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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 SeptemberJune 30, 20172021
OR
¨☐ 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)


Delaware76-0513049
(State or other jurisdiction of

incorporation or organization)
(I.R.S. Employer

Identification No.)
919 Milam, Suite 2100,
Houston, TX
77002
Houston,TX77002
(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 ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common unitsGELNYSE
 
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  ¨







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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 filerxAccelerated filer  ¨
Non-accelerated filer ¨Smaller reporting company  ☐
Large accelerated filer  x
Accelerated filer  ¨
Non-accelerated filer  ¨ (Do not check if a smaller reporting company)
Smaller reporting company  ¨
Emerging growth company  ¨
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
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.August 4, 2021.



Table of Contents
GENESIS ENERGY, L.P.
TABLE OF CONTENTS
 

Page
PART I. FINANCIAL INFORMATION
Item 1.
3
3
4
5
56
67
78
1. Organization and Basis of Presentation and Consolidation
78
2. Recent Accounting Developments
89
3. Acquisition and DivestitureRevenue Recognition
89
4. InventoriesLease Accounting
1011
5. Fixed AssetsInventories
1112
6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations
13
7. Equity Investees
1214
7.8. Intangible Assets
1415
8.9. Debt
1516
9.10. Partners' Capital, Mezzanine EquityCapital and Distributions
1518
10.11. Net IncomeLoss Per Common Unit
21
11.12. Business Segment Information
1922
12.13. Transactions with Related Parties
2125
13.14. Supplemental Cash Flow Information
2226
14.15. Derivatives
2326
15.16. Fair-Value Measurements
2629
16.17. Commitments and Contingencies
2730
17. Condensed Consolidating Financial Information
29
Item 2.
3832
Item 3.
5854
Item 4.
5854
PART II. OTHER INFORMATION
Item 1.
5955
Item 1A.
5955
Item 2.
5955
Item 3.
5955
Item 4.
5955
Item 5.
5955
Item 6.
5956
6157

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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except units)
September 30, 2017 December 31, 2016June 30, 2021December 31, 2020
ASSETS   ASSETS
CURRENT ASSETS:   CURRENT ASSETS:
Cash and cash equivalents$9,694
 $7,029
Cash and cash equivalents$24,205 $21,282 
Restricted cashRestricted cash22,083 5,736 
Accounts receivable - trade, net437,039
 224,682
Accounts receivable - trade, net433,310 392,465 
Inventories98,558
 98,587
Inventories78,327 99,877 
Other45,533
 29,271
Other61,796 60,809 
Total current assets590,824
 359,569
Total current assets619,721 580,169 
FIXED ASSETS, at cost5,522,292
 4,763,396
FIXED ASSETS, at cost5,312,157 5,173,475 
Less: Accumulated depreciation(681,900) (548,532)Less: Accumulated depreciation(1,437,510)(1,322,141)
Net fixed assets4,840,392
 4,214,864
Net fixed assets3,874,647 3,851,334 
MINERAL LEASEHOLDS, net622,756
 —
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income127,248
 132,859
MINERAL LEASEHOLDS, net of accumulated depletionMINERAL LEASEHOLDS, net of accumulated depletion550,959 552,575 
EQUITY INVESTEES383,191
 408,756
EQUITY INVESTEES302,940 319,068 
INTANGIBLE ASSETS, net of amortization187,441
 204,887
INTANGIBLE ASSETS, net of amortization127,947 128,742 
GOODWILL325,046
 325,046
GOODWILL301,959 301,959 
RIGHT OF USE ASSETS, netRIGHT OF USE ASSETS, net144,013 153,925 
OTHER ASSETS, net of amortization60,736
 56,611
OTHER ASSETS, net of amortization41,301 45,847 
TOTAL ASSETS$7,137,634
 $5,702,592
TOTAL ASSETS$5,963,487 $5,933,619 
LIABILITIES AND CAPITAL   LIABILITIES AND CAPITAL
CURRENT LIABILITIES:   CURRENT LIABILITIES:
Accounts payable - trade$203,717
 $119,841
Accounts payable - trade$301,676 $198,433 
Accrued liabilities160,294
 140,962
Accrued liabilities218,327 184,978 
Total current liabilities364,011
 260,803
Total current liabilities520,003 383,411 
SENIOR SECURED CREDIT FACILITY1,372,500
 1,278,200
SENIOR UNSECURED NOTES, net of debt issuance costs2,358,049
 1,813,169
SENIOR SECURED CREDIT FACILITY, netSENIOR SECURED CREDIT FACILITY, net415,653 643,700 
SENIOR UNSECURED NOTES, netSENIOR UNSECURED NOTES, net2,927,489 2,750,016 
DEFERRED TAX LIABILITIES26,399
 25,889
DEFERRED TAX LIABILITIES13,719 13,317 
OTHER LONG-TERM LIABILITIES256,462
 204,481
OTHER LONG-TERM LIABILITIES422,299 393,018 
Total liabilities4,377,421
 3,582,542
Total liabilities4,299,163 4,183,462 
   
MEZZANINE CAPITAL:   MEZZANINE CAPITAL:
Series A Convertible Preferred Units, 22,249,494 issued and outstanding at September 30, 2017691,708
 —
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at June 30, 2021 and December 31, 2020Class A Convertible Preferred Units, 25,336,778 issued and outstanding at June 30, 2021 and December 31, 2020790,115 790,115 
Redeemable noncontrolling interests, 201,705 and 141,249 preferred units issued and outstanding at June 30, 2021 and December 31, 2020, respectivelyRedeemable noncontrolling interests, 201,705 and 141,249 preferred units issued and outstanding at June 30, 2021 and December 31, 2020, respectively204,647 141,194 
   
PARTNERS’ CAPITAL:   PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 and 117,979,218 units issued and outstanding at September 30, 2017 and December 31, 2016, respectively2,077,393
 2,130,331
Common unitholders, 122,579,218 units issued and outstanding at June 30, 2021 and December 31, 2020Common unitholders, 122,579,218 units issued and outstanding at June 30, 2021 and December 31, 2020679,278 829,326 
Accumulated other comprehensive lossAccumulated other comprehensive loss(9,122)(9,365)
Noncontrolling interests(8,888) (10,281)Noncontrolling interests(594)(1,113)
Total partners' capital2,068,505
 2,120,050
Total partners' capital669,562 818,848 
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL$7,137,634
 $5,702,592
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL$5,963,487 $5,933,619 
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)thousands)
 
Three Months Ended
September 30,		 Nine Months Ended
September 30,		 Three Months Ended
June 30,		Six Months Ended
June 30,
2017 2016 2017 2016 2021202020212020
REVENUES:       REVENUES:
Offshore pipeline transportation services80,671
 89,717
 243,437
 244,837
Offshore pipeline transportationOffshore pipeline transportation$73,221 $64,964 $137,605 $143,393 
Sodium minerals and sulfur services109,765
 45,725
 197,879
 129,585
Sodium minerals and sulfur services237,087 192,624 464,374 436,014 
Marine transportation48,534
 55,285
 152,038
 159,930
Marine transportation47,626 56,720 87,957 119,066 
Onshore facilities and transportation247,144
 269,323
 714,974
 750,088
Onshore facilities and transportation145,921 74,159 335,138 229,917 
Total revenues486,114
 460,050
 1,308,328
 1,284,440
Total revenues503,855 388,467 1,025,074 928,390 
COSTS AND EXPENSES:       COSTS AND EXPENSES:
Onshore facilities and transportation product costs202,047
 230,229
 582,535
 620,620
Onshore facilities and transportation product costs124,684 43,447 285,435 155,399 
Onshore facilities and transportation operating costs23,982
 22,476
 80,160
 71,974
Onshore facilities and transportation operating costs15,833 18,238 32,095 36,486 
Marine transportation operating costs35,789
 38,490
 111,980
 105,942
Marine transportation operating costs39,118 38,561 72,204 81,498 
Sodium minerals and sulfur services operating costs79,365
 25,077
 133,335
 67,641
Sodium minerals and sulfur services operating costs196,971 167,010 381,402 372,243 
Offshore pipeline transportation operating costs18,690
 23,122
 54,682
 63,732
Offshore pipeline transportation operating costs21,264 16,403 41,980 35,064 
General and administrative19,409
 11,212
 38,723
 34,716
General and administrative12,907 25,413 24,573 34,786 
Depreciation, depletion and amortization63,732
 54,265
 176,453
 156,800
Depreciation, depletion and amortization67,541 80,120 133,827 154,477 
Gain on sale of assets—
 —
 (26,684) —
Impairment expenseImpairment expense0 277,495 0 277,495 
Total costs and expenses443,014
 404,871
 1,151,184
 1,121,425
Total costs and expenses478,318 666,687 971,516 1,147,448 
OPERATING INCOME43,100
 55,179
 157,144
 163,015
OPERATING INCOME (LOSS)OPERATING INCOME (LOSS)25,537 (278,220)53,558 (219,058)
Equity in earnings of equity investees13,044
 12,488
 34,805
 35,362
Equity in earnings of equity investees14,222 12,618 34,882 26,777 
Interest expense(47,388) (34,735) (122,117) (104,657)Interest expense(59,169)(51,618)(116,998)(106,583)
Other expense(2,276) —
 (2,276) —
Income before income taxes6,480
 32,932
 67,556
 93,720
Other income (expense)Other income (expense)(15,845)(4,550)(35,910)5,708 
Loss from operations before income taxesLoss from operations before income taxes(35,255)(321,770)(64,468)(293,156)
Income tax expense(320) (949) (878) (2,959)Income tax expense(525)(795)(747)(430)
NET INCOME6,160
 31,983
 66,678
 90,761
Net loss attributable to noncontrolling interests152
 118
 457
 370
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
 $91,131
NET INCOME PER COMMON UNIT (Note 10):       
NET LOSSNET LOSS(35,780)(322,565)(65,215)(293,586)
Net loss (income) attributable to noncontrolling interestsNet loss (income) attributable to noncontrolling interests(136)10 (134)26 
Net income attributable to redeemable noncontrolling interestsNet income attributable to redeemable noncontrolling interests(5,766)(4,159)(10,557)(8,245)
NET LOSS ATTRIBUTABLE TO GENESIS ENERGY, L.P.NET LOSS ATTRIBUTABLE TO GENESIS ENERGY, L.P.$(41,682)$(326,714)$(75,906)$(301,805)
Less: Accumulated distributions attributable to Class A Convertible Preferred UnitsLess: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684)(18,684)(37,368)(37,368)
NET LOSS AVAILABLE TO COMMON UNITHOLDERSNET LOSS AVAILABLE TO COMMON UNITHOLDERS$(60,366)$(345,398)$(113,274)$(339,173)
NET LOSS PER COMMON UNIT (Note 11):NET LOSS PER COMMON UNIT (Note 11):
Basic and Diluted$0.01
 $0.28
 $0.51
 $0.81
Basic and Diluted$(0.49)$(2.82)$(0.92)$(2.77)
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:       WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted122,579
 115,718
 121,198
 111,906
Basic and Diluted122,579 122,579 122,579 122,579 
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.



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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITALCOMPREHENSIVE INCOME (LOSS)
(In thousands)
 
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Total
Partners’ capital, January 1, 2017117,979
 $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, net4,600
 140,513
 —
 140,513
Partners' capital, September 30, 2017122,579
 $2,077,393
 $(8,888) $2,068,505
 
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Total
Partners’ capital, January 1, 2016109,979
 $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, net8,000
 298,051
 —
 298,051
Partners' capital, September 30, 2016117,979
 $2,190,829
 $(8,720) $2,182,109
Three Months Ended
June 30,		Six Months Ended
June 30,
2021202020212020
Net loss$(35,780)$(322,565)$(65,215)$(293,586)
Other comprehensive income:
Amortization of prior service cost121 243 243 243 
Total Comprehensive loss(35,659)(322,322)(64,972)(293,343)
Comprehensive loss (income) attributable to noncontrolling interests(136)10 (134)26 
Comprehensive income attributable to redeemable noncontrolling interests(5,766)(4,159)(10,557)(8,245)
Comprehensive loss attributable to Genesis Energy, L.P.$(41,561)$(326,471)$(75,663)$(301,562)
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.



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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
Number of Common UnitsPartners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive LossTotal
Partners' capital, March 31, 2021122,579 $758,031 $(879)$(9,243)$747,909 
Net income (loss)— (41,682)136 — (41,546)
Cash distributions to partners— (18,387)— — (18,387)
Cash contributions from noncontrolling interests— — 149 — 149 
Other comprehensive income— — — 121 121 
Distributions to Class A Convertible Preferred unitholders— (18,684)— — (18,684)
Partners' capital, June 30, 2021122,579 $679,278 $(594)$(9,122)$669,562 
Number of Common UnitsPartners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive LossTotal
Partners' capital, March 31, 2020122,579 $1,382,126 $(2,357)$(8,431)$1,371,338 
Net loss— (326,714)(10)— (326,724)
Cash distributions to partners— (18,386)— — (18,386)
Cash contributions from noncontrolling interests— — 467 — 467 
Other comprehensive income— — — 243 243 
Distributions to Class A Convertible Preferred unitholders— (18,684)— — (18,684)
Partners' capital, June 30, 2020122,579 $1,018,342 $(1,900)$(8,188)$1,008,254 
 Number of
Common Units		Partners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive LossTotal
Partners’ capital, December 31, 2020122,579 $829,326 $(1,113)$(9,365)$818,848 
Net income (loss)— (75,906)134 — (75,772)
Cash distributions to partners— (36,774)— — (36,774)
Cash contributions from noncontrolling interests— — 385 — 385 
Other comprehensive income— — — 243 243 
Distributions to Class A Convertible Preferred unitholders— (37,368)— — (37,368)
Partners' capital, June 30, 2021122,579 $679,278 $(594)$(9,122)$669,562 
Number of
Common Units		Partners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive LossTotal
Partners’ capital, December 31, 2019122,579 $1,443,320 $(3,718)$(8,431)$1,431,171 
Net loss— (301,805)(26)— (301,831)
Cash distributions to partners— (85,805)— — (85,805)
Cash contributions from noncontrolling interests— — 1,844 — 1,844 
Other comprehensive income— — — 243 243 
Distributions to Class A Convertible Preferred unitholders— (37,368)— — (37,368)
Partners' capital, June 30, 2020122,579 $1,018,342 $(1,900)$(8,188)$1,008,254 
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.
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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 
Nine Months Ended
September 30,		 Six Months Ended
June 30,
2017 2016 20212020
CASH FLOWS FROM OPERATING ACTIVITIES:   CASH FLOWS FROM OPERATING ACTIVITIES:
Net income$66,678
 $90,761
Adjustments to reconcile net income to net cash provided by operating activities -   
Net lossNet loss$(65,215)$(293,586)
Adjustments to reconcile net loss to net cash provided by operating activities -Adjustments to reconcile net loss to net cash provided by operating activities -
Depreciation, depletion and amortization176,453
 156,800
Depreciation, depletion and amortization133,827 154,477 
Provision for leased items no longer in use12,589
 —
Gain on sale of assets(26,684) —
Amortization of debt issuance costs and discount8,154
 7,563
Amortization of unearned income and initial direct costs on direct financing leases(10,374) (10,856)
Payments received under direct financing leases15,501
 15,501
Impairment expenseImpairment expense0 277,495 
Amortization and write-off of debt issuance costs, premium and discountAmortization and write-off of debt issuance costs, premium and discount6,965 14,971 
Amortization of non-cash costs on previously owned direct financing leasesAmortization of non-cash costs on previously owned direct financing leases0 (5,802)
Payments received under previously owned direct financing leases (Note 4)
Payments received under previously owned direct financing leases (Note 4)
35,000 10,334 
Equity in earnings of investments in equity investees(34,805) (35,362)Equity in earnings of investments in equity investees(34,882)(26,777)
Cash distributions of earnings of equity investees45,854
 49,528
Cash distributions of earnings of equity investees34,325 25,923 
Non-cash effect of equity-based compensation plans(5,524) 6,102
Non-cash effect of long-term incentive compensation plansNon-cash effect of long-term incentive compensation plans2,884 (3,647)
Deferred and other tax liabilities508
 2,058
Deferred and other tax liabilities402 130 
Unrealized loss on derivative transactions3,040
 742
Unrealized losses (gains) on derivative transactionsUnrealized losses (gains) on derivative transactions32,377 (9,811)
Cancellation of debt incomeCancellation of debt income0 (19,725)
Other, net(7,338) 8,967
Other, net11,229 8,662 
Net changes in components of operating assets and liabilities (Note 13)
(26,262) (63,407)
Net changes in components of operating assets and liabilities (Note 14)
Net changes in components of operating assets and liabilities (Note 14)
31,272 19,518 
Net cash provided by operating activities217,790
 228,397
Net cash provided by operating activities188,184 152,162 
CASH FLOWS FROM INVESTING ACTIVITIES:   CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets(182,653) (363,218)Payments to acquire fixed and intangible assets(111,412)(69,438)
Cash distributions received from equity investees - return of investment14,517
 16,652
Cash distributions received from equity investees - return of investment17,015 13,036 
Acquisitions(1,325,759) (25,394)
Contributions in aid of construction costs124
 12,208
Proceeds from asset sales39,204
 3,303
Proceeds from asset sales32 304 
Other, net—
 185
Net cash used in investing activities(1,454,567) (356,264)Net cash used in investing activities(94,365)(56,098)
CASH FLOWS FROM FINANCING ACTIVITIES:   CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility1,247,700
 883,600
Borrowings on senior secured credit facility366,600 684,500 
Repayments on senior secured credit facility(1,153,400) (831,600)Repayments on senior secured credit facility(592,100)(590,800)
Proceeds from issuance of senior unsecured notes550,000
 —
Proceeds from issuance of Series A convertible preferred units, net729,958
 —
Proceeds from issuance of senior unsecured notes (Note 9)
Proceeds from issuance of senior unsecured notes (Note 9)
259,375 750,000 
Net proceeds from issuance of preferred units (Note 10)
Net proceeds from issuance of preferred units (Note 10)
53,018 0 
Repayment of senior unsecured notes (Note 9)
Repayment of senior unsecured notes (Note 9)
(80,859)(820,713)
Debt issuance costs(17,808) (1,578)Debt issuance costs(11,365)(13,297)
Issuance of common units for cash, net140,513
 298,051
Contributions from noncontrolling interests1,850
 —
Contributions from noncontrolling interests385 1,844 
Distributions to common unitholders(260,586) (227,454)Distributions to common unitholders(36,774)(85,805)
Distributions to preferred unitholdersDistributions to preferred unitholders(37,368)(37,368)
Other, net1,215
 (600)Other, net4,539 4,671 
Net cash provided by financing activities1,239,442
 120,419
Net increase (decrease) in cash and cash equivalents2,665
 (7,448)
Cash and cash equivalents at beginning of period7,029
 10,895
Cash and cash equivalents at end of period$9,694
 $3,447
Net cash used in financing activitiesNet cash used in financing activities(74,549)(106,968)
Net increase (decrease) in cash, restricted cash, and cash equivalentsNet increase (decrease) in cash, restricted cash, and cash equivalents19,270 (10,904)
Cash, restricted cash and cash equivalents at beginning of periodCash, restricted cash and cash equivalents at beginning of period27,018 56,405 
Cash, restricted cash and cash equivalents at end of periodCash, restricted cash and cash equivalents at end of period$46,288 $45,501 
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS




1. Organization and Basis of Presentation and Consolidation
Organization
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry as well as the production of natural soda ash. Our operations are located primarily 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, soda ash businesses,our trona and trona-based exploring, mining, processing, producing, marketing, and selling business based in Wyoming (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 fourthe 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.segments:
These four divisions that constitute our reportable segments consist of the following:
•Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;
•Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as the processing of high sulfur (or “sour”"sour") gas streams for refineries to remove the sulfur, and the selling of 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 CO2;
•Onshore facilities and transportation, which include the terminalling, blending, storing, marketing and transporting of crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products); and
•Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; andAmerica.
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 Unaudited 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, 2016.2020 (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 and Market 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 CISA and we have continued to operate our assets during this pandemic.
We have a designated internal management team to provide resources, updates, and support to our entire workforce during this pandemic, while maintaining a focus to ensure safety and well-being of our employees, the families of our employees, and the communities in which our businesses operate. We will continue to operate in the best interests of our employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or local authorities as we continue to actively monitor the situation.
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Beginning in March 2020, Covid-19 caused commodity prices to decline due to, among other things, reduced industrial activity and travel demand. Additionally, actions taken by OPEC and other oil exporting nations
in that timeframe caused additional significant declines and volatility in the price of oil and gas. We continue to monitor the market environment and will evaluate whether any triggering events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our results of operations.
2. Recent Accounting Developments
Recently IssuedAdopted
    During the first quarter of 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 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 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. Revenue Recognition
Revenue from Contracts with Customers
The following tables reflect the disaggregation of our revenues by major category for the three months ended June 30, 2021 and 2020, respectively:
Three Months Ended
June 30, 2021
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$73,221 $0 $47,626 $18,176 $139,023 
Product Sales0 212,434 0 127,745 340,179 
Refinery Services0 24,653 0 0 24,653 
$73,221 $237,087 $47,626 $145,921 $503,855 
Three Months Ended
June 30, 2020
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$64,964 $0 $56,720 $21,845 $143,529 
Product Sales0 172,410 0 52,314 224,724 
Refinery Services0 20,214 0 0 20,214 
$64,964 $192,624 $56,720 $74,159 $388,467 
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following tables reflect the disaggregation of our revenues by major category for the six months ended June 30, 2021 and 2020, respectively:
Six Months Ended
June 30, 2021
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$137,605 $0 $87,957 $42,570 $268,132 
Product Sales0 417,212 0 292,568 709,780 
Refinery Services0 47,162 0 0 47,162 
$137,605 $464,374 $87,957 $335,138 $1,025,074 
Six Months Ended
June 30, 2020
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities & TransportationConsolidated
Fee-based revenues$143,393 $0 $119,066 $62,835 $325,294 
Product Sales0 387,776 0 167,082 554,858 
Refinery Services0 48,238 0 0 48,238 
$143,393 $436,014 $119,066 $229,917 $928,390 

    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 May 2014,general, the FASB issued revised guidance ontiming 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.

Contract Assets and Liabilities
    The table below depicts our contract asset and liability balances at December 31, 2020 and June 30, 2021:
Contract AssetsContract Liabilities
Current Assets- OtherOther AssetsAccrued LiabilitiesOther Long-Term Liabilities
Balance at December 31, 2020$36,500 $12,065 $2,988 $19,834 
Balance at June 30, 202130,813 0 2,669 18,576 


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 June 30, 2021. 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 customersvariable consideration that will supersede most currentis 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 guidance, including industry-specific guidance. The core principleover a long-term period with long-term fixed consideration (adjusted for indexing as required), we determined our allocations of the revenue model istransaction price that an entity will recognize revenuerelate to depict the transfer of promised goods or services to customers in an amount that reflects theunsatisfied performance obligations. For our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard providesover 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. Thoughlong term period. Therefore, we have not finalized our conclusions, we currently plan to applyallocated 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 marketremaining contract value to lowerfuture periods.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
    The guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The guidance is effective for reporting periods after December 15, 2016, with early adoption permitted. We have adopted this guidance as of January 1, 2017 with no material impact on our consolidated financial statements.
In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lesseesfollowing chart depicts how we expect to recognize arevenues for future periods related to these contracts:
Offshore Pipeline TransportationOnshore Facilities and Transportation
Remainder of 2021$31,048 $9,604 
202275,623 4,698 
202363,982 0 
202456,326 0 
202560,311 0 
Thereafter97,761 0 
Total$385,051 $14,302 



4. Lease Accounting
Lessee Arrangements
We lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this guidance.
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We do not expect the adoption of this guidance to have a material impact on our consolidated financial statements.
3. Acquisition and Divestiture
Acquisition
Alkali Business
On September 1, 2017, we acquired the Alkali Business 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 and a variety of chemicalstransportation equipment (including trucks, trailers, and other industrial products. To finance that transactionrailcars), terminals, land and the related costs, we used proceedsfacilities, 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 resultsmajority of our Alkali Business in our sodium minerals and sulfur services segment fromleases 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 allocationlife of the purchase price, as presented on our Consolidated Balance Sheet, is summarized as follows:
Accounts receivable138,291
Inventories31,944
Other current assets13,947
Fixed assets617,878
Mineral leaseholds623,137
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. Thesesole discretion. We considered these options when determining the lease terms used to derive our right of use assets will be depreciated under the straight line method and have an average useful lifeassociated lease liabilities. Leases with a term of approximately 15 years. Mineral leaseholds include the trona reserves at our Green River, Wyoming facility andless 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 StatementBalance Sheets. Lease expenses are recognized on a straight line basis over the lease term.
    Our Right of Operations.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 cease-use provision for railcars no longer in use. Our short-term and long-term lease liabilities are recorded within "Accrued liabilities" and "Other long-term liabilities," respectively, on our Unaudited Condensed Consolidated Balance Sheets.
Lessor Arrangements
4.    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
    During the three and six months ended June 30, 2021 and 2020, we acted as a lessor in revenue contracts associated with the M/T American Phoenix, which is included in our marine transportation segment. During the three and six months ended June 30, 2020, we acted as a lessor in our Free State pipeline system, which was included in our onshore facilities and transportation segment. Our lease revenues for these arrangements (inclusive of fixed and variable consideration) are reflected in the table below:
Three Months Ended
June 30,		Six Months Ended
 June 30,
2021202020212020
M/T American Phoenix$3,819 $6,734 $7,239 $13,377 
Free State Pipeline (1)
0 1,499 0 3,422 
(1) We sold the Free State pipeline to a subsidiary of Denbury, Inc. ("Denbury") on October 30, 2020.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Direct Finance Lease
We formerly held a direct finance lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the finance lease, we were paid a quarterly payment, which commenced in August 3, 2008. During the third quarter of 2020, our customer, Denbury, defaulted under the agreement. On October 30, 2020 we executed an agreement with our customer to accelerate the remaining principal payments on the previously owned NEJD direct financing lease, payable in 4 equal installments. During the six months ended June 30, 2021, we collected $35.0 million and we have an outstanding receivable (included within "Accounts receivable- trade, net" on the Unaudited Condensed Consolidated Balance Sheet) of $35.0 million as of June 30, 2021 from Denbury for the remaining payments due in 2021 per the agreement. Additionally as part of this transaction, we transferred the ownership of all of our CO2 assets to Denbury, including the Free State pipeline system as noted previously.

5. Inventories
The major components of inventories were as follows:
June 30,
2021		December 31, 2020
Petroleum products$1,308 $5,840 
Crude oil23,597 37,661 
Caustic soda4,459 5,167 
NaHS10,701 9,101 
Raw materials - Alkali operations7,230 7,120 
Work-in-process - Alkali operations4,455 9,355 
Finished goods, net - Alkali operations13,279 13,002 
Materials and supplies, net - Alkali operations13,298 12,631 
Total$78,327 $99,877 
 September 30,
2017		 December 31,
2016
Petroleum products$2,618
 $11,550
Crude oil46,035
 73,133
Caustic soda5,381
 4,593
NaHS11,176
 9,304
Raw materials - Alkali Operations4,560
 —
Work-in-process - Alkali Operations4,751
 —
Finished goods, net - Alkali Operations14,197
 —
Materials and supplies, net - Alkali Operations9,840
 —
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 below cost by $0.5 million and $5.0 million as of SeptemberJune 30, 20172021 and December 31, 2016.2020, respectively, therefore we reduced the value of our inventory in our Unaudited Consolidated Financial Statements by these amounts.

Materials and supplies include chemicals, maintenance supplies, and spare parts which will be consumed in the mining of trona ore and production of soda ash processes.
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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:
 
June 30, 2021December 31, 2020
Crude oil pipelines and natural gas pipelines and related assets$2,821,996 $2,811,030 
Alkali facilities, machinery, and equipment641,619 622,598 
Onshore facilities, machinery, and equipment268,689 267,810 
Transportation equipment21,348 19,470 
Marine vessels1,011,171 998,553 
Land, buildings and improvements221,146 219,382 
Office equipment, furniture and fixtures22,185 22,001 
Construction in progress260,742 170,740 
Other43,261 41,891 
Fixed assets, at cost5,312,157 5,173,475 
Less: Accumulated depreciation(1,437,510)(1,322,141)
Net fixed assets$3,874,647 $3,851,334 
 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 equipment617,878
 —
Onshore facilities, machinery, and equipment757,874
 427,658
Transportation equipment17,995
 17,543
Marine vessels898,582
 863,199
Land, buildings and improvements103,774
 55,712
Office equipment, furniture and fixtures9,681
 9,654
Construction in progress58,069
 440,225
Other53,821
 48,203
Fixed assets, at cost5,522,292
 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:
June 30,
2021		December 31, 2020
Mineral leaseholds$566,019 $566,019 
Less: Accumulated depletion(15,060)(13,444)
Mineral leaseholds, net of accumulated depletion$550,959 $552,575 
 September 30,
2017
Mineral leaseholds623,137
Less: Accumulated depletion(381)
Mineral leaseholds, net$622,756


Our depreciation and depletion expense for the periods presented was as follows:
Three Months Ended
June 30,		Six Months Ended
June 30,
2021202020212020
Depreciation expense$64,148 $75,089 $126,850 $144,331 
Depletion expense704 841 1,616 1,804 
 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 Expense381
 —
 381
 —



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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


2020, due to the challenging economic environment from the decline in commodity prices (including the collapse in the differential of Western Canadian Select to the Gulf Coast) and Covid-19, crude-by-rail transportation became uneconomic for producers and the demand and outlook for our rail logistics assets declined. As a result, we recognized impairment expense of $277.5 million associated with the rail logistics assets in our onshore facilities and transportation segment, including $272.7 million of net fixed assets and $4.8 million of right of use assets, net on the Unaudited Condensed Consolidated Balance Sheet. The fair value was calculated utilizing the income approach and assumptions were primarily based on level 3 inputs of the fair value hierarchy.
Asset Retirement Obligations
We record AROsasset 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, 2016:2020:
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
ARO liability balance, December 31, 2016$213,726
Accretion expense8,257
Change in estimate7,875
Acquisitions2,444
Divestitures(7,649)
Settlements(21,252)
Other240
ARO liability balance, September 30, 2017$203,641
ARO liability balance, December 31, 2020$176,852 
Accretion expense5,177 
Changes in estimate97 
Settlements(2,824)
ARO liability balance, June 30, 2021$179,302 
Of the ARO balances disclosed above, $19.3$12.3 million and $22.4$14.7 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance SheetSheets as of SeptemberJune 30, 20172021 and December 31, 2016,2020, respectively. The remainder of the ARO liability as of SeptemberJune 30, 20172021 and December 31, 20162020 is included in "Other long-term liabilities" on our Unaudited Condensed Consolidated Balance Sheet.Sheets.
With respect to our AROs, the following table presents our forecastestimate of accretion expense for the periods indicated:
Remainder of2021$4,975 
2022$9,384 
2023$9,128 
2024$9,783 
2025$10,487 
Remainder of2017$2,741
 2018$9,686
 2019$8,782
 2020$9,378
 2021$10,014
Certain of our unconsolidated affiliates have AROs recorded at SeptemberJune 30, 20172021 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 SeptemberJune 30, 20172021 and December 31, 2016,2020, the unamortized excess cost amounts totaled $386.3$327.6 million and $398.1$335.4 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.investees:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
Genesis’ share of operating earnings$18,094 $16,490 $42,627 $34,522 
Amortization of excess purchase price(3,872)(3,872)(7,745)(7,745)
Net equity in earnings$14,222 $12,618 $34,882 $26,777 
Distributions received (1)
$21,914 $18,394 $51,430 $38,959 
(1) Includes distributions attributable to the period and received during or promptly following such period.
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 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):
June 30,
2021		December 31, 2020
BALANCE SHEET DATA:
Assets
Current assets$17,546 $30,465 
Fixed assets, net167,764 171,732 
Other assets5,447 4,673 
Total assets$190,757 $206,870 
Liabilities and equity
Current liabilities$13,649 $9,958 
Other liabilities229,836 237,595 
Equity (Deficit)(52,728)(40,683)
Total liabilities and equity$190,757 $206,870 
 September 30,
2017		 December 31,
2016
BALANCE SHEET DATA:   
Assets   
Current assets$18,638
 $17,111
Fixed assets, net221,123
 232,736
Other assets1,282
 861
Total assets$241,043
 $250,708
Liabilities and equity   
Current liabilities$20,683
 $20,727
Other liabilities231,469
 219,644
Equity(11,109) 10,337
Total liabilities and equity$241,043
 $250,708
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
INCOME STATEMENT DATA:
Revenues$33,757 $30,419 $76,170 $63,311 
Operating income$24,636 $21,922 $56,797 $45,528 
Net income$23,610 $20,636 $54,755 $42,219 


 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 facilityRevolving 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 2015March 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 2015March 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:
 
 June 30, 2021December 31, 2020
 Gross
Carrying
Amount		Accumulated
Amortization		Carrying
Value		Gross
Carrying
Amount		Accumulated
Amortization		Carrying
Value
Marine contract intangibles$800 $589 $211 $800 $571 $229 
Offshore pipeline contract intangibles158,101 49,233 108,868 158,101 45,073 113,028 
Other33,629 14,761 18,868 29,244 13,759 15,485 
Total$192,530 $64,583 $127,947 $188,145 $59,403 $128,742 
 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 agreements38,678
 35,947
 2,731
 38,678
 34,204
 4,474
Segment total133,332
 127,756
 5,576
 133,332
 123,960
 9,372
Onshore Facilities & Transportation:           
Customer relationships35,430
 34,731
 699
 35,430
 33,676
 1,754
Intangibles associated with lease13,260
 4,815
 8,445
 13,260
 4,459
 8,801
Segment total48,690
 39,546
 9,144
 48,690
 38,135
 10,555
Marine contract intangibles27,000
 10,350
 16,650
 27,000
 6,300
 20,700
Offshore pipeline contract intangibles158,101
 18,029
 140,072
 158,101
 11,788
 146,313
Other28,747
 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
June 30,		Six Months Ended
June 30,
2021202020212020
Amortization of intangible assets$2,580 $4,146 $5,180 $8,262 
15
 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
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
We estimate that our amortization expense for the next five years will be as follows:
Remainder of2021$5,673 
2022$11,244 
2023$10,976 
2024$10,661 
2025$10,494 
9. Debt
Remainder of2017$5,919
 2018$21,506
 2019$17,171
 2020$16,237
 2021$10,627
Our obligations under debt arrangements consisted of the following:

 June 30, 2021December 31, 2020
 PrincipalUnamortized Premium and Debt Issuance CostsNet ValuePrincipalUnamortized Debt Issuance CostsNet Value
Senior secured credit facility-Revolving Loan (1)
$118,200 $0 $118,200 $643,700 $0 $643,700 
Senior secured credit facility-Term Loan (2)
300,000 2,547 297,453 0 0 0 
6.000% senior unsecured notes due 20230 0 0 80,859 504 80,355 
5.625% senior unsecured notes due 2024341,135 2,534 338,601 341,135 2,963 338,172 
6.500% senior unsecured notes due 2025534,834 5,046 529,788 534,834 5,639 529,195 
6.250% senior unsecured notes due 2026359,799 3,799 356,000 359,799 4,189 355,610 
8.000% senior unsecured notes due 20271,000,000 7,401 992,599 750,000 13,022 736,978 
7.750% senior unsecured notes due 2028720,975 10,474 710,501 720,975 11,269 709,706 
Total long-term debt$3,374,943 $31,801 $3,343,142 $3,431,302 $37,586 $3,393,716 
(1)    Unamortized debt issuance costs associated with our senior secured credit facility Revolving Loan, as defined below (included in Other Long Term Assets on the Unaudited Condensed Consolidated Balance Sheets), were $5.5 million and $5.8 million as of June 30, 2021 and December 31, 2020, respectively.
(2)    Unamortized debt issuance costs associated with our senior secured credit facility Term Loan, as defined below (included in Senior Secured Credit Facility, net on the Unaudited Condensed Consolidated Balance Sheets), was $2.5 million as of June 30, 2021.
Senior Secured Credit Facility
On April 8, 2021, we entered into the Fifth Amended and Restated Credit Agreement (our "new credit agreement") to replace our Fourth Amended and Restated Credit Agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprised of a revolving loan facility with a borrowing capacity of $650 million (the "Revolving Loan") and a term loan facility of $300 million (the "Term Loan"). The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to 2 occasions and subject to certain conditions. At June 30, 2021, the key terms for rates under our Revolving Loan (which are dependent on our leverage ratio as defined in the new credit agreement) and Term Loan, are as follows:
•Revolving Loan: 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 in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity on such day 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 2.25% to 3.75% on Eurodollar borrowings and from 1.25% to 2.75% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At June 30, 2021, the applicable margins on our borrowings were 2.75% for alternate base rate borrowings and 3.75% for Eurodollar rate borrowings based on our leverage ratio.
•Term Loan: The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate and the Eurodollar rates for our Term Loan are calculated consistent with
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


our Revolving Loan discussed above, and the applicable margin is fixed at 3.75% on Eurodollar borrowings and 2.75% on alternate base rate borrowings for the Term Loan.
8. Debt
Our obligations under debt arrangements consisted•Letter of the following:
 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 2021350,000
 3,399
 346,601
 350,000
 4,163
 345,837
6.750% senior unsecured notes due August 2022750,000
 16,889
 733,111
 750,000
 19,296
 730,704
6.000% senior unsecured notes due May 2023400,000
 5,958
 394,042
 400,000
 6,758
 393,242
5.625% senior unsecured notes due June 2024350,000
 5,941
 344,059
 350,000
 6,614
 343,386
6.500% senior unsecured notes due October 2025550,000
 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 million and $10.7 million as of September 30, 2017 and December 31, 2016, respectively.
As of September 30, 2017, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.
Senior Secured Credit Facility
In July 2017, we amended our credit agreementfee rates range from 2.25% 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 dependent3.75% based on our leverage ratio (as defined inas computed under the credit agreement), are as follows:
•The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowingsfacility and from 0.50% to 2.00% on alternate base rate borrowings.
•Lettercan fluctuate quarterly. At June 30, 2021, our letter of credit fees range from 1.50% to 3.00%rate was 3.75%.
•We pay a commitment fee on the unused portion of the Revolving Loan. The commitment fee rates on the unused committed amount will range from 0.25%0.30% to 0.50% per annum depending on our leverage ratio. At June 30, 2021, our commitment fee rate on the unused committed amount was 0.50%.
•The accordion feature is $300.0 million, giving usWe have the ability to expandincrease the aggregate size of the facility to up to $2.0 billion for acquisitions or growth projects,Revolving Loan by an additional $200 million, subject to lender consent.consent and certain other customary conditions.
At SeptemberJune 30, 2017,2021, we had $1.4 billion borrowed$118.2 million outstanding under our $1.7 billion credit facility,Revolving Loan, with $38.7$19.6 million of the borrowed amount designated as a loan under the inventory sublimit. Our new credit agreement allows up to $100.0 million of the capacity to be used for letters of credit, of which $12.8$1.3 million was outstanding at SeptemberJune 30, 2017.2021. Due to the revolving nature of loans under our credit facility,Revolving Loan, additional borrowings, and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our Revolving Loan at June 30, 2021 was $530.5 million, subject to compliance with covenants.
At June 30, 2021, we had $300 million borrowed under our Term Loan. Principal repayments on the Term Loan under our new credit facilityagreement are as follows:
Year
Principal Due (1)
2021$15,000 
202260,000 
2023100,000 
2024125,000 
(1)    Principal repayments of $15 million are due at Septemberthe end of each calendar quarter starting December 31, 2021 until December 31, 2022. Principal repayments of $25 million are due at the end of each calendar quarter during 2023, with the remaining balance due at the maturity date of March 15, 2024. We intend to make the scheduled repayments on our Term Loan with the available borrowing capacity under our Revolving Loan.
Under our new credit agreement, the permitted maximum consolidated leverage ratio is 5.85x through June 30, 2017 was $314.7 million.2021, 5.75x through March 31, 2022, and then 5.50x thereafter. The permitted maximum consolidated senior secured leverage ratio is 2.50x, and the minimum interest coverage ratio is 2.50x for the full term of the agreement. As of June 30, 2021, we were in compliance with the financial covenants contained in our new credit agreement and indentures for our senior unsecured notes indentures as described below.
Senior Unsecured Note IssuanceTransactions
On August 14, 2017,January 16, 2020, we issued $550$750 million in aggregate principal amount of 6.50%our 7.75% senior unsecured notes due OctoberFebruary 1, 2025.2028 (the “2028 Notes”). Interest payments are due AprilFebruary 1 and OctoberAugust 1 of each year. That issuance generated net proceeds of $736.7 million, net of issuance costs incurred. We used $554.8 million of the net proceeds to redeem the portion of the 6.75% senior unsecured notes due August 1, 2022 (the "2022 Notes") (including principal, accrued interest and tender premium) that were validly tendered, and the remaining net proceeds were used to repay a portion of the borrowings outstanding under our revolving credit facility. On January 17, 2020 we called for redemption the 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 Notes, inclusive of our transactions costs and the write-off of the related unamortized debt issuance costs and discount, which is recorded in "Other income (expense)" in our Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30, 2020.
On December 17, 2020, we issued $750 million in aggregate principal amount of our 8.00% senior unsecured notes due January 15, 2027 (the "2027 Notes"). Interest payments are due on January 15 and July 15 of each year with the initial interest payment due April 1, 2018. Thaton July 15, 2021. The issuance generated net proceeds of $540.1approximately $737 million, net of issuance costs incurred. TheWe used $316.5 million of the net proceeds to repay the portion of the 6.00% senior unsecured notes due May 15, 2023 (the "2023 Notes") (including principal, accrued interest and tender premium) that were validly tendered, and the remaining proceeds were used to fundrepay a portion of the purchase price forborrowings outstanding under our acquisitionrevolving credit facility. On January 19, 2021, we redeemed the remaining principal balance outstanding on our 2023 Notes of $80.9 million in accordance with the terms and conditions of the Alkali Business.
9. Partners’ Capital, Mezzanine Equityindenture governing the 2023 Notes. We incurred a total loss of approximately $1.6 million relating to the extinguishment of our remaining 2023 Notes, inclusive of the redemption fee and Distributions
At September 30, 2017, our outstanding common units consistedthe write-off of 122,539,221 Class A units and 39,997 Class B units.

the related unamortized
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


debt issuance costs, which is recorded in "Other income (expense)" in our Unaudited Condensed Consolidated Statements of Operations for the six months ended June 30, 2021.
On March 24, 2017,April 22, 2021, we completed our offering of an additional $250 million in aggregate principal amount of our 2027 Notes. The notes constitute an additional issuance of our existing 2027 Notes that we issued 4,600,000on December 17, 2020 in an aggregate principal amount of $750 million. The additional $250 million of notes have identical terms as (other than with respect to the issue price) and constitute part of the same series of the 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75% plus accrued interest from December 17, 2020. We used the net proceeds from the offering for general partnership purposes, including repaying a portion of the revolving borrowings outstanding under our new credit agreement.
During 2020, we repurchased certain of our senior unsecured notes on the open market and recorded cancellation of
debt income of $18.5 million and $19.7 million for the three and six months ended June 30, 2020, respectively. These are
recorded within "Other income (expense)" in our Unaudited Consolidated Statements of Operations.

Our $2.9 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, Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and certain other subsidiaries. The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020 and the ownership of Genesis NEJD Pipeline LLC's pipeline was transferred in October 2020. 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 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 23, 2019 (the "Services Agreement").
10. Partners’ Capital, Mezzanine Capital and Distributions
At June 30, 2021, our outstanding common units consisted of 122,539,221 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.and 39,997 Class B units.
Distributions
We paid or will pay the following distributions to our common unitholders in 20162020 and 2017:2021:
Distribution For Date Paid 
Per Unit
Amount
 
Total
Amount
 Distribution ForDate PaidPer Unit
Amount		Total
Amount
2016     
20202020
1st Quarter
 May 13, 2016 $0.6725
 $73,961
 
1st Quarter
May 15, 2020$0.15 $18,387 
2nd Quarter
 August 12, 2016 $0.6900
 $81,406
 
2nd Quarter
August 14, 2020$0.15 $18,387 
3rd Quarter
 November 14, 2016 $0.7000
 $82,585
 
3rd Quarter
November 13, 2020$0.15 $18,387 
4th Quarter
 February 14, 2017 $0.7100
 $83,765
 
4th Quarter
February 12, 2021$0.15 $18,387 
2017     
20212021
1st Quarter
 May 15, 2017 $0.7200
 $88,257
 
1st Quarter
May 14, 2021$0.15 $18,387 
2nd Quarter
 August 14, 2017 $0.7225
 $88,563
 
2nd Quarter
August 13, 2021(1)$0.15 $18,387 
3rd Quarter
 November 14, 2017
(1) 
$0.5000
 $61,290
 
(1) This distribution was declared on July 7, 2021 and will be paid to unitholders of record as of October 31, 2017.July 30, 2021.

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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 June 30, 2021 we sold $750 million ofhad 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 unitsClass 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.    
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 haveAccounting for the option to payClass A Convertible Preferred Units
Our Class A Convertible Preferred Units are considered redeemable securities under GAAP due to the holdersexistence of redemption provisions upon a deemed liquidation event that is outside our preferred unitscontrol. Therefore, we present them as temporary equity in the applicable distributionmezzanine section of the Unaudited Condensed Consolidated Balance Sheets. 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 permittedrequired to convert more than 7,416,498adjust the carrying amount of our preferred units in any consecutive twelve-month period. At any time after September 1, 2020, ifClass A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we have fewer than 592,768would 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 equalClass A Convertible Preferred Units to the greaterredemption value over a period of (i)time comprising the then-applicable conversion ratedate the feature first becomes probable and (ii) the quotient of (a)date the Issue Priceunits can first be redeemed. Our Class A Convertible Preferred Units contain a distribution Rate Reset Election (as defined in Note 15). This Rate Reset Election is bifurcated and (b) 95% ofaccounted 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.
    Net Loss Attributable to Genesis Energy, L.P. is reduced by Class A Convertible Preferred Unit distributions that accumulated during the volume-weighted average price of our common unitsperiod. Net Loss Attributable to Genesis Energy, L.P. was reduced by $18.7 million and $37.4 million for the 30-trading day period ending priorthree and six months ended June 30, 2021 and 2020.
    We paid or will pay the following cash distributions to the date that we notify the holdersour Class A Convertible Preferred unitholders in 2020 and 2021:
Distribution ForDate PaidPer Unit
Amount		Total
Amount
2020
1st Quarter
May 15, 2020$0.7374 $18,684 
2nd Quarter
August 14, 2020$0.7374 $18,684 
3rd Quarter
November 13, 2020$0.7374 $18,684 
4th Quarter
February 12, 2021$0.7374 $18,684 
2021
1st Quarter
May 14, 2021$0.7374 $18,684 
2nd Quarter
August 13, 2021(1)$0.7374 $18,684 
(1) This distribution was declared on July 7, 2021 and will be paid to unitholders of our outstanding preferred unitsrecord as of such conversion.July 30, 2021.
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


Redeemable Noncontrolling Interests
cease to be listed), require us to use commercially reasonable efforts to cause the surviving entity in any such transaction to issue    On September 23, 2019, we, through a substantially equivalent securitysubsidiary, Alkali Holdings, entered into an amended and restated Limited Liability Company Agreement of Alkali Holdings (the "LLC Agreement") and a Securities Purchase Agreement (the "Securities Purchase Agreement") whereby certain investment fund entities affiliated with GSO Capital Partners LP (collectively "GSO") purchased $55,000,000 (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 ending 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% 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 their55,000 Alkali Holdings 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 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 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 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 rightcommitted to purchase up to 50%$350,000,000 of any parity securities on substantially the same terms offered to other purchasers for so long as an initial purchaser (including its affiliates) owns at least 11,124,747 of our preferred units in Alkali Holdings, the entity that holds our trona and (iii)trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the rightnet proceeds from the Alkali Holdings preferred units to appoint two directorsfund up to 100% of the anticipated cost of expansion of the Granger facility (the "Granger Optimization Project" or "GOP"). On April 14, 2020, we entered into an amendment to our general partner’s boardagreements with GSO to, among other things, extend the construction timeline of directors if (and so long as)the GOP by one year, which we fail to paycurrently anticipate completing in full any three quarterly distribution amounts, whether or not consecutive, attributable to any quarter ending after March 1, 2019.
The Rate Reset Electionthe second half of these2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units represents an embedded derivative that must be bifurcated fromto GSO, which was accounted for as issuance costs. As part of the related host contractamendment, the commitment period was increased to four years, and recorded at fair valuethe total commitment of GSO was increased to, subject to compliance with the covenants contained in the agreements with GSO, up to $351,750,000 preferred units (or 351,750 preferred units) in Alkali Holdings. As of June 30, 2021, there are 201,705 Alkali Holdings preferred units outstanding.
Accounting for Redeemable Noncontrolling Interests
    Classification
The Alkali Holdings preferred units issued and outstanding are accounted for as a redeemable noncontrolling interest in the mezzanine section on our Unaudited Condensed Consolidated Balance Sheet. See further information in Note 14. TheSheets due to the redemption features for a change of control.
Initial and Subsequent Measurement
We recorded the Alkali Holdings preferred units themselvesat their issuance date fair value, net of issuance costs. The fair value as of June 30, 2021 represents the carrying amount based on the issued and outstanding Alkali Holdings preferred units most probable redemption event on the six and a half 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 Loss Attributable to Genesis Energy, L.P. for the three months ended June 30, 2021 includes $5.8 million of adjustments, of which $4.9 million was allocated to the paid-in-kind ("PIK") distributions on the outstanding Alkali Holdings preferred units and $0.9 million was attributable to redemption accretion value adjustments. Net Loss Attributable to Genesis Energy, L.P. for the six months ended June 30, 2021 includes $10.6 million of adjustments, of which $9.0 million was allocated to the PIK distributions on the outstanding Alkali Holdings preferred units and $1.6 million was attributable to redemption accretion value adjustments. Net Loss Attributable to Genesis Energy, L.P. for the three months ended June 30, 2020 includes $4.2 million of adjustments, of which $3.4 million was allocated to the PIK distributions and $0.8 million was attributable to redemption accretion value adjustments. Net Loss Attributable to Genesis Energy, L.P. for the six months ended June 30, 2020 includes $8.2 million of adjustments, of which $6.7 million was allocated to the PIK distributions and $1.5 million was attributable to redemption accretion value adjustments. We elected to pay distributions for the period ended June 30, 2021 in-kind to our Alkali Holdings preferred unitholders. The unitholders liquidation preference is increased by new issuances and PIK distributions and is reduced by tax distributions paid to the unitholders, which are classified as mezzaninerequired to be paid by us to fulfill the income tax liabilities of each holder of Alkali Holdings preferred units.
    As of the reporting date, there are 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 June 30, 2021, the redemption amount would be equal to $248.9 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, 2020 to June 30, 2021:

Balance as of December 31, 2020$141,194 
Issuance of preferred units, net of issuance costs (1)
59,247 
PIK distribution8,955 
Redemption accretion1,602 
Tax distributions (1)
(6,351)
Balance as of June 30, 2021$204,647 

(1) During the period ended June 30, 2021, we issued 6,356 Alkali Holdings preferred units to GSO to satisfy the company's obligation to pay tax distributions. Additionally, we issued 54,100 Alkali Holdings preferred units to GSO during the six months ended June 30, 2021 to continue to fund the GOP.

10.
11. Net IncomeLoss 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 Seriesour Class A Convertible Preferred unitsUnits is calculated using the if-converted method. Under the if-converted method, the Series A Preferredthese units are assumed to be converted at the beginning of the period (beginning with their

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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 ninesix months ended SeptemberJune 30, 2017,2021, the effect of the assumed conversion of the 22,249,494 Series25,336,778 Class A convertible preferred unitsConvertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.
The following table reconciles net incomeloss and weighted average units used in computing basic and diluted net incomeloss per common unit (in thousands, except per unit amounts)thousands):
Three Months Ended
June 30,		Six Months Ended
June 30,
2021202020212020
Net Loss Attributable to Genesis Energy L.P.$(41,682)$(326,714)$(75,906)$(301,805)
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684)(18,684)(37,368)(37,368)
Net Loss Available to Common Unitholders$(60,366)$(345,398)$(113,274)$(339,173)
Weighted Average Outstanding Units122,579 122,579 122,579 122,579 
Basic and Diluted Net Loss per Common Unit$(0.49)$(2.82)$(0.92)$(2.77)


21
 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 Units122,579
 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 four4 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 the processing of high sulfur (or “sour”) gas streams as part of refining operationsfor refineries to remove the sulfur, and the selling of 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.
•Onshore facilities and transportation – terminalling, blending, storing, marketing and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products); and
•Marine transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; andAmerica.
Substantially all of our revenues are derived from and substantially all of our assets that 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, amortization and amortization)accretion), 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 rightslong-term incentive compensation plan and includes the non-income portion of payments received under the previously owned direct financing leases.lease.
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


Segment information for the periods presented below was as follows:
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesOnshore Facilities & TransportationMarine TransportationTotal
Three Months Ended June 30, 2021
Segment margin (a)$83,106 $38,194 $22,368 $8,468 $152,136 
Capital expenditures (b)$19,421 $80,560 $2,487 $11,157 $113,625 
Revenues:
External customers$73,221 $239,258 $144,406 $46,970 $503,855 
Intersegment (c)0 (2,171)1,515 656 0 
Total revenues of reportable segments$73,221 $237,087 $145,921 $47,626 $503,855 
Three Months Ended June 30, 2020
Segment margin (a)$75,148 $24,824 $21,215 $18,138 $139,325 
Capital expenditures (b)$1,983 $33,462 $829 $3,493 $39,767 
Revenues:
External customers$64,964 $194,543 $74,690 $54,270 $388,467 
Intersegment (c)0 (1,919)(531)2,450 0 
Total revenues of reportable segments$64,964 $192,624 $74,159 $56,720 $388,467 
Six Months Ended June 30, 2021
Segment Margin (a)$167,375 $81,914 $43,367 $15,577 $308,233 
Capital expenditures (b)$30,949 $90,598 $3,586 $22,871 $148,004 
Revenues:
External customers$137,605 $468,564 $332,556 $86,349 $1,025,074 
Intersegment (c)0 (4,190)2,582 1,608 0 
Total revenues of reportable segments$137,605 $464,374 $335,138 $87,957 $1,025,074 
Six Months Ended June 30, 2020
Segment Margin (a)$160,394 $61,765 $49,314 $37,140 $308,613 
Capital expenditures (b)$3,010 $48,437 $1,986 $17,725 $71,158 
Revenues:
External customers$143,393 $440,078 $231,489 $113,430 $928,390 
Intersegment (c)0 (4,064)(1,572)5,636 0 
Total revenues of reportable segments$143,393 $436,014 $229,917 $119,066 $928,390 
 Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Marine Transportation Onshore Facilities & 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         
Segment Margin (a)$243,528
 $63,864
 $39,768
 $71,999
 $419,159
Capital expenditures (b)$8,498
 $1,331,892
 $44,496
 $115,663
 $1,500,549
Revenues:         
External customers$244,653
 $204,237
 $143,599
 $715,839
 $1,308,328
Intersegment (c)(1,216) (6,358) 8,439
 (865) —
Total revenues of reportable segments$243,437
 $197,879
 $152,038
 $714,974
 $1,308,328
Nine Months Ended September 30, 2016         
Segment Margin (a)$249,457
 $61,586
 $53,695
 $63,969
 $428,707
Capital expenditures (b)$35,175
 $1,645
 $62,928
 $258,681
 $358,429
Revenues:         
External customers$242,672
 $136,437
 $155,197
 $750,134
 $1,284,440
Intersegment (c)2,165
 (6,852) 4,733
 (46) —
Total revenues of reportable segments$244,837
 $129,585
 $159,930
 $750,088
 $1,284,440
(a)A reconciliation of total Segment Margin to net loss attributable to Genesis Energy, L.P. for the periods is presented below.
Total assets by reportable segment(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 contributions to equity investees, if any.
(c)Intersegment sales were as follows:
 September 30,
2017		 December 31,
2016
Offshore pipeline transportation$2,507,540
 $2,575,335
Sodium minerals and sulfur services1,826,815
 395,043
Onshore facilities and transportation1,939,355
 1,875,403
Marine transportation811,870
 813,722
Other assets52,054
 43,089
Total consolidated assets7,137,634
 5,702,592
(a)A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for the periods is presented below.
(b)Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same.

conducted under terms that we believe were no more or less favorable than then-existing market conditions.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


    Total assets by reportable segment were as follows:
(c)Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
June 30,
2021		December 31, 2020
Offshore pipeline transportation$2,152,939 $2,187,083 
Sodium minerals and sulfur services2,041,083 1,962,146 
Onshore facilities and transportation1,011,805 1,035,662 
Marine transportation710,870 711,058 
Other assets46,790 37,670 
Total consolidated assets$5,963,487 $5,933,619 

Reconciliation of total Segment Margin to net income:loss attributable to Genesis Energy, L.P.:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
Total Segment Margin$152,136 $139,325 $308,233 $308,613 
Corporate general and administrative expenses(12,359)(24,867)(23,511)(31,359)
Depreciation, depletion, amortization and accretion(69,684)(82,580)(138,681)(158,558)
Interest expense(59,169)(51,618)(116,998)(106,583)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(7,692)(5,776)(16,548)(12,182)
Other non-cash items (2)
(14,683)(23,291)(33,127)8,777 
Distribution from unrestricted subsidiaries not included in income (3)
(17,500)(2,294)(35,000)(4,532)
Cancellation of debt income (4)
0 18,532 0 19,725 
Loss on extinguishment of debt (4)
0 0 (1,627)(23,480)
Differences in timing of cash receipts for certain contractual arrangements (5)
(6,446)(11,638)(6,745)(16,128)
Impairment expense (6)
0 (277,495)0 (277,495)
Provision for leased items no longer in use6 (58)(598)72 
Redeemable noncontrolling interest redemption value adjustments (7)
(5,766)(4,159)(10,557)(8,245)
Income tax expense(525)(795)(747)(430)
Net loss attributable to Genesis Energy, L.P.$(41,682)$(326,714)$(75,906)$(301,805)
 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)(1)    Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)Certain cash payments received from customers under certain of our minimum payment obligation contracts are not recognized as revenue under GAAP in the period in which such payments are received.
12. Transactions(2)     The three and six months ended June 30, 2021 include a $14.3 million unrealized loss and $32.8 million unrealized loss, respectively, from the valuation of the embedded derivative associated with Related Partiesour Class A Convertible Preferred Units. The three and six months ended June 30, 2020 include a $21.8 million unrealized loss and $10.7 million unrealized gain, respectively, from the valuation of the embedded derivative. Refer to Note 16 for details.
Sales, purchases(3)    The three 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,
 2017 2016 2017 2016
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 product sales to ANSAC31,774
 —
 31,774
 —
Costs and expenses:       
Amounts paid to our CEO in connection with the use of his aircraft$165
 $165
 $495
 $495
Charges for services from Poseidon Oil Pipeline Company, LLC (2)254
 251
 744
 749
Charges for services from ANSAC454
 —
 454
 —
(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 Septembersix months ended June 30, 2017 and December 31, 2016 (i) Sandhill Group, LLC owed us $0.22021 include $17.5 million and $0.2$35.0 million, respectively, for purchases of CO2,in cash receipts not included in income associated with principal repayments on our previously owned NEJD pipeline. The three and (ii) Poseidon Oil Pipeline Company, LLC owed us $2.0six months ended June 30, 2020 include $2.3 million and $1.6$4.5 million, respectively, in cash receipts not included in income associated with principal repayments on our NEJD pipeline. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit facility. See Note 4for services rendered.details.

(4)     Refer to Note 9 for details surrounding the repurchases of certain of our senior unsecured notes and the extinguishment of our 2022 Notes and 2023 Notes.
(5)    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.
(6)    Refer to Note 6 for details surrounding our non-cash impairment expense recorded for the three and six months ended June 30, 2020.
(7) Includes PIK distributions attributable to the period and accretion on the redemption feature.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


13. Transactions with Unconsolidated AffiliatesRelated Parties
The transactions with related parties were as follows:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
Revenues:
Revenues from services and fees to Poseidon(1)
$3,242 $3,035 $7,028 $6,182 
Revenues from product sales to ANSAC71,329 48,695 139,284 121,774 
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft$165 $165 $330 $330 
Charges for services from Poseidon(1)
238 249 478 503 
Charges for services from ANSAC519 629 697 1,461 
(1)We own a 64% interest in Poseidon.

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

Poseidon
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 automatically renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three and ninesix months ended SeptemberJune 30, 20172021 reflect the $2.1$2.4 million and $6.3$4.7 million, respectively, associated with this agreement. Our revenues for the three and six months ended June 30, 2020 reflect $2.3 million and $4.6 million, respectively, of fees we earned through the provision of services under that agreement. At June 30, 2021 and December 31, 2020, Poseidon owed us $2.9 million and $2.6 million, respectively, for services rendered.

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 theour 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 them. 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 June 30, 2021, such amount is not material to us.
    Net salesSales to ANSAC were $31.8$71.3 million and $139.3 million during the period September 1, 2017 to Septemberthree and six months ended June 30, 2017.2021 and were $48.7 million and $121.8 million during the three and six months ended June 30, 2020. The costs charged to us by ANSAC, included in sodium minerals and sulfur services operating costs, were $0.5 million and $0.7 million during the period September 1, 2017 to Septemberthree and six months ended June 30, 2017.2021 and were $0.6 million and $1.5 million during the three and six months ended June 30, 2020.
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Receivables from and payables to ANSAC as of SeptemberJune 30, 20172021 and December 31, 2020 are as follows:
 June 30,December 31,
 20212020
Receivables:
ANSAC$66,178 $43,400 
Payables:
ANSAC$169 $470 

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

13.14. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
Nine Months Ended
September 30,		 Six Months Ended
June 30,
2017 2016 20212020
(Increase) decrease in:   (Increase) decrease in:
Accounts receivable$(79,938) $11,029
Accounts receivable$(77,785)$178,509 
Inventories31,973
 (26,215)Inventories21,550 (44,394)
Deferred charges(293) (5,291)Deferred charges9,823 9,240 
Other current assets(2,769) 5,184
Other current assets(4,835)(9,919)
Increase (decrease) in:   Increase (decrease) in:
Accounts payable32,896
 (27,213)Accounts payable49,809 (93,080)
Accrued liabilities(8,131) (20,901)Accrued liabilities32,710 (20,838)
Net changes in components of operating assets and liabilities(26,262) (63,407)Net changes in components of operating assets and liabilities$31,272 $19,518 
Payments of interest and commitment fees were $126.9$78.0 million and $125.1$97.8 million for the ninesix months ended SeptemberJune 30, 20172021 and SeptemberJune 30, 2016,2020, respectively. We capitalized interest of $13.8$1.4 million and $19.9$1.0 million during the ninesix months ended SeptemberJune 30, 20172021 and SeptemberJune 30, 2016.2020, respectively.
At SeptemberJune 30, 20172021 and SeptemberJune 30, 2016,2020, we had incurred liabilities for fixed and intangible asset additions totaling $25.7$71.5 million and $55.3$25.5 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not

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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. The increase in this amount is principally due to the increase in capital expenditures associated with our GOP, which has the ability to be fully financed with our Alkali Holding preferred units, subject to compliance with the covenants contained in the agreements with GSO (Note 10).


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
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
    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. We had 0 outstanding swap contracts at June 30, 2021.
At SeptemberJune 30, 2017,2021, we hadentered into the following outstanding derivative commodity contracts that were entered into to economically hedge inventory, or fixed price purchase commitments.commitments or forecasted purchases.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


 
Sell (Short)
Contracts
 
Buy (Long)
Contracts
Sell (Short)
Contracts		Buy (Long)
Contracts
Designated as hedges under accounting rules:    Designated as hedges under accounting rules:
Crude oil futures:    Crude oil futures:
Contract volumes (1,000 bbls) 694
 —
Contract volumes (1,000 bbls)92 0 
Weighted average contract price per bbl $48.03
 $—
Weighted average contract price per bbl$70.71 $0 
    
Not qualifying or not designated as hedges under accounting rules:    Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:    Crude oil futures:
Contract volumes (1,000 bbls) 482
 322
Contract volumes (1,000 bbls)204 10 
Weighted average contract price per bbl $50.17
 $50.76
Weighted average contract price per bbl$70.75 $72.66 
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
Natural gas futures:Natural gas futures:
Contract volumes (10,000 MMBTU)Contract volumes (10,000 MMBTU)15 15 
Weighted average contract price per MMBTUWeighted average contract price per MMBTU$3.55 $3.14 
Crude oil options:    Crude oil options:
Contract volumes (1,000 bbls) 50
 20
Contract volumes (1,000 bbls)8 0 
Weighted average premium received $0.63
 $0.19
Weighted average premium received/paidWeighted average premium received/paid$5.59 $0 
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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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


The following tables reflect the estimated fair value gain (loss) position of our derivatives at SeptemberJune 30, 20172021 and December 31, 2016:2020:
Fair Value of Derivative Assets and Liabilities
 Unaudited Condensed Consolidated Balance Sheets LocationFair Value
 June 30,
2021		 December 31, 2020
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assetsCurrent Assets - Other$65 $732 
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other(65)(732)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$0 $0 
Natural Gas Swap (undesignated hedge)Current Assets - Other0 616 
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assetsCurrent Assets - Other$13 $1,022 
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other(13)(1,022)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$0 $0 
Liability Derivatives:
Preferred Distribution Rate Reset Election (2)
Other long-term liabilities(85,154)(52,372)
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities
Current Assets - Other (1)
$(605)$(2,114)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
605 2,114 
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$0 $0 
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities
Current Assets - Other (1)
$(267)$(3,345)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
267 3,073 
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$0 $(272)
 (1)    These derivative liabilities have been funded with margin deposits recorded in our Unaudited Condensed Consolidated Balance Sheets under Current Assets - Other.
 Unaudited Condensed Consolidated Balance Sheets Location Fair Value
 September 30,
2017		 December 31,
2016
Asset Derivatives:     
Commodity derivatives - futures and call options (undesignated hedges):     
Gross amount of recognized assetsCurrent Assets - Other $503
 $443
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other (503) (443)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $—
 $—
Commodity derivatives - futures and call options (designated hedges):     
Gross amount of recognized assetsCurrent Assets - Other $43
 $3,321
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other (43) (3,321)
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) —
Commodity derivatives - futures and call options (undesignated hedges):     
Gross amount of recognized liabilities
Current Assets - Other (1)
 $(1,167) $(1,772)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 1,167
 1,772
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $—
 $—
Commodity derivatives - futures and call options (designated hedges):     
Gross amount of recognized liabilities
Current Assets - Other (1)
 $(2,643) $(9,506)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 2,459
 7,589
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 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 SeptemberJune 30, 2017,2021, we had a net broker receivable of approximately $3.1$1.5 million (consisting of initial margin of $2.4$1.5 million increased by $0.7 million of and 0 variation margin).  As of December 31, 2016,2020, we had a net broker receivable of approximately $5.6$3.4 million (consisting of initial margin of $5.1 million increased by $0.5 million of variation margin).  At

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


September(consisting of initial margin of $3.3 million increased by $0.1 million of variation margin).  At June 30, 20172021 and December 31, 2016,2020, 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 unitsClass A Convertible Preferred Units may make a Rateone-time election to reset the quarterly distribution amount (a "Rate Reset ElectionElection") to a cash amount per preferred unitClass A Convertible Preferred Unit equal to the amount that would be payable per quarter if a preferred unitClass 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 unitsour 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"Other income (expense)" in our Unaudited Condensed Consolidated Statement of Operations. At SeptemberJune 30, 2017,2021, the fair value of this embedded derivative was a liability of $36.7$85.2 million. See Note 910 for additional information regarding our SeriesClass A preferred unitsConvertible Preferred Units and the Rate Reset Election.
Effect on Operating Results
Amount of Gain (Loss) Recognized in Income
 Unaudited Condensed Consolidated Statements of Operations LocationThree Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidanceOnshore facilities and transportation product costs$(1,563)$(10,936)$(7,460)$(10,207)
Contracts not considered hedges under accounting guidanceOnshore facilities and transportation product costs, Sodium minerals and sulfur services operating costs(1,779)(2,642)(5,700)(4,017)
Total commodity derivatives$(3,342)$(13,578)$(13,160)$(14,224)
Natural Gas SwapSodium minerals and sulfur services operating costs$30 $983 $(37)$551 
Preferred Distribution Rate Reset ElectionOther income (expense)$(14,344)$(21,839)$(32,782)$10,706 
   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 guidanceOnshore facilities and transportation product costs $(3,399) $1,672
 $8,433
 $(8,279)
Contracts not considered hedges under accounting guidanceOnshore 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 ElectionOther 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
(3)Level 3 fair values are based on unobservable inputs in which little or no market data exists.
(1)Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;
(2)Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and
(3)Level 3 fair values are based on unobservable inputs in which little or no market data exists.
As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

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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 SeptemberJune 30, 20172021 and December 31, 2016.2020.
 Fair Value atFair Value at
June 30, 2021December 31, 2020
Recurring Fair Value MeasuresLevel 1Level 2Level 3Level 1Level 2Level 3
Commodity derivatives:
Assets$78 $0 $0 $1,754 $616 $0 
Liabilities$(872)$0 $0 $(5,459)$0 $0 
Preferred Distribution Rate Reset Election$0 $0 $(85,154)$0 $0 $(52,372)
  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:

Six Months Ended
June 30,
2021
Balance as of December 31, 2020$(52,372)
Unrealized loss for the period included in earnings(32,782)
Balance as of June 30, 2021$(85,154)
 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 June 30, 2021.
The fair value of the embedded derivative feature is based on a valuation model that estimates the fair value of the convertible preferred unitsour 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 ofrelative 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 June 30, 2021. 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 reportDue to a decrease in our discount yield compared to the preceding quarters, as well as the passage of time as we draw nearer to our coupon rate reset date in 2022, we recorded unrealized gainslosses of $14.3 million and losses associated with this embedded derivative$32.8 million, respectively, for the three and six months ended June 30, 2021. During the second quarter of 2020, we recorded an unrealized loss of $21.8 million, while in the first quarter of 2020, we recorded an unrealized gain of $32.5 million, due to the significant changes and fluctuations in the energy industry credit markets and our common unit price during the period. These effects are all recorded within "Other income (expense)" on the Unaudited Condensed Consolidated Statements of Operations as Other income (expense), net.Operations.
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 SeptemberJune 30, 20172021 our senior unsecured notes had a carrying value of $2.9 billion and fair value of $2.4$3.0 billion compared to $1.8a carrying value of $2.8 billion and $1.9fair value of $2.7 billion respectively, at December 31, 2016.2020. 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.

16.17. 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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.


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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.

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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.



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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 assets75
 —
 569,457
 11,836
 (238) 581,130
Total current assets81
 —
 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, net15,229
 —
 382,916
 128,306
 (151,026) 375,425
Advances to affiliates3,889,517
 —
 —
 82,479
 (3,971,996) —
Equity investees—
 —
 383,191
 —
 —
 383,191
Investments in subsidiaries2,666,281
 —
 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 facility1,372,500
 —
 —
 —
 —
 1,372,500
Senior unsecured notes2,358,049
 —
 —
 —
 —
 2,358,049
Deferred tax liabilities—
 —
 26,399
 —
 —
 26,399
Advances from affiliates—
 —
 3,971,992
 —
 (3,971,992) —
Other liabilities36,727
 —
 183,552
 187,057
 (150,874) 256,462
Total liabilities3,802,007
 —
 4,503,282
 195,149
 (4,123,017) 4,377,421
Mezzanine Capital:           
Series A Convertible Preferred Units691,708
 —
 —
 —
 —
 691,708
Partners’ capital, common units2,077,393
 —
 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


30
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 assets50
 —
 340,555
 12,237
 (302) 352,540
Total current assets56
 —
 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, net10,696
 —
 390,214
 133,980
 (140,533) 394,357
Advances to affiliates2,650,930
 —
 —
 73,295
 (2,724,225) —
Equity investees—
 —
 408,756
 —
 —
 408,756
Investments in subsidiaries2,594,882
 —
 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 facility1,278,200
 —
 —
 —
 —
 1,278,200
Senior unsecured notes1,813,169
 —
 —
 —
 —
 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 liabilities3,126,233
 —
 3,126,970
 194,097
 (2,864,758) 3,582,542
Mezzanine Capital:           
Series A Convertible Preferred Units—
 —
 —
 —
 —
 —
Partners’ capital, common units2,130,331
 —
 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





















31
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 subsidiaries55,971
 —
 (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 taxes6,312
 —
 56,332
 (581) (55,583) 6,480
Income tax benefit (expense)—
 —
 (322) 2
 —
 (320)
NET INCOME6,312
 —
 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


32
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 subsidiaries66,811
 —
 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 taxes32,101
 —
 67,799
 (129) (66,839) 32,932
Income tax expense—
 —
 (949) —
 —
 (949)
NET INCOME32,101
 —
 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


















33
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 subsidiaries191,471
 —
 (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 taxes67,135
 —
 192,469
 (1,610) (190,438) 67,556
Income tax expense—
 —
 (880) 2
 —
 (878)
NET INCOME67,135
 —
 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


34
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 subsidiaries195,674
 —
 (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 taxes91,131
 —
 198,753
 (540) (195,624) 93,720
Income tax (expense) benefit—
 —
 (2,956) (3) —
 (2,959)
NET INCOME91,131
 —
 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



35
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 facility1,247,700
 —
 —
 —
 —
 1,247,700
Repayments on senior secured credit facility(1,153,400) —
 —
 —
 —
 (1,153,400)
Proceeds from issuance of senior unsecured notes550,000
 —
 —
 —
 —
 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, net140,513
 —
 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 activities1,236,377
 —
 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 period6
 —
 6,360
 663
 —
 7,029
Cash and cash equivalents at end of period$6
 $—
 $8,960
 $728
 $—
 $9,694

36
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 transfers54,148
 —
 —
 —
 (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 facility883,600
 —
 —
 —
 —
 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, net298,051
 —
 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 activities121,019
 —
 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 period6
 —
 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.Report.
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 attributableNet Loss Attributable to Genesis Energy, L.P. of $6.3$41.7 million or $0.01 per common unit, during the three months ended SeptemberJune 30, 2017 (“2017 Quarter”2021 (the "2021 Quarter") compared to net income attributableNet Loss Attributable to Genesis Energy, L.P. of $32.1$326.7 million or $0.28 per common unit, during the three months ended SeptemberJune 30, 2016 (“2016 Quarter”2020 (the "2020 Quarter").
Net incomeLoss Attributable to Genesis Energy, L.P. in the 2020 Quarter was negatively affectedimpacted by impairment expense of $277.5 million associated with the rail logistics assets included within our onshore facilities and transportation segment and a one-time charge of approximately $25.2$13 million or $0.21 per unit,associated with certain severance and restructuring costs included within general and administrative costs and expenses. Additionally, the 2020 Quarter included cancellation of debt income of $18.5 million, which is recorded within "Other income (expense)" on the Unaudited Condensed Consolidated Statements of Operations, associated with the open market repurchase and extinguishment of certain of our senior unsecured notes.
Net Loss Attributable to Genesis Energy, L.P. in the 2021 Quarter was impacted, relative to the 2020 Quarter, by: (i) lower depreciation, depletion and amortization expense of $12.6 million primarily due to transactionlower depreciation expense on our rail logistics assets as they were impaired during 2020; (ii) an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $14.3 million in the 2021 Quarter compared to an unrealized (non-cash) loss of $21.8 million during the 2020 Quarter recorded within Other income (expense); and financing expenses, as well as an increase in(iii) higher interest expense primarily driven by our acquisition of the Alkali Business during the quarter. For the 2017 Quarter, our operating results include one month of activity related to the Alkali Business$7.6 million (see "Other Costs, Interest, and Income Taxes" below for the month of September.additional discussion regarding interest expense).
Cash flow from operating activities was $33.8$111.0 million for the 20172021 Quarter compared to $124.7$62.6 million for the 20162020 Quarter. Cash flows from operating activities forThis increase is primarily attributable to higher Segment Margin of $12.8 million in the 20172021 Quarter were also negatively affected by certain non-recurring costs

described above as well as an increaseand positive changes in net working capital that is not necessarily meaningful to the underlying performance of the our businesses.capital.
Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") to our common unitholders was $91.8$49.6 million for the 20172021 Quarter, a decrease of $3.2$0.8 million, or 3.4%1.7%, from the 20162020 Quarter. See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves.
Segment Margin (as defined below in "Non-GAAP Financial Measures") was $152.1 million for the 2021 Quarter, an increase of $12.8 million, or 9%, from the 2020 Quarter. A more detailed discussion of our segment results and other costs are included below in "Results of Operations".
    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 million for the 2017 Quarter, an increase of $5.2 million, or 3.7%, from the 2016 Quarter.
A more detailed discussion of our segment results and other costs is included below in "Results of Operations".
Distribution
In October 2017,July 2021, we declared our quarterly distribution to our common unitholders $0.50of $0.15 per unitsunit related to the 2017 Quarter, which will be paid in November 2017.

2021 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, 2017August 13, 2021 to unitholders holders of record at the close of business on November 3, 2017.July 30, 2021.
Segment Reporting Change


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Covid-19 and Market 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 CISA and we have continued to operate our assets during this pandemic.
    We have a designated 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 best interests of our employees, stakeholders, customers, partners, and suppliers and make any necessary changes as required by federal, state, or local authorities as we continue to actively monitor the situation.
Beginning in March 2020, Covid-19 caused commodity prices to decline due to, among other things, reduced industrial activity and travel demand. Additionally, actions taken by OPEC and other oil exporting nations in that timeframe caused additional declines and volatility in the fourth quarterprice of 2016,oil and gas. While we started reporting our results on a comparative basishave seen some recovery in four business segments.commodity prices since the beginning of the pandemic, primarily due to economies re-opening over time, there is still an element of volatility that we expect to continue at least for the near-term and possibly longer, due to the continued uncertainty of the pandemic, which could further negatively impact oil, natural gas, and petroleum products and industrial products.
    Due to the increasingly integrated natureeconomic effects from commodity prices and Covid-19, demand and volumes throughout our businesses were negatively impacted throughout 2020 beginning in the second quarter. Additionally, during 2020, our businesses were negatively impacted by lower refinery utilization, crude differentials, supply and demand imbalances in our Alkali Business, and an unprecedented hurricane season. However, we began to see economic recovery across a majority of our onshore operations, the results ofasset footprint as we exited 2020, which has continued during 2021. Specifically, during 2021, our onshoreoffshore pipeline transportation segment formerly reported underexperienced volumes at its own segment, is now reportednormal run rate as we resumed normal operations on our CHOPS pipeline. Additionally, our Alkali Business has continued to see volume demand recovery and continued pricing recovery on our ANSAC export volumes.
We continue to monitor the market environment and will evaluate whether any triggering events would indicate possible impairments of long-lived assets, intangible assets and goodwill. Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results, including with respect to the duration and severity of the Covid-19 pandemic. In the current volatile economic environment and to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our onshore facilitiesresults of operations.
We believe the fundamentals of our core businesses continue to remain strong and, transportation segment. The onshore facilitiesgiven the current industry environment and transportation segment also now includes what was formerly reportedcapital market behavior, we have continued our focus on de-leveraging our balance sheet, which included the reduction of our distribution to common unitholders beginning in the first quarter of 2020 and continuing to recognize the benefits from our supply and logistics segment. This segment was renamedcost savings initiative in the second quarter of 20172020. Additionally, during the 2021 Quarter, we successfully refinanced and extended our senior secured credit facility and issued an additional $250 million in aggregate principal amount of our 2027 Notes. These two events resulted in no scheduled maturities of long-term debt until 2024, other than the minimal quarterly payments due on the Term Loan under our new credit agreement beginning at the end of 2021 (which will be financed by the available borrowing capacity under the Revolving Loan under our new credit agreement). Refer to more accurately describe the nature"Liquidity and Capital Resources" for additional discussion.

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Table of its 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.Contents

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 20172021 Quarter increased $26.1$115.4 million, or 5.7%30%, from the 20162020 Quarter which includes the effects of one month of revenue contributed by the Alkali Business. Additionally,and our total costs and expenses (excluding interest)impairment expense) as presented on the Unaudited Condensed Consolidated Statements of Operations increased $38.1$89.1 million, or 9.4%23%, 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.periods, with a net increase to our operating income of $26.3 million.
The increase in our operating income during the 2021 Quarter is primarily driven by: (i) lower general and administrative costs as the 2020 Quarter included a one-time charge of approximately $13 million associated with certain severance and restructuring costs; and (ii) lower depreciation, depletion, and amortization of $12.6 million primarily due to lower depreciation expense on our rail logistics assets as they were impaired during 2020.
A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products throughin our crude oil marketing business, which is included in our onshore facilities and transportation segment, and revenues and costs associated with our Alkali Business, which is included in our sodium minerals and sulfur services segment. The decreaseWe describe, in more detail, the impact on revenues and costs for each of our businesses below.
    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") increased to $66.07 per barrel in the 2021 Quarter, as compared to $27.85 per barrel in the 2020 Quarter. Impacts from Covid-19 along with actions taken by OPEC and other oil exporting nations beginning in early 2020 have caused significant and continued price volatility in oil and gas prices.
We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs in this segment between those two quarterly periods is primarily attributable to decreases inour purchase and sale of crude oil and petroleum product sales volumes as discussed further below. In general, we do not expect fluctuations in prices for crude oil and natural gas to materially affect ourproducts, producing minimal direct impact on Segment Margin, net income, and Available Cash before Reserves or Segment Margin to the same extent they affect our revenues and costs.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 affectour Alkali Business, our revenues and costs attributable to our purchaseare derived from the extraction of trona, as well as the activities surrounding the processing and sale of crude oilnatural soda ash and petroleumother alkali specialty products, producing minimalincluding 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. Our selling prices for volumes sold internationally and through ANSAC are contracted for the current year either annually in the prior December and January of the current year or periodically (often quarterly) throughout 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 may have a lesser impact to operating costs due to the indirect exposure to changesfact that a portion of our costs are fixed in prices discussed above, the factors addressednature. Our costs, of which some are variable in our onshore facilitiesnature and transportation segment discussion below, and the fact the crude oil prices have remained low for an extended period of time as comparedothers 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 2021 Quarter as noted above, we had positive effects to our revenues (with a lesser impact to costs) relative to the 2020 Quarter due to increased sales volumes and more favorable ANSAC pricing. For additional information, see our segment-by-segment analysis below.
In addition to our crude oil marketing business and petroleum product sales volumes have continuedAlkali Business discussed above, we continue to decline, including a 19.0% decreaseoperate 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 providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of billions ofa billion dollars) to develop numerous large reservoir,large-reservoir, long-lived crude oil and natural gas properties.properties; (ii) our sulfur services business, which is one of the largest producers and marketers (based on tons produced) 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%95% of the volumes transported on our onshore crude pipelines, and refiners contract for over 85%75% of the use of our inland barges, which are used primarily to transport intermediate refined products (not crude oil) between refiningrefining 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
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suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. ThoseTheir 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 lowerrelatively low commodity price environment.environments. Given these facts, we do not expect changes in commodity prices to impact our 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 and nine months ended September 30, 2017 and September 30, 2016 was as follows:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
 (in thousands)(in thousands)
Offshore pipeline transportation$83,106 $75,148 $167,375 $160,394 
Sodium minerals and sulfur services38,194 24,824 81,914 61,765 
Onshore facilities and transportation22,368 21,215 43,367 49,314 
Marine transportation8,468 18,138 15,577 37,140 
Total Segment Margin$152,136 $139,325 $308,233 $308,613 
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
 (in thousands) (in thousands)
Offshore pipeline transportation78,228
 86,557
 $243,528
 $249,457
Sodium minerals and sulfur services30,031
 20,526
 63,864
 61,586
Onshore facilities and transportation25,606
 17,560
 71,999
 63,969
Marine transportation12,649
 16,697
 39,768
 53,695
Total Segment Margin$146,514
 $141,340
 $419,159
 $428,707

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 expenseplus 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 reconciliationimportant 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.
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A reconciliation of total Segment Margin to net incomeNet Loss Attributable to Genesis Energy, L.P. for the periods presented is as follows:

 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
Total Segment Margin$152,136 $139,325 $308,233 $308,613 
Corporate general and administrative expenses(12,359)(24,867)(23,511)(31,359)
Depreciation, depletion, amortization and accretion(69,684)(82,580)(138,681)(158,558)
Interest expense(59,169)(51,618)(116,998)(106,583)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(7,692)(5,776)(16,548)(12,182)
Other non-cash items (2)
(14,683)(23,291)(33,127)8,777 
Distribution from unrestricted subsidiaries not included in income (3)
(17,500)(2,294)(35,000)(4,532)
Cancellation of debt income— 18,532 — 19,725 
Provision for leased items no longer in use6 (58)(598)72 
Differences in timing of cash receipts for certain contractual arrangements (4)
(6,446)(11,638)(6,745)(16,128)
Loss on debt extinguishment (5)
— — (1,627)(23,480)
Impairment expense— (277,495)— (277,495)
Redeemable noncontrolling interest redemption value adjustments (6)
(5,766)(4,159)(10,557)(8,245)
Income tax expense(525)(795)(747)(430)
Net Loss Attributable to Genesis Energy, L.P.$(41,682)$(326,714)$(75,906)$(301,805)
 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)
Gain on sale of assets—
 —
 26,684
 —
Non-cash provision for leased items no longer in use

—
 —
 (12,589) —
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
(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2) CertainThe three and six months ended June 30, 2021 include a $14.3 million unrealized loss and a $32.8 million unrealized loss, respectively, from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units. The three and six months ended June 30, 2020 include a $21.8 million unrealized loss and $10.7 million unrealized gain, respectively, from the valuation of the embedded derivative.
(3)The three and six months ended June 30,2021 include $17.5 million and $35.0 million, respectively, and the three and six months ended June 30,2020 include $2.3 million and $4.5 million, respectively, in cash payments receivedreceipts not included in income associated with principal repayments on our previously owned NEJD pipeline. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit facility.
(4)Includes the difference in timing of cash receipts from customers under certainduring the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our minimumNon-GAAP measures, we add those amounts in the period of payment obligation contracts are not recognized as revenue under GAAPand deduct them in the period in which such payments are received.GAAP recognizes them.
(5)The six months ended June 30, 2021 includes the transaction costs and write-off of the unamortized issuance costs associated with the redemption of our remaining 2023 Notes. The six months ended June 30, 2020 includes the transaction costs associated with the tender and redemption of our 2022 Notes, as well as the write-off of the unamortized issuance costs and discount associated with these notes.
(6) Includes PIK distributions attributable to the period and accretion on the redemption feature.


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Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
 (in thousands)(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues$70,153 $61,003 $132,815 $130,584 
Offshore natural gas pipeline revenue, excluding non-cash revenues10,567 10,302 20,964 23,639 
Offshore pipeline operating costs, excluding non-cash expenses(19,328)(14,010)(37,334)(31,742)
Distributions from equity investments (1)
21,714 17,853 50,930 37,913 
Offshore pipeline transportation Segment Margin$83,106 $75,148 $167,375 $160,394 
Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS204,963 196,962 160,940 219,572 
Poseidon265,359 253,341 302,180 266,261 
Odyssey125,170 114,006 131,771 133,375 
GOPL (2)
8,646 2,631 7,716 4,940 
Total crude oil offshore pipelines604,138 566,940 602,607 624,148 
Natural gas transportation volumes (MMBtus/d)347,123 329,876 336,456 375,283 
Volumetric Data net to our ownership interest (3):
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS204,963 196,962 160,940 219,572 
Poseidon169,830 162,138 193,395 170,407 
Odyssey36,299 33,062 38,214 38,679 
GOPL (2)
8,646 2,631 7,716 4,940 
Total crude oil offshore pipelines419,738 394,793 400,265 433,598 
Natural gas transportation volumes (MMBtus/d)108,695 106,919 105,614 127,695 
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
 (in thousands) (in thousands)
Offshore crude oil pipeline revenue$67,506
 $69,759
 $204,585
 $199,391
Offshore natural gas pipeline revenue13,164
 19,957
 38,852
 45,445
Offshore pipeline operating costs, excluding non-cash expenses(15,979) (20,292) (46,859) (54,463)
Distributions from equity investments (1)
19,535
 20,880
 59,100
 64,502
Other(5,998) (3,747) (12,150) (5,418)
Offshore pipeline transportation Segment Margin$78,228
 $86,557
 $243,528
 $249,457
        
Volumetric Data 100% basis:       
Crude oil pipelines (average barrels/day unless otherwise noted):       
CHOPS203,697
 190,613
 220,374
 200,753
Poseidon257,093
 263,519
 258,031
 259,446
Odyssey135,787
 107,252
 122,433
 106,622
GOPL (2)
8,317
 6,287
 8,166
 5,839
Total crude oil offshore pipelines604,894
 567,671
 609,004
 572,660
        
Natural gas transportation volumes (MMBtus/d)467,095
 775,546
 516,974
 656,452
        
Volumetric Data net to our ownership interest (3):
       
Crude oil pipelines (average barrels/day unless otherwise noted):       
CHOPS203,697
 190,613
 220,374
 200,753
Poseidon164,540
 168,652
 165,140
 166,045
Odyssey39,378
 31,103
 35,506
 30,920
GOPL (2)
8,317
 6,287
 8,166
 5,839
Total crude oil offshore pipelines415,932
 396,655
 429,186
 403,557
        
Natural gas transportation volumes (MMBtus/d)189,778
 502,792
 237,328
 374,950
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2021 and 2020, respectively.     
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2017 and 2016, respectively.
(2)One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system.
(3)Volumes are the product of our effective ownership interest through the year, including changes in ownership interest, multiplied by the relevant throughput over the given year.
(2)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 SeptemberJune 30, 20172021 Compared with Three Months Ended SeptemberJune 30, 20162020
Offshore Pipeline Transportationpipeline transportation Segment Margin for the 20172021 Quarter decreased $8.3increased $8.0 million, or 10%11%, from the 2016 Quarter. The 20172020 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 keyprimarily due to higher crude oil and natural gas assets, includingtransportation volumes. During the 2021 Quarter, we transported higher volumes on our Poseidon100% owned SEKCO pipeline as a result of increased production activity from the Buckskin and certain associated lateralsLucius fields, which are fully dedicated to SEKCO and further downstream to Poseidon. Additionally, we own. While suchexperienced less 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 reflects2021 Quarter, as the effects of a contractual step down2020 Quarter was impacted by extended downtime due to a lower transportation rate for a certain lateral which we own that will be in place going forward. In addition, the 2016 Quarter benefitedeconomic environment from the temporary diversionCovid-19 pandemic and as a result of certain natural gas volumesweather interruptions 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.Tropical Storm Cristobal.

NineSix Months Ended SeptemberJune 30, 20172021 Compared with NineSix Months Ended SeptemberJune 30, 20162020
Offshore pipeline transportation Segment Margin for the first ninesix months of 2017 decreased $5.92021 increased $7.0 million, or 2%4%, from the first ninesix months of 2016. The first nine months2020, primarily as a result of 2017the increased volumes transported on our 100% owned SEKCO pipeline as a result of increased production activity from the Buckskin and Lucius fields, which are fully dedicated to SEKCO and further
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downstream to Poseidon. This increase in volumes was negatively impactedpartially offset by both anticipatedlower volumes during 2021 on our CHOPS pipeline, as it was out of service through February 3, 2021 due to damage at a junction platform that the system goes up and unanticipated downtime at several major fields, including weather related downtime, affecting certainover as a result of our deepwater Gulf of Mexico customers and thus certain of our key crude oil and natural gas assets, including our Poseidonthe 2020 hurricane season. On February 4, 2021, we placed the CHOPS 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 duringback into service upon the fourth quarter of 2017. The nine months ended September 30, 2017 also reflects the effectsinstallation of a contractual step downbypass that allows our pipeline to aoperate around the junction platform. The lower transportation rate for a certain lateral whichCHOPS pipeline volumes were partially offset by increased distributions from our equity method investments, primarily associated with our 64% owned Poseidon oil pipeline system, as we own that will be in place going forward. In addition, the nine months ended September 30, 2016 benefited from the temporary diversionwere able to successfully divert CHOPS volumes to Poseidon during its out 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.service period.

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
June 30,		Six Months Ended
June 30,
2017 2016 2017 2016 2021202020212020
Volumes sold:       Volumes sold:
NaHS volumes (Dry short tons "DST")30,381
 34,299
 95,575
 96,116
NaHS volumes (Dry short tons "DST")28,052 21,942 56,854 52,024 
Soda Ash volumes (short tons sold) (2)
336,000
 —
 336,000
 —
NaOH (caustic soda) volumes (dry short tons sold) (3)
21,746
 19,653
 55,962
 59,802
Total388,127
 53,952
 487,537
 155,918
Soda Ash volumes (short tons sold)Soda Ash volumes (short tons sold)772,132 594,810 1,534,952 1,417,057 
NaOH (caustic soda) volumes (DST)NaOH (caustic soda) volumes (DST)21,124 20,326 41,386 36,629 
       
Revenues (in thousands):       Revenues (in thousands):
NaHS revenues$33,702
 $37,054
 $105,209
 $103,680
NaHS revenues, excluding non-cash revenuesNaHS revenues, excluding non-cash revenues$30,134 $23,326 $60,270 $56,517 
NaOH (caustic soda) revenues11,145
 9,872
 29,511
 28,816
NaOH (caustic soda) revenues9,799 8,644 18,206 16,085 
Revenues associated with Alkali Business65,554
 —
 65,554
 —
Revenues associated with Alkali Business173,779 141,898 341,103 318,134 
Other revenues1,355
 1,143
 3,963
 3,941
Other revenues893 462 1,823 1,105 
Total external segment revenues$111,756
 $48,069
 $204,237
 $136,437
Total external segment revenues, excluding non-cash revenues(1)
Total external segment revenues, excluding non-cash revenues(1)
$214,605 $174,330 $421,402 $391,841 
       
Segment Margin (in thousands)$30,031
 $20,526
 $63,864
 $61,586
Segment Margin (in thousands)$38,194 $24,824 $81,914 $61,765 
       
Average index price for NaOH per DST (1)
$647
 $496
 $613
 $453
Average index price for NaOH per DST(2)
Average index price for NaOH per DST(2)
$755 $698 $702 $673 
(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 SeptemberJune 30, 20172021 Compared with Three Months Ended SeptemberJune 30, 20162020
Sodium minerals and sulfur services Segment Margin for the 20172021 Quarter increased $9.5$13.4 million, or 46%54%. This increase is principallyprimarily due to the inclusion of one month's contribution from thehigher soda ash volumes and favorable export pricing in our Alkali Business. This was partially offset by the results ofBusiness and higher NaHS sales volumes in our refinery services business during the 2021 Quarter. During the 2020 Quarter, volume demand in our Alkali Business was significantly impacted by the worldwide economic shutdowns and related NaHSuncertainty from the Covid-19 pandemic. As economies have continued to open up and caustic sodareduce restrictions, we have seen demand recovery, both domestically and internationally through ANSAC. We continued to produce at a high rate at our Westvaco facility during the 2021 Quarter, despite a short halt in production for our long-wall move and certain other planned maintenance activities. The 2017Additionally, we saw slightly favorable export pricing in the 2021 Quarter results for these activitiesrelative to the 2020 Quarter and sequentially from the first quarter of 2021, which is evidence that the supply and demand balance is becoming more balanced. These increases were in linepartially offset by lower domestic pricing and lower sales volumes associated with our expectationsGranger facility, as it was put in cold standby during the second half of 2020. Our Granger facility is expected to come back online during the second half of 2023 upon the completion of the GOP. In our refinery services business, we reported higher NaHS volumes in the 2021 Quarter due to improved volume demand from our domestic pulp and includepaper customer base that was negatively impacted in 2020 as a result of the effectstiming of previously disclosed commercial discussions with certain of our host refineriesspring turnarounds and several NaHS customers, which resulted in extendingoutages due to the term and tenor of a large number of contractual relationships.Covid-19 pandemic.
NineSix Months Ended SeptemberJune 30, 20172021 Compared with NineSix Months Ended SeptemberJune 30, 20162020
Sodium minerals and sulfur services Segment Margin for the first ninesix months of 20172021 increased $2.3$20.1 million, or 4%.33%, from the first six months of 2020. This increase is principallyprimarily due to higher soda ash volumes and more favorable export pricing in our Alkali Business and higher NaHS sales volumes in our refinery services business during 2021. During the 2020 Quarter, volume demand in our Alkali Business was significantly impacted by the worldwide economic shutdowns and uncertainty from the Covid-19 pandemic. As economies have continued to open up and reduce restrictions, we have seen demand recovery, both
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domestically and internationally through ANSAC, and continued to produce at a high rate at our Westvaco facility during 2021. Additionally, relative to 2020, we benefited from slightly favorable export pricing in 2021. These increases were partially offset by lower domestic pricing and lower sales volumes associated with our Granger facility, as it was put in cold standby during the second half of 2020. Our Granger facility is expected to come back online during the second half of 2023 upon the completion of the GOP. In our refinery services business, we reported higher NaHS volumes in 2021 primarily due to improved demand from our domestic pulp and paper customer base that was negatively impacted in 2020 as a result of the timing of spring turnarounds and outages due to the inclusion of one month's contribution from the Alkali Business.Covid-19 pandemic. This was partially offset by the results oflower demand from our refinery services business and related NaHS and caustic soda activities. The nine months ended September 30, 2017 results for these activities weremining customers, primarily 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.Peru.

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 and rail facilities and 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 from natural and anthropogenic sources to crude oil fields owned by our customers;
•shipping crude oil and refined products to and from producers and refiners via trucks, pipelines, and railcars;
loading and •unloading railcars at our crude-by-rail terminals;
•storing and blending of crude oil and intermediate and finished refined products;
•purchasing/selling and/or transporting crude oil from the wellhead to markets for ultimate use in refining; and
•purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets.
We also use our terminal facilities to take advantage of contango market conditions, to gather and market crude oil, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products. 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.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills and assets to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.
In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.


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Operating results from our onshore facilities and transportation segment were as follows:
Three Months Ended
September 30,		 Nine Months Ended
September 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2017 2016 2017 2016 2021202020212020
(in thousands) (in thousands) (in thousands)(in thousands)
Gathering, marketing, and logistics revenue$229,002
 $255,324
 $663,988
 $701,688
Gathering, marketing, and logistics revenue$136,148 $59,830 $314,710 $195,137 
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines17,261
 13,219
 48,606
 44,773
Payments received under direct financing leases not included in income1,751
 1,586
 5,127
 4,645
Crude oil and CO2 pipeline tariffs and revenuesCrude oil and CO2 pipeline tariffs and revenues8,902 14,145 18,877 34,006 
Distributions from unrestricted subsidiaries not included in income (1)
Distributions from unrestricted subsidiaries not included in income (1)
17,500 2,294 35,000 4,532 
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions(202,157) (230,760) (583,123) (621,500)Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions(124,383)(42,783)(286,367)(154,277)
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 expensesOperating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses(15,431)(17,877)(30,697)(36,370)
Other948
 782
 2,200
 5,752
Other(368)5,606 (8,156)6,286 
Segment Margin$25,606
 $17,560
 $71,999
 $63,969
Segment Margin$22,368 $21,215 $43,367 $49,314 
       
Volumetric Data (average barrels per day):       
Volumetric Data (average barrels per day unless otherwise noted):Volumetric Data (average barrels per day unless otherwise noted):
Onshore crude oil pipelines:       Onshore crude oil pipelines:
Texas45,329
 11,529
 28,418
 41,708
Texas84,551 62,261 58,800 73,380 
Jay13,716
 15,119
 14,480
 14,494
Jay7,933 5,067 8,356 7,540 
Mississippi8,104
 9,503
 8,478
 10,607
Mississippi5,327 4,883 5,213 5,646 
Louisiana (1)
130,862
 30,814
 115,436
 26,865
Wyoming22,204
 9,772
 19,816
 10,003
Louisiana (2)
Louisiana (2)
46,319 33,032 54,821 83,635 
Onshore crude oil pipelines total220,215
 76,737
 186,628
 103,677
Onshore crude oil pipelines total144,130 105,243 127,190 170,201 
       
CO2 pipeline (average Mcf/day):
       
CO2 pipeline (average Mcf/day):
Free State68,363
 88,026
 73,042
 101,157
Free State (3)
Free State (3)
— 94,282 — 114,558 
       
Crude oil and petroleum products sales:       Crude oil and petroleum products sales:
Total crude oil and petroleum products sales52,082
 64,292
 49,255
 66,725
Total crude oil and petroleum products sales20,653 21,874 26,028 23,996 
Rail load/unload volumes (2)
42,221
 13,091
 55,010
 13,344
Rail unload volumesRail unload volumes3,556 4,150 21,803 49,095 
(1) The three and six months ended June 30, 2021 include cash payments received from our previously owned NEJD pipeline of $17.5 million and $35.0 million not included in income, respectively. The three and six months ended June 30, 2020 includes cash payments received from the NEJD pipeline of $5.2 million and $10.3 million, respectively, of which $2.3 million and $4.5 million, respectively, were not included in income.
(2) Total daily volume for the three months and ninesix months ended SeptemberJune 30, 20172021 includes 66,04839,875 and 54,97432,397 barrels per day respectively of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines which became operational inpipelines. Total daily volume for the three and six months ended June 30, 2020 includes 28,851 and 36,586 barrels per day of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
(3) The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020.
Three Months Ended June 30, 2021 Compared with Three Months Ended June 30, 2020
    Onshore facilities and transportation Segment Margin for the 2021 Quarter increased $1.2 million, or 5%. This increase is primarily due to higher cash receipts received during the 2021 Quarter from Denbury of approximately $12.3 million associated with our previously owned NEJD pipeline as a result of our agreement reached during the fourth quarter of 2016. Additionally, this includes 19,574 and 6,925 barrels per day for the three months and nine months ended September 30, 2017 respectively of crude oil2020. This increase was partially offset by: (i) lower contracted minimum volume commitments with our main customer associated with our new Raceland PipelineBaton Rouge corridor assets (including rail, terminal and pipeline volumes), as these commitments stepped down beginning in 2021, and the use of built up prepaid transportation credits during the 2021 Quarter by our main customer; and (ii) the divestiture of our Free State pipeline during the fourth quarter of 2020, which became fully operationalcontributed positively to Segment Margin in the second quarter of 2017.2020 Quarter.
(2) Indicates total barrels for either loading or unloading at all rail facilities.
ThreeSix Months Ended SeptemberJune 30, 20172021 Compared with ThreeSix Months Ended SeptemberJune 30, 20162020
    Onshore facilities and transportation Segment Margin for our onshore facilities and transportation segment increased by $8.0the first six months of 2021 decreased $5.9 million, or 46%12%, betweenfrom the two three month periods. In the 2017 Quarter, this increase isfirst six months of 2020. This decrease was primarily attributabledue to the ramp up in volumes on our pipeline,lower rail unload and terminal infrastructure on our recently completed infrastructure in the Baton Rouge corridor. In addition, relative to the 2016 Quarter, we experienced an increase in volumes on our Texas pipeline system as the repurposing of our Houston area crude oil pipeline volumes associated with our Baton Rouge corridor assets, in addition to our customer utilizing certain of its prepaid transportation credits that accumulated during 2020, and expansionthe divestiture of our terminal infrastructure became operational inFree State pipeline during the secondfourth quarter of 2017.2020, which contributed
Nine Months Ended September 30, 2017 Compared with Nine Months Ended September 30, 2016
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positively to Segment Margin for our onshore facilities and transportation segment increased by $8.0 million, or 13%, betweenduring the first ninesix 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 principallyended June 30, 2020. These decreases were partially offset by lower demand for our services in our historical back-to-back, or buy/sell, crude oil marketing businesshigher cash receipts received during the six months ended June 30, 2021 from Denbury of approximately $24.7 million associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. In addition, the first nine months of 2017 were negatively impacted by lower volumes on our Texaspreviously owned NEJD pipeline system, as the repurposinga result of our Houston area crude oil pipeline and expansion of our terminal infrastructure did not became operational untilagreement reached during the secondfourth quarter of 2017 while the first nine months of 2016 included historical volumes on our legacy Texas pipeline system assets prior to the repurposing project for the majority of the period.2020.

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 3.03.2 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
June 30,		Six Months Ended
June 30,
 2021202020212020
Revenues (in thousands):
Inland freight revenues$18,231 $25,805 $35,746 $53,377 
Offshore freight revenues16,504 22,268 31,030 43,359 
Other rebill revenues (1)
12,891 8,647 21,181 22,330 
Total segment revenues$47,626 $56,720 $87,957 $119,066 
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (in thousands)$39,158 $38,582 $72,380 $81,926 
Segment Margin (in thousands)$8,468 $18,138 $15,577 $37,140 
Fleet Utilization: (2)
Inland Barge Utilization81.2 %87.6 %76.6 %90.5 %
Offshore Barge Utilization96.8 %96.8 %96.3 %98.1 %
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
Revenues (in thousands):       
Inland freight revenues$19,666
 $22,108
 $61,725
 $66,402
Offshore freight revenues17,468
 23,271
 54,912
 66,240
Other rebill revenues (1)
11,400
 9,906
 35,401
 27,288
Total segment revenues$48,534
 $55,285
 $152,038
 $159,930
        
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses$35,885
 $38,588
 $112,270
 $106,235
        
Segment Margin (in thousands)$12,649
 $16,697
 $39,768
 $53,695
        
Fleet Utilization: (2)
       
Inland Barge Utilization90.8% 87.6% 90.5% 91.4%
Offshore Barge Utilization99.3% 96.2% 98.4% 91.2%
(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 SeptemberJune 30, 20172021 Compared with Three Months Ended SeptemberJune 30, 20162020
Marine Transportationtransportation Segment Margin for the 20172021 Quarter decreased $4.0$9.7 million, or 24%53%, from the 20162020 Quarter. TheThis decrease in Segment Margin is primarily dueattributable to lower utilization and day rates onin our inland business during the 2021 Quarter and lower rates in our offshore fleets (which offset higher utilization as adjusted for planned dry docking time). Thebarge operation, including our M/T American Phoenix was also undergoing planned regulatory dry docking inspections for approximately one month duringtanker. During the 20172021 Quarter, which negatively impacted Segment Margin. In our inland fleet, weaker demandwe began to see sequential improvement in the offshore barge spot market pricing, but we expect to see continued to apply pressure on our utilization, and to an extent, the spot rates which we expect to continue into the fourth quarter. Inin our offshore barge fleet,inland business as a number of our units have come off longer term contracts, weMidwest and Gulf Coast refineries have continued to chooserun at lower utilization rates to primarily place them in spot service or short-termbetter align with overall demand as a result of Covid-19 and the current operating environment. We have continued to enter into short term contracts (less than a year) service, asin 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
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Six Months Ended SeptemberJune 30, 20172021 Compared with NineSix Months Ended SeptemberJune 30, 20162020
Marine transportation Segment Margin for the first ninesix months of 20172021 decreased $13.9$21.6 million, or 26%58%, from the first ninesix months of 2016. The2020. This decrease in Segment Margin is primarily dueattributable to lower utilization and day rates onin our inland business during the 2021 Quarter and lower rates in our offshore fleets (which offset higher utilization as adjusted for planned dry docking time). Thebarge operation, including our 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 demandtanker. We expect to see continued to apply pressure on our utilization, and to an extent, the spot rates which we expect to continue into the fourth quarter. Inin our offshore barge fleet,inland business as a number of our units have come off longer term contracts, weMidwest and Gulf Coast refineries have continued to chooserun at lower utilization rates to primarily place them in spot service or short-termbetter align with overall demand as a result of Covid-19 and the current operating environment. We have continued to enter into short term contracts (less than a year) service, asin both the inland and offshore markets because we continue to believe the day rates currently being offered by the market arehave yet to fully recover from their cyclical lows. We also re-contracted our M/T American Phoenix tanker beginning in the 2021 Quarter for one year, but at or approaching, cyclical lows.a lower rate than our previous long-term contract that ended during the second half of 2020.


Other Costs, Interest, and Income Taxes
General and administrative expenses
Three Months Ended
September 30,		 Nine Months Ended
September 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2017 2016 2017 2016 2021202020212020
(in thousands) (in thousands) (in thousands)(in thousands)
General and administrative expenses not separately identified below:       General and administrative expenses not separately identified below:
Corporate$7,456
 $7,692
 $24,735
 $26,068
Corporate$10,368 $23,364 $19,789 $34,157 
Segment3,233
 1,918
 4,809
 3,364
Segment1,036 1,073 2,087 2,138 
Equity-based compensation plan expense(1,875) 1,239
 (2,330) 3,918
Long-term incentive compensation expenseLong-term incentive compensation expense882 955 1,962 (1,530)
Third party costs related to business development activities and growth projects10,595
 363
 11,509
 1,366
Third party costs related to business development activities and growth projects621 21 735 21 
Total general and administrative expenses$19,409
 $11,212
 $38,723
 $34,716
Total general and administrative expenses$12,907 $25,413 $24,573 $34,786 
Three Months Ended June 30, 2021 Compared with Three Months Ended June 30, 2020
Total general and administrative expenses increased $8.2 million and $4.0 million betweenfor the three and nine month periods2021 Quarter decreased by $12.5 million. This decrease is primarily attributabledue to the third party financing, legal2020 Quarter including a one-time charge of approximately $13 million related to certain severance and accounting costs surrounding our acquisitionrestructuring expenses.
Six Months Ended June 30, 2021 Compared with Six Months Ended June 30, 2020
Total general and administrative expenses for the first six months of 2021 decreased by $10.2 million primarily due to the Alkali Business in the 2017 Quarter.2020 Quarter including a one-time charge of approximately $13 million related to certain severance and restructuring expenses. This was partially offset by the effectshigher long-term incentive compensation expense as a result of changes in assumptions used to value our equity based compensationoutstanding awards that are tied to our unit price.between the two periods.

Depreciation, depletion, and amortization expense
Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
 (in thousands)(in thousands)
Depreciation and depletion expense$64,852 $75,930 $128,466 $146,135 
Amortization expense2,689 4,190 5,361 8,342 
Total depreciation, depletion and amortization expense$67,541 $80,120 $133,827 $154,477 

Three Months Ended June 30, 2021 Compared with Three Months Ended June 30, 2020
    Total depreciation, depletion, and amortization expense for the 2021 Quarter decreased by $12.6 million. This decrease is primarily due to lower depreciation expense associated with our rail logistics assets in the 2021 Quarter as they were impaired during the second quarter of 2020. Additionally, our contract intangible associated with the M/T American Phoenix became fully amortized on September 30, 2020, which resulted in lower amortization expense in the 2021 Quarter.
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 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
 (in thousands) (in thousands)
Depreciation and depletion expense$57,498
 $46,909
 $157,819
 $135,428
Amortization of intangible assets5,879
 6,122
 17,623
 18,154
Amortization of CO2 volumetric production payments
355
 1,234
 1,011
 3,218
Total depreciation, depletion and amortization expense$63,732
 $54,265
 $176,453
 $156,800

Six Months Ended June 30, 2021 Compared with Six Months Ended June 30, 2020
Total depreciation, depletion, and amortization expense increased $9.5for the first six months of 2021 decreased by $20.7 million and $19.7 million betweendue to lower depreciation expense associated with our rail logistics assets in 2021 as they were impaired during the second quarter of 2020. Additionally, our contract intangible associated with the M/T American Phoenix became fully amortized on September 30, 2020, which resulted in lower amortization expense in the 2021 Quarter.
Impairment Expense
During the three and nine month periods primarily as a resultsix months ended June 30, 2020, we recorded impairment expenses of placing additional$277.5 million associated with the rail logistics assets into service, including those acquired as a part of the Alkali Business in the 2017 Quarter.included within our onshore facilities and transportation segment. We had no impairment expense during 2021.

Interest expense, net
Three Months Ended
June 30,		Six Months Ended
June 30,
 2021202020212020
 (in thousands)(in thousands)
Interest expense, senior secured credit facility (including commitment fees)$5,812 $9,664 $13,243 $20,409 
Interest expense, senior unsecured notes51,859 40,202 100,194 82,560 
Amortization of debt issuance costs and premium2,255 2,200 4,970 4,591 
Capitalized interest(757)(448)(1,409)(977)
Net interest expense$59,169 $51,618 $116,998 $106,583 
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2017 2016 2017 2016
 (in thousands) (in thousands)
Interest expense, senior secured credit facility (including commitment fees)$13,150
 $11,076
 $37,307
 $31,117
Interest expense, senior unsecured notes33,276
 28,609
 90,495
 85,828
Amortization of debt issuance costs and discount2,894
 2,571
 8,154
 7,563
Capitalized interest(1,932) (7,521) (13,839) (19,851)
Net interest expense$47,388
 $34,735
 $122,117
 $104,657

Three Months Ended June 30, 2021 Compared with Three Months Ended June 30, 2020
Net interest expense for the 2021 Quarter increased $12.7$7.6 million and $17.5 million between the three and nine month periods primarily due to increased interest expense associated with our senior unsecured notes. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest at 8.00% and we purchased and extinguished the remaining principal balance of our 6.00% 2023 Notes on January 19, 2021. On April 22, 2021, we issued an additional $250 million in aggregate principal amount of notes under the same terms as our 2027 Notes. The excess proceeds received from the issuance of our 2027 Notes were used to repay borrowings on our revolving credit facility.
The increase in interest expense on our averagesenior unsecured notes was partially offset by lower interest expense on our senior secured credit facility. The decrease in interest expense on our senior secured credit facility was primarily due to a lower outstanding indebtedness from acquiredbalance during the 2021 Quarter.
Six Months Ended June 30, 2021 Compared with Six Months Ended June 30, 2020
Net interest expense for the first six months of 2021 increased by $10.4 million primarily due to increased interest expense associated with our senior unsecured notes. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75% and constructed assets, includingwe purchased and extinguished our $750 million 2022 notes that accrued interest at 6.75% during 2020. On December 17, 2020, we issued our $750 million 2027 Notes that accrue interest at 8.00% and we purchased and extinguished the financing of the acquisition of the Alkali Business from Tronox in the 2017 Quarter. In addition, capitalized interest decreased as result of certainremaining principal balance of our large organic growth projects being completed and placed into service6.00% 2023 Notes on January 19, 2021. On April 22, 2021, we issued an additional $250 million in aggregate principal amount of notes under the same terms as our 2027 Notes. The excess proceeds received from the issuance of our 2027 Notes were used to repay borrowings on our revolving credit facility.
The increase in interest expenses on our senior unsecured notes was partially offset by lower interest expense on our senior secured credit facility. The decrease in interest expense on our senior secured credit facility was primarily due to a lower outstanding balance during previous quarters in 2017.2021.
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
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Table 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.Contents
Liquidity and Capital Resources
General
On April 8, 2021, we entered into our new credit agreement to replace our existing agreement. Our new credit agreement provides for a $950 million senior secured credit facility, comprised of our Revolving Loan facility with a borrowing capacity of $650 million and our Term Loan facility with a borrowing capacity of $300 million, with the ability to increase the aggregate size of the revolving loan facility by an additional $200 million subject to lender consent and certain other customary conditions. The new credit agreement matures on March 15, 2024, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions. Under our new credit agreement, the permitted maximum consolidated leverage ratio is 5.85x through June 30, 2021, 5.75x through March 31, 2022, and then 5.50x thereafter. The permitted maximum consolidated senior secured leverage ratio is 2.50x, and the minimum interest coverage ratio is 2.50x for the full term of the agreement.
On December 17, 2020, we issued $750 million 2027 Notes that accrue interest at 8.00%. We used the net proceeds to repay a portion of our 6.00% 2023 Notes that were validly tendered and we redeemed the remaining principal balance of $80.9 million on our 6.00% 2023 Notes on January 19, 2021. The excess proceeds received from this offering were used to repay borrowings on our revolving credit facility. Furthermore, on April 22, 2021 we completed our offering of an additional $250 million in aggregate principal amount of our 2027 Notes. The additional $250 million of notes have identical terms (other than with respect to issue price) and constitute part of the same series of our 2027 Notes. The $250 million of the 2027 Notes were issued at a premium of 103.75%, plus accrued interest from December 17, 2020. The net proceeds from this additional offering were used for general partnership purposes, including to pay down the outstanding borrowings on our Revolving Loan.
The successful completion of our new credit agreement (including its extended maturity and leverage flexibility) and the refinancing of our previously held 2023 Notes has resulted in no scheduled maturities of long-term debt until 2024, other than the minimal quarterly payments due under the associated term loan facility each quarter beginning at the end of 2021 (which will be funded by the available capacity under our revolving loan facility).
As of SeptemberJune 30, 2017, we had $314.72021, our balance sheet and liquidity position remained strong, which included $530.5 million of remaining borrowing capacity, subject to compliance with covenants, under our $1.7 billionnew $950 million senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our new credit facilityagreement 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 prior credit facility and the proceeds from issuances of equity and senior unsecured notes.
Our primary cash requirements consist of:
•working capital, primarily inventories, payables and trade receivables and payables;accrued liabilities;
•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 capitalnecessary funds on satisfactory terms or implement our growth strategy successfully.
At SeptemberJune 30, 2017,2021, our long-term debt totaled $4 billion, consistingapproximately $3,343.2 million, which is a reduction of $1.4 billion$50.6 million sequentially from December 31, 2020, and consisted of $415.7 million outstanding under our senior secured credit facility, net (including $39$19.6 million borrowed under the inventory sublimit tranche) and $2.4 billion$2,927.5 million of senior unsecured notes, net. Our senior unsecured notes, net balance is comprised of $350 million carrying amount due on February 15, 2021, $400 million carrying amount due on May 15, 2023, $350$338.6 million carrying amount due on June 15, 2024, $750 million carrying amount due August 1, 2022 and $550$529.8 million carrying amount due October 2025.2025, $356.0 million carrying amount due May 2026, $992.6 million carrying value due January 15, 2027, and $710.5 million carrying amount due February 1, 2028. We remain focused on continuing to reduce our leverage.
On August 14, 2017,September 23, 2019, we issued $550announced the 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 1preferred units of each year with the initial interest payment due April 1, 2018. That issuance generated netAlkali Holdings. The proceeds of $540.1 million, net of issuance costs incurred. The net proceeds were usedreceived from GSO will fund up to fund a portion100% of the purchase price for our acquisitionanticipated cost of the Alkali Business.

In July 2017,GOP. On April 14, 2020, we amendedentered into an amendment to our credit agreementagreements with GSO to, among other things, make certain technical amendments related toextend the financing of our acquisitionconstruction timeline of the Alkali Business.
On March 24, 2017,GOP by one year. The extended completion date of the project is anticipated in the second half of 2023. In consideration for the amendment, we issued 4,600,000 Class A common1,750 Alkali Holdings preferred units to
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GSO, which was accounted for as issuance costs. Additionally, the total commitment of GSO was increased to, subject to compliance with the covenants contained in a public offering at a price of $30.65 per unit, which included the exercise by the underwriters of an option to purchaseagreements with GSO, 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 million of Class A convertible$351,750,000 preferred units (or 351,750 preferred units) in a private placement, comprisedAlkali Holdings. The Alkali Holdings preferred unitholders receive PIK distributions in lieu of 22,249,494 units for a cash purchase pricedistributions during the new anticipated construction period. 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.year.
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, weShelf Registration Statement
    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.
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.
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.
Equity Distribution Program and Shelf Registration Statements
We expectability 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. In connection with implementing our equity distribution program, we filedhave 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, we have issued no additional units under this program.

We have another universal shelf registration statement (our "2015"2021 Shelf") on file with the SEC.SEC which we filed on April 19, 2021 to replace our existing universal shelf registration statement that expired on April 20, 2021. Our 20152021 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 20152021 Shelf willis set to expire in April 2018. We expect to file a replacement universal shelf registration statement before our 2015 Shelf expires.2024.
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 purchaseacquire 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 buypurchase 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 months ended September 30, 20172021 Quarter and September 30, 2016.2020 Quarter.
Net cash flows provided by our operating activities for the Nine Months Ended Septembersix months ended June 30, 20172021 were $217.8$188.2 million compared to $228.4$152.2 million for the Nine Months Ended Septembersix months ended June 30, 2016.2020. This decrease in operating cash flowincrease is primarily dueattributable to an increasepositive changes in working capital needs.during 2021 and transactions costs incurred during 2020 associated with the tender and redemption of our previously held 2022 Notes.
Capital Expenditures, Distributions and Distributions Paid to our UnitholdersCertain 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

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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 months ended September 30, 20172021 and September 30, 2016 is2020 are as follows:
Six Months Ended
June 30,
 20212020
 (in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets$7,371 $2,097 
Sodium minerals and sulfur services assets16,032 12,051 
Marine transportation assets22,871 17,725 
Onshore facilities and transportation assets3,453 1,618 
Information technology systems190 99 
Total maintenance capital expenditures49,917 33,590 
Growth capital expenditures:
Offshore pipeline transportation assets23,578 913 
Sodium minerals and sulfur services assets74,566 36,386 
Marine transportation assets— — 
Onshore facilities and transportation assets133 368 
Information technology systems4,211 2,515 
Total growth capital expenditures102,488 40,182 
Total capital expenditures for fixed and intangible assets$152,405 $73,772 
 Nine Months Ended
September 30,
 2017 2016
 (in thousands)
Capital expenditures for fixed and intangible assets:   
Maintenance capital expenditures:   
Offshore pipeline transportation assets$4,093
 $1,198
Sodium minerals and sulfur services assets1,616
 1,645
Marine transportation assets17,439
 11,358
Onshore facilities and transportation assets3,213
 9,478
Information technology systems53
 404
Total maintenance capital expenditures26,414
 24,083
Growth capital expenditures:   
Offshore pipeline transportation assets$4,405
 $7,777
Sodium minerals and sulfur services assets5,276
 —
Marine transportation assets27,057
 51,570
Onshore facilities and transportation assets112,450
 249,203
Information technology systems114
 6,398
Total growth capital expenditures149,302
 314,948
Total capital expenditures for fixed and intangible assets175,716
 339,031
Capital expenditures for acquisitions, inclusive of working capital acquired:   
Acquisition of Alkali business1,325,000
 —
Acquisition of remaining interest in Deepwater Gateway (1)
—
 26,200
Total business combinations capital expenditures1,325,000
 26,200
Capital expenditures related to equity investees—
 —
Total capital expenditures$1,500,716
 $365,231
(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 GOP. We anticipate spendingentered into agreements with GSO for the purchase of up to approximately $45.0$350 million inclusive of capitalized interest, duringpreferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the remainderanticipated cost of 2017 for projects currently under construction. The most significant ofthe GOP. On April 14, 2020, we entered into an amendment to our recent projects are described below.
Baton Rouge Area Infrastructure Expansion
We are currently expanding our existing Baton Rouge area infrastructureagreements with GSO to, allow for greater capacity and flexibility in servicing our major refinery customer in the region. This expansion includesamong other things, extend the construction timeline of an additional 500,000 barrelsthe GOP by one year. The extended completion date of crude oil tankage at our existing Baton Rouge Terminal. Additionally, this expansion will include the upgrading of pumping and other infrastructure capabilities in order to allow for the efficient handling of expected increases in crude oil volumes received at our Baton Rouge area facilities. We expect these assets to become operational in the first quarter of 2018.
Houston Area Crude Oil Pipeline and Terminal Infrastructure
We have constructed new, and expanded existing, crude oil pipeline and terminal facilities in Webster, Texas and Texas City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We have also constructed a new crude oil pipeline that delivers crude oil received from upstream crude oil pipelines (including CHOPS, which delivers crude oil originating in the deepwater Gulf of Mexico to the Texas City area) to our new Texas City Terminal, which connects to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal includes approximately 750,000 barrels of crude oil tankage. As a part of this project we 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 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 operationalis anticipated in the second quarterhalf of 2017.2023. In consideration for the amendment, we issued 1,750 Alkali Holdings preferred units to GSO. As part of the amendment, the commitment period was increased to four years, and the total commitment of GSO was increased to, subject to compliance with the covenants contained in the agreements with GSO, up to $351,750,000 preferred units (or 351,750 preferred units) in Alkali Holdings. The Alkali Holdings preferred unitholders receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of June 30, 2021 we had issued 201,705 Alkali Holdings preferred units. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.
Raceland Terminal    Except for the GOP, we do not anticipate spending material growth capital expenditures on any individual projects during the rest of 2021.
Maintenance Capital Expenditures
Maintenance capital expenditures incurred during 2021 primarily relate to expenditures in our Alkali Business, our marine transportation segment, and Crude Oil Pipeline
We have constructed a new crude oil terminalin our offshore transportation segment. Our Alkali Business, which is included in our sodium minerals and pipeline in Raceland, Louisiana that connectssulfur services segment, incurs expenditures to existing midstream infrastructure to provide further distributionmaintain its equipment and facilities due to the Louisiana refining markets.nature of its operations. Our new Raceland Terminal consists of 515,000 barrels of crude oil tankagemarine transportation segment incurs expenditures as we frequently replace 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, toupgrade certain equipment associated with 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 bargesbarge and 18 new-build push boats forvessel fleet during our inland marine barge transportation fleet. We have accepted delivery of 23 of those bargesplanned 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 inunplanned dry-docks. Additionally, we incurred maintenance capital expenditures forin our offshore transportation segment to replace certain pipeline and platform equipment and complete the nine months ended September 30, 2017 Quarter as comparedinstallation of a bypass to allow our CHOPS pipeline to resume operations in 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.2021 Quarter. 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
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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,August 13, 2021, 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, 2017.2021 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, 2017August 13, 2021 to unitholders holders of record at the close of business on November 3, 2017.July 30, 2021.
Guarantor Summarized Financial Information
Our $2.9 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% Guarantor Subsidiaries. The assets owned by Genesis Free State Pipeline, LLC were sold on October 30, 2020 and the ownership of Genesis NEJD Pipeline LLC's pipeline was transferred in October 2020. 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 SheetsGenesis Energy, L.P. and Guarantor Subsidiaries
June 30, 2021December 31, 2020
ASSETS:
Current assets$368,126 $313,328 
Fixed assets, net3,082,195 3,115,492 
Non-current assets826,504 861,230 
LIABILITIES AND CAPITAL:(1)
Current liabilities381,264 266,688 
Non-current liabilities3,694,962 3,710,044 
Class A Convertible Preferred Units790,115 790,115 
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Statements of OperationsGenesis Energy, L.P. and Guarantor Subsidiaries
Six Months Ended
June 30, 2021		Twelve Months Ended
December 31. 2020
Revenues$679,668 $1,156,428 
Operating costs644,271 1,421,674 
Operating income (loss)35,397 (265,246)
Loss before income taxes(82,629)(408,717)
Net loss(1)
(83,366)(409,951)
Less: Accumulated distributions to Class A Convertible Preferred Units(37,368)(74,736)
Net loss available to common unitholders(120,734)(484,687)
(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 $63.2 million and $95.7 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the Non-Guarantor Subsidiaries as of June 30, 2021 and December 31, 2020, respectively.
Non-GAAP Financial Measure Reconciliations
For definitions and discussion of our Non-GAAP financial measures refer to the "Non-GAAP Financial Measures" as later discussed and defined.
Available Cash before Reserves for the periods presented below was as follows:
 Three Months Ended
June 30,
 20212020
(in thousands)
Net loss attributable to Genesis Energy, L.P.$(41,682)$(326,714)
Income tax expense525 795 
Depreciation, depletion, amortization and accretion69,684 82,580 
Impairment expense— 277,495 
Plus (minus) Select Items, net47,440 40,809 
Maintenance capital utilized (1)
(13,300)(9,900)
Cash tax expense(195)(150)
Distributions to preferred unitholders(18,684)(18,684)
Redeemable noncontrolling interest redemption value adjustments (2)
5,766 4,159 
Available Cash before Reserves$49,554 $50,390 
(1)For a description of the term "maintenance capital utilized", please see the definition of the term "Available Cash before Reserves" discussed below. Maintenance capital expenditures in the 2021 Quarter and 2020 Quarter were $23.8 million and $13.0 million, respectively.
(2)Includes PIK distributions attributable to the period 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.
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 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 accretion66,436
 57,103
Cash received from direct financing leases not included in income1,751
 1,586
Cash effects of sales of certain assets967
 120
Effects of distributable cash generated by equity method investees not included in income7,136
 9,063
Expenses related to acquiring or constructing growth capital assets10,595
 363
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value2,168
 (571)
Maintenance capital utilized (1)
(3,375) (1,885)
Non-cash tax expense150
 649
Differences in timing of cash receipts for certain contractual arrangements (2)
(5,847) (3,624)
Other items, net5,514
 107
Available Cash before Reserves91,807
 95,012
(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.

 Three Months Ended
June 30,
 20212020
 (in thousands)
I.Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements (1)
$6,446 $11,638 
Distribution from unrestricted subsidiaries not included in income (2)
17,500 2,294 
Certain non-cash items:
Unrealized losses on derivative transactions excluding fair value hedges, net of changes in inventory value (3)
14,750 21,108 
Adjustment regarding equity investees (4)
7,692 5,776 
Other(67)2,183 
             Sub-total Select Items, net46,321 42,999 
II.Applicable only to Available Cash before Reserves
Certain transaction costs (5)
621 21 
Other498 (2,211)
Total Select Items, net (6)
$47,440 $40,809 
(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.
 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 sales967
 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 flows4,194
 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 expense3,566
 (2,047)
   Expenses related to acquiring or constructing assets that provide new sources of cash flow10,595
 363
   Differences in timing of cash receipts for certain contractual arrangements (2)
(5,847) (3,624)
   Other items, net16,190
 1,964
Available Cash before Reserves91,807
 95,012
(2) The 2021 Quarter includes $17.5 million in cash receipts associated with principal repayments on our previously owned NEJD pipeline not included in income. The 2020 Quarter includes cash payments received from the NEJD pipeline of $2.3 million not included in income. Genesis NEJD Pipeline, LLC is defined as an unrestricted subsidiary under our credit facility.

(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.

(3) The 2021 Quarter includes a $14.3 million unrealized loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and the 2020 Quarter includes a $21.8 million unrealized loss from the valuation of the embedded derivative.

(4) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.

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

(6) Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
Non- GAAP
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-GAAPnon-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 incomeloss 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
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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 expenseplus 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 incomeloss 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, alsooften 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)
(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.
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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 to 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 forother than the year ended December 31, 2016additional $250 million issuance of our 2027 Notes and our new credit agreement (including its extended maturity), which are discussed in further detail in Note 9.

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, the impact of our cost saving measures and the amount of such cost savings, 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, and caustic soda, and CO2, all of which may be affected by
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economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, pandemics (including Covid-19), the actions of OPEC and other oil exporting nations, conservation and technological advances;
•our ability to successfully execute our business and financial strategies;
•our ability to realize cost savings from our recent cost saving measures;
•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 suchsoda 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 (common and preferred) 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;
•reduction in demand for our services resulting in impairments of our assets;
•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
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•the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.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.
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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’sSEC's rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this Quarterly Report on Form 10-Q is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.
There were no changes during the third quarter of 20172021 Quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 20162020 (the "Annual Report"). There have been no material developments in legal proceedings since the filing of such Form 10-K.
Item 1A. Risk Factors
There has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, except as supplemented by our quarterly Reports on Form 10-Q and Current Reports on Form 8-K and Form 8-K/A.2020.
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 other risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
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, 2017.2021 Quarter.

Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Information regarding mine safety and other regulatory action at our minemines in Green River and Granger, Wyoming is includingincluded in Exhibit 95 to this Form 10-Q.

Item 5. Other Information
None.
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Item 6. Exhibits.
(a) Exhibits
2.13.1
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).
3.1Certificate 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
3.3
3.4
3.5
3.6

3.7
3.6
3.73.8
4.13.9
3.10
4.1
*4.2
*4.3
*4.322.1

*10.131.1
10.2
Sixth Amendment to the Fourth Amended and Restated Credit Agreement, dated July 28, 2017, among Genesis Energy, L.P., as borrower, Wells Fargo Bank National Association, as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated August 7, 2017, File No. 001-12295).

10.3
Board Observer 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 10.1 to the Company’s Current Report on Form 8-K filed on September 7, 2017, File No. 001-12295).

*31.1
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2
*32
*95
*101.INS XBRL Instance DocumentDocument- 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 DocumentDocument.
*101.CAL XBRL Calculation Linkbase DocumentDocument.
*101.LAB XBRL Label Linkbase DocumentDocument.
*101.PRE XBRL Presentation Linkbase DocumentDocument.
*101.DEF XBRL Definition Linkbase DocumentDocument.
104Cover Page Interactive Data File (formatted as Inline XBRL).
*Filed herewith
56

Table of Contents
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, L.P.
(A Delaware Limited Partnership)
By:
GENESIS ENERGY, LLC,

as General Partner
 
Date:November 3, 2017August 4, 2021By:
/s/ ROBERT V. DEERE
Robert V. Deere
Chief Financial Officer
(Duly Authorized Officer)



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