeemed the remaining $222.1 million of our 2022 Notes on February 16, 2020.

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 2017 Quarter included a $2.5 million unrealized loss on derivative positions as compared to a $0.6 million unrealized gain on derivative positions in the 2016 Quarter. Net income for the first nine months of 2017 included an unrealized loss on derivative positions, excluding fair value hedges, of $3.0 million. Net income for the first nine months of 2016 included an unrealized loss on derivative positions of $0.7 million.

Liquidity and Capital Resources

General

As of ~~September 30, 2017~~March 31, 2020, ~~we had~~ ~~$314.7~~our balance sheet and liquidity position remained strong, including $721.5 million of remaining borrowing capacity under our ~~$1.7~~$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 and reducing outstanding debt; and

quarterly cash distributions to our preferred and common unitholders.

~~As discussed in our recently announced strategic reallocation of capital, we intend to allocate more capital to debt repayments and growth opportunities (and less to current distributions).~~

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~~necessary funds on satisfactory terms or implement our growth strategy successfully.

At ~~September 30, 2017,~~March 31, 2020, our long-term debt totaled $4approximately $3.4 billion, consisting of ~~$1.4 billion~~$977.4 million outstanding under our credit facility (including ~~$39~~$7.7 million borrowed under the inventory sublimit tranche) and ~~$2.4~~$2.5 billion of senior unsecured notes, ~~comprised of~~ ~~$350 million~~ ~~carrying amount due on~~ ~~February 15, 2021~~,comprising $400 million carrying amount due on May 15, 2023, ~~$350~~$349 million carrying amount due on June 15, 2024, ~~$750 million carrying amount due August 1, 2022 and~~ $550 million carrying amount due October ~~2025.~~2025, $447 million carrying amount due May 2026, and $750 million carrying amount due February 15, 2028.

On ~~August 14, 2017,~~September 23, 2019, we ~~issued $550~~announced the expansion of our existing Granger facility (the "Granger Optimization Project" or "GOP"). We entered into agreements with GSO for the purchase of up to approximately $350 million ~~in aggregate principal amount~~ of ~~6.50% senior unsecured notes due October 1, 2025. Interest payments are due April 1 and October 1~~preferred units of ~~each year with the initial interest payment due April 1, 2018. That issuance generated net~~Alkali Holdings. The proceeds ~~of $540.1 million, net of issuance costs incurred. The net proceeds were used~~received from GSO will fund up to ~~fund a portion~~100% of the ~~purchase price for our acquisition~~anticipated cost of the ~~Alkali Business.~~

~~In July 2017,~~GOP. On April 14, 2020, we ~~amended~~entered into an amendment to our ~~credit agreement~~agreements with GSO to, among other things, ~~make certain technical amendments related to~~extend the ~~financing of our acquisition~~construction timeline of the Granger expansion project by one year. The extended completion date of the project is mid to late 2023. The Alkali ~~Business.~~

OnHoldings preferred unitholders will receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of March ~~24, 2017,~~31, 2020 we had issued 4,600,000 Class A common units in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of offering costs, of approximately $140.5 million from that offering.

~~Class A Convertible Preferred Units~~

~~On September 1, 2017, we sold $750~~$130 million of ~~Class A convertible~~Alkali Holdings preferred units ~~in a private placement, comprised of 22,249,494 units for a cash purchase price~~to be used to fund the construction. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our preferred units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those preferred units.

Each of our preferred units accumulate quarterly distribution amounts in arrears at an annual rate of 8.75% (or $2.9496), yielding a quarterly rate of 2.1875% (or $0.7374), subject to certain adjustments. With respect to any quarter ending on or prior to March 1, 2019, we have the option to pay to the holders of our preferred units the applicable distribution amount in cash, preferred units, or any combination thereof. If we elect to pay all or any portion of a quarterly distribution amount in preferred units, the number of such preferred units will equal the product of (i) the number of then outstanding preferred units and (ii) the quarterly rate. We have elected to pay the distribution amount attributable to the quarter ended on September 30, 2017 in preferred units. For each quarter ending after March 1, 2019, we must pay all distribution amounts in respect of our preferred units in cash.

The Rate Reset Election of these preferred units represents and embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Unaudited Condensed Consolidated Balance Sheet. See further information in ~~Note 14. The preferred units themselves are classified as mezzanine capital on our Condensed Consolidated Balance Sheet.~~

~~See Note 9 for additional information regarding our preferred units.~~year.

Equity Distribution Program and Shelf Registration Statements

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

In 2016, we implemented an equity distribution program that will allow us to consummate “at the market” offerings of common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue additional common units from time to time, although there are limits to the amount of our “at the market” offerings the market can absorb from time to time.transactions. 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 $1.0 billion of equity and debt securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in October 2020. As of ~~September 30, 2017,~~March 31, 2020, we ~~have~~had issued no ~~additional~~ units under this program.

We have another universal shelf registration statement (our ~~"2015~~"2018 Shelf") on file with the SEC. Our ~~2015~~2018 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~~2018 Shelf will expire in April ~~2018.~~2021. We expect to file a replacement universal shelf registration statement before our ~~2015~~2018 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.~~expenditures and asset retirement obligations (if any). 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 purchased crude oil in the same month in which we ~~purchase~~acquire 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 onshore facilities and transportation activities, we ~~buy~~purchase 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.

In our Alkali Business, we typically extract trona from our mining facilities, process it into soda ash and other alkali products, and deliver and sell the alkali products to our customers all within a relatively short time frame. If we do experience any differences in timing of extraction, processing and sales of our trona or alkali products, it could impact the cash requirements for these activities in the short term.

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

See Note 1314 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~September 30, 2016.~~March 31, 2019.

Net cash flows provided by our operating activities for the ~~Nine Months Ended September 30, 2017~~three months ended March 31, 2020 were ~~$217.8~~$89.6 million compared to ~~$228.4~~$114.0 million for the ~~Nine Months Ended September 30, 2016.~~three months ended March 31, 2019. This decrease ~~in operating cash flow~~ is primarily ~~due~~attributable to ~~an increase in working capital needs.~~transaction costs incurred during the 2020 Quarter associated with the tender and redemption of our 2022 Notes.

Capital Expenditures, Distributions and ~~Distributions Paid to our Unitholders~~Certain Cash Requirements

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 preferred and common 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.

We currently plan to allocate a substantial portion of our excess cash flow to reduce the balance outstanding under our revolving credit facility and to opportunistically repurchase our outstanding senior unsecured notes.

Capital Expenditures ~~and Business and Asset Acquisitions~~

A summary of our expenditures for fixed assets, business and other asset acquisitions for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~September 30, 2016~~March 31, 2019 is as follows:


	Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2020		2019
	(in thousands)				(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets	$	4,093	$	1,198	$	768	$	433
Sodium minerals and sulfur services assets	1,616		1,645		4,575		8,048
Marine transportation assets	17,439		11,358		14,232		9,228
Onshore facilities and transportation assets	3,213		9,478		908		199
Information technology systems	53		404		75		141
Total maintenance capital expenditures	26,414		24,083		20,558		18,049
Growth capital expenditures:
Offshore pipeline transportation assets	$	4,405	$	7,777	259		25
Sodium minerals and sulfur services assets	5,276		—		10,400		14,658
Marine transportation assets	27,057		51,570		—		—
Onshore facilities and transportation assets	112,450		249,203		249		576
Information technology systems	114		6,398		1,178		—
Total growth capital expenditures	149,302		314,948		12,086		15,259
Total capital expenditures for fixed and intangible assets	175,716		339,031		32,644		33,308
Capital expenditures for acquisitions, inclusive of working capital acquired:
Acquisition of Alkali business	1,325,000		—
Acquisition of remaining interest in Deepwater Gateway ⁽¹⁾	—		26,200
Total business combinations capital expenditures	1,325,000		26,200
Capital expenditures related to equity investees	—		—
Total capital expenditures	$	1,500,716	$	365,231	$	32,644	$	33,308


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

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

Growth Capital Expenditures

On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with GSO for the purchase of up to approximately $350 million of preferred units of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. The extended completion date of the project is mid to late 2023. The Alkali Holdings preferred unitholders will receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of March 31, 2020 we had issued $130 million of Alkali Holdings preferred units to be used to fund the construction. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.

Except for the Granger Optimization Project, we do not anticipate spending ~~approximately $45.0 million, inclusive of capitalized interest,~~material growth capital expenditures on any individual projects during 2020.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred during the ~~remainder of 2017 for projects currently under construction. The most significant of~~2020 Quarter primarily relate to expenditures in our ~~recent projects are described below.~~

~~Baton Rouge Area Infrastructure Expansion~~

~~We are currently expanding~~Alkali Business and in our ~~existing Baton Rouge area infrastructure~~marine transportation segment. Our Alkali Business, which is included in our sodium minerals and sulfur services segment, incurs expenditures to ~~allow for greater capacity~~maintain its equipment and flexibility in servicing our major refinery customer in the region. This expansion includes the construction of an additional 500,000 barrels of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes received at our Baton Rouge area facilities. We expect these assets to become operational in the first quarter of 2018.

~~Houston Area Crude Oil Pipeline and Terminal Infrastructure~~

~~We have constructed new, and expanded existing, crude oil pipeline and terminal~~ facilities in Webster, Texas and Texas City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We have also constructed a new crude oil pipeline that delivers crude oil received from upstream crude oil pipelines (including CHOPS, which delivers crude oil originating in the deepwater Gulf of Mexicodue to the ~~Texas City area) to~~nature of its operations. Our marine transportation segment incurs expenditures as we frequently replace and upgrade certain equipment associated with our ~~new Texas City Terminal, which connects to~~barge and vessel fleet during our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal includes approximately 750,000 barrels of crude oil tankage. As a part of this project, we have also made the necessary upgrades on our existing 18-inch Webster to Texas City crude oil pipeline to reverse the direction of flow. The result of this expanded crude oil

~~infrastructure allows additional optionality to Houston~~planned and Baytown area refineries, including the ExxonMobil Baytown refinery, its largest refinery in the U.S.A., and provides additional delivery outlets for other crude oil pipelines. These assets became operational in the second quarter of 2017.

~~Raceland Terminal and Crude Oil Pipeline~~

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

~~InlandMarine 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 23 of those barges and 18 of those push boats through September 30, 2017. We expect to take delivery of those remaining barges periodically through 2017 and 2018.

~~Maintenance Capital Expenditures~~

Our slight increase in maintenance capital expenditures for the nine months ended September 30, 2017 Quarter as compared to the nine months ended September 30, 2016 Quarter principally relates to an increase in marine maintenance capital spending as a result of higher spending on certain vessel replacement parts and components.unplanned drydocks. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.

~~Proceeds from Assets Sales~~

The nine months ended September 30, 2017 include proceeds from asset sales of $39.2 million, as compared to proceeds of $3.3 million during the nine months ended September 30, 2016. This is principally comprised of the sale of certain non-core natural gas gathering and platform assets in the Gulf of Mexico in the second quarter of 2017. Subsequent to the end of the 2017 Quarter, we sold a non-core crude oil terminal facility in the Permian Basin, which completed a series of smaller asset sales totaling approximately $76 million (inclusive of non-core asset sales recognized through September 30, 2017).

Distributions to Unitholders

~~As recently announced as part of our strategic reallocation of capital, we reset our common unit distribution to $0.50 per common unit.~~ On ~~November 14, 2017,~~May 15, 2020, we will pay a distribution of ~~$0.50~~$0.15 per common unit totaling ~~$61.3~~$18.4 million with respect to the ~~2017 Quarter to common unitholders of record on October 31, 2017.~~2020 Quarter. Information on our recent distribution history is included in Note 109 to our Unaudited Condensed Consolidated Financial Statements.

With respect to our Class A Convertible Preferred Units, we ~~have~~ declared a ~~payment-in-kind ("PIK") of the~~ quarterly distribution, which will result in the issuance of an additional 162,234 Class A Convertible Preferred Units. This PIK amount, as pro-rated based on the period these units were outstanding, equates to acash distribution of ~~$0.2458~~$0.7374 per Class A Convertible Preferred Unit (or $2.9496 on an annualized basis) for ~~the 2017 Quarter, or $2.9496 annualized.~~each Class A Convertible Preferred Unit held of record. These distributions will be payable on ~~November 14, 2017~~May 15, 2020 to unitholders ~~holders~~ of record at the close of business on ~~November 3, 2017.~~May 1, 2020.

Guarantor Summarized Financial Information

Our $2.5 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 (the "Guarantor Subsidiaries), except the subsidiaries that hold our Alkali Business (collectively, the "Alkali Subsidiaries"), Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and certain other 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. The Guarantor Subsidiaries largely own the assets that we use to operate our business other than our Alkali Business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Alkali Holdings and Genesis Energy, L.P., to the extent agreed to in the Services Agreement. Genesis Energy Finance Corporation has no independent assets or operations. See Note 9 for additional information regarding our consolidated debt obligations.

The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes, the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution of such Guarantor Subsidiary (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.

The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.

The following is the summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a combined basis after elimination of intercompany transactions, which includes related receivable and payable balances, and the investment in and equity earnings from the Non-Guarantor Subsidiaries.



Balance Sheets	Genesis Energy, L.P. and Guarantor Subsidiaries
	March 31, 2020		December 31, 2019
ASSETS:
Current assets	$	251,305	$	323,492
Fixed assets, net	3,504,222		3,538,450
Non-current assets	923,194		951,276

LIABILITIES AND CAPITAL:⁽¹⁾
Current liabilities	230,092		292,941
Non-current liabilities	3,721,378		3,738,816
Class A Convertible Preferred Units	790,115		790,115



Statements of Operations	Genesis Energy, L.P. and Guarantor Subsidiaries
	Three Months Ended March 31, 2020			Twelve Months Ended December 31. 2019
Revenues	$	357,658		$	1,617,170
Operating costs	305,712			1,454,040
Operating income	51,946			163,130
Income before income taxes	24,907			566
Net income (loss) ⁽¹⁾	25,273			(122		)
Less: Accumulated distributions to Class A Convertible Preferred Units	(18,684		)	(74,467		)
Net income (loss) available to common unitholders	6,589			(74,589		)

(1) There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for either period presented.

Excluded from non-current assets in the table above are $79.6 million and $76.2 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the Non-Guarantor Subsidiaries as of March 31, 2020 and December 31, 2019, respectively.

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,
2017 2016
(in thousands)
Net income attributable to Genesis Energy, L.P. $ 6,312
$ 32,101
Depreciation, depletion, amortization and accretion 66,436
57,103
Cash received from direct financing leases not included in income 1,751
1,586
Cash effects of sales of certain assets 967
120
Effects of distributable cash generated by equity method investees not included in income 7,136
9,063
Expenses related to acquiring or constructing growth capital assets 10,595
363
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value 2,168
(571 )
Maintenance capital utilized ⁽¹⁾
(3,375 ) (1,885 )
Non-cash tax expense 150
649
Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾
(5,847 ) (3,624 )
Other items, net 5,514
107
Available Cash before Reserves 91,807
95,012



	Three Months Ended March 31,
	2020			2019
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	24,909		$	15,954
Income tax (benefit) expense	(365		)	402
Depreciation, depletion, amortization and accretion	75,978			79,937
Plus (minus) Select Items, net	4,806			12,016
Maintenance capital utilized ⁽¹⁾	(8,800		)	(6,125		)
Cash tax expense	(150		)	(150		)
Distributions to preferred unitholders	(18,684		)	(6,138		)
Redeemable noncontrolling interest redemption value adjustments ⁽²⁾	4,086			—
Available Cash before Reserves	$	81,780		$	95,896


(1)	For a description of the term "maintenance capital ~~utilized,"~~utilized", please see the definition of the term "Available Cash ~~Before~~before Reserves" discussed below. Maintenance capital expenditures in the 2020 Quarter and 2019 Quarter were $20.6 million and $18.0 million, respectively.


(2)	~~Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in~~Includes PIK distributions attributable to the period ~~in which such payments are received.~~and accretion on the redemption feature.

We define Available Cash before Reserves (“Available Cash before Reserves”) as net income before interest, taxes, depreciation, depletion, and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, “Select Items”), as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, net interest expense, cash tax expense, and cash distributions to our preferred unitholders. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.

Three Months Ended
September 30,
2017 2016
(in thousands)
Cash Flows from Operating Activities $ 33,836
$ 124,725
Adjustments to reconcile net cash flow provided by operating activities to Available Cash before Reserves:
   Maintenance capital utilized ⁽¹⁾
(3,375 ) (1,885 )
   Proceeds from certain asset sales 967
120
   Amortization and writeoff of debt issuance costs, including premiums and discounts (2,894 ) (2,571 )
   Effects of available cash of equity method investees not included in operating cash flows 4,194
4,801
   Net changes in components of operating assets and liabilities not included in calculation
   of Available Cash before Reserves
34,575
(26,834 )
   Non-cash effect of equity based compensation expense 3,566
(2,047 )
   Expenses related to acquiring or constructing assets that provide new sources of cash flow 10,595
363
   Differences in timing of cash receipts for certain contractual arrangements ⁽²⁾
(5,847 ) (3,624 )
   Other items, net 16,190
1,964
Available Cash before Reserves 91,807
95,012



		Three Months Ended March 31,
		2020			2019
		(in thousands)
I.	Applicable to all Non-GAAP Measures
	Differences in timing of cash receipts for certain contractual arrangements ⁽¹⁾	$	4,490		$	(2,287	)
	Adjustment regarding direct financing leases ⁽²⁾	2,238			2,028
	Certain non-cash items:
	Unrealized (gains) losses on derivative transactions excluding fair value hedges, net of changes in inventory value⁽³⁾	(31,002		)	3,865
	Loss on debt extinguishment ⁽⁴⁾	23,480			—
	Adjustment regarding equity investees ⁽⁵⁾	6,406			4,828
	Other	(2,259		)	2,161
	Sub-total Select Items, net ⁽⁶⁾	3,353			10,595
II.	Applicable only to Available Cash before Reserves
	Certain transaction costs ⁽⁷⁾	—			117
	Equity compensation adjustments	—			(137		)
	Other	1,453			1,441
	Total Select Items, net⁽⁸⁾	$	4,806		$	12,016


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


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

(1) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.

(2) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.

(3) The 2020 Quarter includes a $32.5 million unrealized gain from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and the 2019 Quarter includes a $3.0 million unrealized loss from the valuation of the embedded derivative.

(4) Includes our transaction costs associated with the tender of $527.9 million and redemption of $222.1 million of our 2022 Notes in the first quarter of 2020, along with the write-off of our unamortized issuance costs and discount associated with these notes.

~~Non- GAAP~~(5) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.

(6) Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.

(7) Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in advance of acquisition.

(8) Represents Select Items applicable to Available Cash before Reserves.

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~~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 1112 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. Our non-GAAP financial measures should not be considered as an alternative to GAAP

measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

Segment Margin

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees and certain litigation expenses that are not deducted to determine our Pro Forma Adjusted EBITDA under our revolving credit facility. Our Segment Margin definition also includes the non-income portion of payments received under direct financing leases and eliminates non-cash revenues, expenses, gains, losses and charges (such as depreciation and amortization, unrealized gain or loss on derivative transactions not designated as hedges for accounting purposes,after eliminating gain or loss on sale of ~~non-surplus~~ assets, ~~and equity based compensation expense~~plus or minus applicable Select Items. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is ~~not settled in cash).~~important to the evaluation of our core operating results.

A reconciliation of total Segment Margin to net income is included in our segment disclosure in Note 912 to our Unaudited Condensed Consolidated Financial Statements, as well as previously in this Item 2.

Available Cash before Reserves

Purposes, Uses and Definition

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

Disclosure Format Relating to Maintenance Capital

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

Maintenance Capital Requirements

Maintenance Capital Expenditures

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

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

As we exist today, a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them.

We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

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

Maintenance Capital Utilized

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

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

Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Commercial Commitments

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

Report.

Off-Balance Sheet Arrangements

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

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, estimated or projected future financial performance, our expectations regarding the potential impact of the COVID-19 pandemic, 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, soda ash, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources,

international events, pandemics (including COVID-19), the ~~supply~~actions of ~~our assumptions about, changes in forecast data for,~~OPEC and ~~price trends related to crude~~other oil ~~liquid petroleum, natural gas, NaHS, caustic soda and CO~~2~~, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events,~~exporting nations, conservation and technological advances;

our ability to successfully execute our business and financial strategies;

the realized benefits of the preferred equity investment in Alkali Holdings by GSO or our ability to comply with the GOP agreements and maintain control over and ownership of the Alkali Business;

throughput levels and rates;

changes in, or challenges to, our tariff rates;

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

service interruptions in our pipeline transportation systems, ~~and~~ processing ~~operations;~~operations, or mining facilities;

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

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

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

the effects of production declines ~~and~~ resulting from a suspension of drilling in the Gulf of Mexico or otherwise;

the effects of future laws and ~~government regulation;~~regulations;

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

expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;

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

loss of key personnel;

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

an increase in the competition that our operations encounter;

cost and availability of insurance;

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

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

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

the impact of natural disasters, pandemics (including COVID-19), epidemics, accidents or ~~terrorism;~~terrorism, and actions taken by governmental authorities and other third parties in response thereto, on our business financial condition and results of operations;

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.~~price; and

a cyberattack involving our information systems and related infrastructure, or that of our business associates.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report ~~on Form 10-K for the year ended~~ ~~December 31, 2016~~. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual ~~Report on Form 10-K for the year ended~~ ~~December 31, 2016~~.Report. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 1154 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~~SEC'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~~first quarter of ~~2017~~2020 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2019. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

~~There~~Except as described below, there has been no material change in our risk factors as previously disclosed in our Annual ~~Report on Form 10-K for~~Report.

As part of the ~~fiscal year ended December 31, 2016, except as supplemented by our quarterly Reports on~~filing of this Form 10-Q, we intend to revise, clarify and ~~Current Reports on Form 8-K~~supplement our risk factors, including those contained in the Annual Report. The risk factor below should be considered together with the other risk factors described in the Annual Report and ~~Form 8-K/A.~~filings with the SEC under the Securities Exchange Act of 1934, as amended, after the Annual Report.

For additional information about our risk factors, see Item 1A of our Annual Report, ~~on Form 10-K for the year ended December 31, 2016,~~ as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

In December 2019, a novel strain of coronavirus (SARS-Cov-2), which causes COVID-19, was reported to have surfaced in China. The spread of this virus has caused business disruption, including disruption to the oil and natural gas and industrial industries. In March 2020, the World Health Organization declared the outbreak of COVID-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, petroleum products and industrial products, and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas, petroleum products and industrial products (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. These potential impacts, while uncertain, could adversely affect our operating results.

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

There were no sales of unregistered equity securities during the ~~2017 Quarter other than as previously included in our Current Report on Form 8-K filed on September 7, 2017.~~2020 Quarter.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Information regarding mine safety and other regulatory action at our ~~mine~~mines in Green River and Granger, Wyoming is ~~including~~included in Exhibit 95 to this Form 10-Q.

Item 5. Other Information

None.

Item 6. Exhibits.

(a) Exhibits



	~~2.1~~		Stock Purchase Agreement, dated August 2, 2017, by and among Genesis Energy, L.P., Tronox US Holdings, Inc., Tronox Alkali Corporation and, for the purposes set forth therein, Tronox Limited (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated August 7, 2017, File No. 001-12295).
	3.1		Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 of the Registration Statement on Form S-1, File No. 333-11545).
	3.2		Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to the 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 5.1 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4		First Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated September 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 7, 2017, File No. 001-12295).
	3.5		Second Amendment to Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P., dated December 31, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated January 4, 2018, File No. 001-12295).
	3.6		Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).



	~~3.6~~3.7	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K dated January 7, 2009, File No. 001-12295).
	~~3.7~~3.8	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 5.2 to the Company's Current Report on Form 8-K dated January 3, 2011, File No. 001-12295).
	3.9	Certificate of Incorporation of Genesis Energy Finance Corporation, dated as of November 26, 2006 (incorporated by reference to Exhibit 3.7 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	3.10	Bylaws of Genesis Energy Finance Corporation (incorporated by reference to Exhibit 3.8 to Registration Statement on Form S-4 filed on September 26, 2011, File No. 333-177012).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-12295).
	4.2	~~Eighth~~Fourteenth Supplemental Indenture for 7.750% Senior Notes Due 2028, dated as of ~~August 14, 2017,~~January 16, 2020, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the ~~subsidiary guarantors~~Guarantors named therein and U.S. Bank National Association, as trustee to the Indenture dated as of May 21, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association,Associations, as trustee (incorporated by reference ~~from~~to Exhibit 4.2 to the Company’s Current ~~Report~~report on Form 8-K ~~filed on August 14, 2017,~~dated January 16, 2020, File No. 001-12295).
	~~4.3~~	Registration Rights Agreement, dated September 1, 2017, by and among Genesis Energy, L.P., GSO Rodeo Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295).
*	10.1	Class A Convertible Preferred Unit Purchase Agreement, dated August 2, 2017, by and between Genesis Energy, L.P., and the purchasers named on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 7, 2017, File No. 001-12295).
	~~10.2~~	~~Sixth~~Tenth Amendment to ~~the~~ Fourth Amended and Restated Credit Agreement, dated ~~July 28, 2017,~~as of March 25, 2020, among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party ~~thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated August 7, 2017, File No. 001-12295).~~thereto.
*	~~10.3~~22.1	~~Board Observer Agreement, dated September 1, 2017, by~~List of Issuers and among Genesis Energy, L.P., GSO Rodeo Holdings LP and Rodeo Finance Aggregator LLC (incorporated by reference from Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295).Guarantor Subsidiaries.
*	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.
*	95	Mine Safety ~~Disclosures~~Disclosures.
*	101.INS	XBRL Instance ~~Document~~Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
*	101.SCH	XBRL Schema ~~Document~~Document.
*	101.CAL	XBRL Calculation Linkbase ~~Document~~Document.
*	101.LAB	XBRL Label Linkbase ~~Document~~Document.
*	101.PRE	XBRL Presentation Linkbase ~~Document~~Document.
*	101.DEF	XBRL Definition Linkbase ~~Document~~Document.
	104	Cover Page Interactive Data File (formatted as Inline XBRL).



*	Filed herewith

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, 2017~~May 6, 2020	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer
			(Duly Authorized Officer)

6154



Accounts receivable	138,291
Inventories	31,944
Other current assets	13,947
Fixed assets	617,878
Mineral leaseholds	623,137
Accounts payable	(51,534		)
Other current liabilities	(29,870		)
Other long-term liabilities	(18,793		)
Total Purchase Price	$	1,325,000



ARO liability balance, December 31, 2016	$	213,726
Accretion expense	8,257
Change in estimate	7,875
Acquisitions	2,444
Divestitures	(7,649		)
Settlements	(21,252		)
Other	240
ARO liability balance, September 30, 2017	$	203,641



Remainder of	2017	$	2,741
	2018	$	9,686
	2019	$	8,782
	2020	$	9,378
	2021	$	10,014



Remainder of	2017	$	5,919
	2018	$	21,506
	2019	$	17,171
	2020	$	16,237
	2021	$	10,627



	September 30,
	2017
Receivables:
ANSAC	$	59,406
Payables:
ANSAC	$	1,317



	Three Months Ended September 30,	Nine Months Ended September 30,
	2017	2017
Beginning Balance	—	—
Initial valuation of Preferred Distribution Rate Reset Election	(34,450)	(34,450)
Net Loss for the period included in earnings	(2,276)	(2,276)
Ending Balance	(36,726)	(36,726)



	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	$	—	$	8,960		$	728		$	—		$	9,694
Other current assets	75		—		569,457			11,836			(238		)	581,130
Total current assets	81		—		578,417			12,564			(238		)	590,824
Fixed assets, at cost	—		—		5,444,707			77,585			—			5,522,292
Less: Accumulated depreciation	—		—		(655,808		)	(26,092		)	—			(681,900		)
Net fixed assets	—		—		4,788,899			51,493			—			4,840,392
Mineral Leaseholds	—		—		622,756			—			—			622,756
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	15,229		—		382,916			128,306			(151,026		)	375,425
Advances to affiliates	3,889,517		—		—			82,479			(3,971,996		)	—
Equity investees	—		—		383,191			—			—			383,191
Investments in subsidiaries	2,666,281		—		81,135			—			(2,747,416		)	—
Total assets	$	6,571,108	$	—	$	7,162,360		$	274,842		$	(6,870,676	)	$	7,137,634
LIABILITIES AND CAPITAL
Current liabilities	$	34,731	$	—	$	321,339		$	8,092		$	(151	)	$	364,011
Senior secured credit facility	1,372,500		—		—			—			—			1,372,500
Senior unsecured notes	2,358,049		—		—			—			—			2,358,049
Deferred tax liabilities	—		—		26,399			—			—			26,399
Advances from affiliates	—		—		3,971,992			—			(3,971,992		)	—
Other liabilities	36,727		—		183,552			187,057			(150,874		)	256,462
Total liabilities	3,802,007		—		4,503,282			195,149			(4,123,017		)	4,377,421
Mezzanine Capital:
Series A Convertible Preferred Units	691,708		—		—			—			—			691,708
Partners’ capital, common units	2,077,393		—		2,659,078			88,581			(2,747,659		)	2,077,393
Noncontrolling interests	—		—		—			(8,888		)	—			(8,888		)
Total liabilities, mezzanine capital and partners’ capital	$	6,571,108	$	—	$	7,162,360		$	274,842		$	(6,870,676	)	$	7,137,634