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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
Form 10-Q 

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 20192020
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.)
Delaware76-0513049
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
919 Milam, Suite 2100,
Houston,TX77002
(Address of principal executive offices)(Zip code)
Registrant’s telephone number, including area code:(713)(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 every Interactive Data File required to be submitted 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 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  ☐
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
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 the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 122,539,221 Class A Common Units and 39,997 Class B Common Units outstanding as of August 6, 2019.5, 2020.



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GENESIS ENERGY, L.P.
TABLE OF CONTENTS
 

Page
PART I. FINANCIAL INFORMATION
Item 1.
3
3
4
5
6
7
8
 1. Organization and Basis of Presentation and Consolidation
8
 2. Recent Accounting Developments
89
 3. Revenue Recognition
9
 4. Lease Accounting
11
 5. Inventories
1412
 6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations
1513
 7. Equity Investees
1614
 8. Intangible Assets
1715
 9. Debt
1816
 10. Partners' Capital, Mezzanine Capital and Distributions
1917
 11. Net Income (Loss) Per Common Unit
20
 12. Business Segment Information
21
 13. Transactions with Related Parties
2324
 14. Supplemental Cash Flow Information
2526
 15. Derivatives
2526
 16. Fair-Value Measurements
2829
 17. Commitments and Contingencies
3031
Item 2.
30
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
3932
Item 3.
55
Item 4.
5655
PART II. OTHER INFORMATION
Item 1.
5756
Item 1A.
5756
Item 2.
5756
Item 3.
5756
Item 4.
5756
Item 5.
5756
Item 6.
5857
5958

2
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except units)
 
June 30, 2019 December 31, 2018June 30, 2020December 31, 2019
ASSETS   ASSETS
CURRENT ASSETS:   CURRENT ASSETS:
Cash and cash equivalents$9,579
 $10,300
Cash and cash equivalents$28,020  $29,128  
Restricted cashRestricted cash17,481  27,277  
Accounts receivable - trade, net297,847
 323,462
Accounts receivable - trade, net238,300  417,002  
Inventories84,094
 73,531
Inventories109,531  65,137  
Other44,877
 35,986
Other79,458  54,530  
Total current assets436,397
 443,279
Total current assets472,790  593,074  
FIXED ASSETS, at cost5,505,360
 5,440,858
FIXED ASSETS, at cost5,188,913  5,540,596  
Less: Accumulated depreciation(1,160,353) (1,023,825)Less: Accumulated depreciation(1,238,006) (1,246,121) 
Net fixed assets4,345,007
 4,417,033
Net fixed assets3,950,907  4,294,475  
MINERAL LEASEHOLDS, net of accumulated depletion558,197
 560,481
MINERAL LEASEHOLDS, net of accumulated depletion554,021  555,825  
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income112,428
 116,925
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income102,738  107,702  
EQUITY INVESTEES344,583
 355,085
EQUITY INVESTEES322,412  334,523  
INTANGIBLE ASSETS, net of amortization147,178
 162,602
INTANGIBLE ASSETS, net of amortization131,969  138,927  
GOODWILL301,959
 301,959
GOODWILL301,959  301,959  
RIGHT OF USE ASSETS, net191,497
 —
RIGHT OF USE ASSETS, net166,016  177,071  
OTHER ASSETS, net of amortization117,697
 121,707
OTHER ASSETS, net of amortization66,625  94,085  
TOTAL ASSETS$6,554,943
 $6,479,071
TOTAL ASSETS$6,069,437  $6,597,641  
LIABILITIES AND CAPITAL   LIABILITIES AND CAPITAL
CURRENT LIABILITIES:   CURRENT LIABILITIES:
Accounts payable - trade$132,026
 $127,327
Accounts payable - trade$118,606  $218,737  
Accrued liabilities220,975
 205,507
Accrued liabilities185,051  196,758  
Total current liabilities353,001
 332,834
Total current liabilities303,657  415,495  
SENIOR SECURED CREDIT FACILITY967,000
 970,100
SENIOR SECURED CREDIT FACILITY1,053,000  959,300  
SENIOR UNSECURED NOTES, net of debt issuance costs2,466,137
 2,462,363
SENIOR UNSECURED NOTES, net of debt issuance costs2,379,576  2,469,937  
DEFERRED TAX LIABILITIES12,911
 12,576
DEFERRED TAX LIABILITIES12,770  12,640  
OTHER LONG-TERM LIABILITIES397,690
 259,198
OTHER LONG-TERM LIABILITIES388,687  393,850  
Total liabilities4,196,739
 4,037,071
Total liabilities4,137,690  4,251,222  
   
MEZZANINE CAPITAL:   MEZZANINE CAPITAL:
Class A Convertible Preferred Units, 25,336,778 and 24,438,022 issued and outstanding at June 30, 2019 and December 31, 2018, respectively790,115
 761,466
Class A Convertible Preferred Units, 25,336,778 issued and outstanding at June 30, 2020 and December 31, 2019Class A Convertible Preferred Units, 25,336,778 issued and outstanding at June 30, 2020 and December 31, 2019790,115  790,115  
Redeemable noncontrolling interests, 131,750 and 130,000 preferred units issued and outstanding at June 30, 2020 and December 31, 2019, respectivelyRedeemable noncontrolling interests, 131,750 and 130,000 preferred units issued and outstanding at June 30, 2020 and December 31, 2019, respectively133,378  125,133  
   
PARTNERS’ CAPITAL:   PARTNERS’ CAPITAL:
Common unitholders, 122,579,218 units issued and outstanding at June 30, 2019 and December 31, 20181,575,599
 1,690,799
Accumulated other comprehensive income939
 939
Common unitholders, 122,579,218 units issued and outstanding at June 30, 2020 and December 31, 2019Common unitholders, 122,579,218 units issued and outstanding at June 30, 2020 and December 31, 20191,018,342  1,443,320  
Accumulated other comprehensive lossAccumulated other comprehensive loss(8,188) (8,431) 
Noncontrolling interests(8,449) (11,204)Noncontrolling interests(1,900) (3,718) 
Total partners' capital1,568,089
 1,680,534
Total partners' capital1,008,254  1,431,171  
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL$6,554,943
 $6,479,071
TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL$6,069,437  $6,597,641  
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
 
Three Months Ended
June 30,		 Six Months Ended
June 30,		 Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
REVENUES:       REVENUES:
Offshore pipeline transportation services$78,427
 $69,969
 $156,744
 $143,229
Offshore pipeline transportationOffshore pipeline transportation$64,964  $78,427  $143,393  $156,744  
Sodium minerals and sulfur services274,606
 298,881
 550,092
 584,791
Sodium minerals and sulfur services192,624  274,606  436,014  550,092  
Marine transportation58,706
 56,185
 115,356
 105,114
Marine transportation56,720  58,706  119,066  115,356  
Onshore facilities and transportation223,046
 327,353
 432,602
 645,062
Onshore facilities and transportation74,159  223,046  229,917  432,602  
Total revenues634,785
 752,388
 1,254,794
 1,478,196
Total revenues388,467  634,785  928,390  1,254,794  
COSTS AND EXPENSES:       COSTS AND EXPENSES:
Onshore facilities and transportation product costs167,050
 283,059
 335,155
 560,877
Onshore facilities and transportation product costs43,447  167,050  155,399  335,155  
Onshore facilities and transportation operating costs19,175
 23,046
 38,827
 45,341
Onshore facilities and transportation operating costs18,238  19,175  36,486  38,827  
Marine transportation operating costs44,836
 44,217
 88,569
 82,064
Marine transportation operating costs38,561  44,836  81,498  88,569  
Sodium minerals and sulfur services operating costs219,894
 232,517
 438,602
 456,015
Sodium minerals and sulfur services operating costs167,010  219,894  372,243  438,602  
Offshore pipeline transportation operating costs4,117
 17,440
 22,575
 35,780
Offshore pipeline transportation operating costs16,403  4,117  35,064  22,575  
General and administrative13,412
 13,529
 25,098
 25,203
General and administrative25,413  13,412  34,786  25,098  
Depreciation, depletion and amortization79,353
 77,680
 156,991
 152,935
Depreciation, depletion and amortization80,120  79,353  154,477  156,991  
Impairment expenseImpairment expense277,495  —  277,495  —  
Total costs and expenses547,837
 691,488
 1,105,817
 1,358,215
Total costs and expenses666,687  547,837  1,147,448  1,105,817  
OPERATING INCOME86,948
 60,900
 148,977
 119,981
OPERATING INCOME (LOSS)OPERATING INCOME (LOSS)(278,220) 86,948  (219,058) 148,977  
Equity in earnings of equity investees15,046
 8,324
 28,043
 18,896
Equity in earnings of equity investees12,618  15,046  26,777  28,043  
Interest expense(55,507) (57,909) (111,208) (114,045)Interest expense(51,618) (55,507) (106,583) (111,208) 
Other expense(4,692) (188) (7,668) (5,432)
Income before income taxes41,795
 11,127
 58,144
 19,400
Other income (expense)Other income (expense)(4,550) (4,692) 5,708  (7,668) 
Income (loss) before income taxesIncome (loss) before income taxes(321,770) 41,795  (293,156) 58,144  
Income tax expense(143) (256) (545) (631)Income tax expense(795) (143) (430) (545) 
NET INCOME41,652
 10,871
 57,599
 18,769
NET INCOME (LOSS)NET INCOME (LOSS)(322,565) 41,652  (293,586) 57,599  
Net loss (income) attributable to noncontrolling interests(1,532) 126
 (1,525) 262
Net loss (income) attributable to noncontrolling interests10  (1,532) 26  (1,525) 
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.$40,120
 $10,997
 $56,074
 $19,031
Net income attributable to redeemable noncontrolling interestsNet income attributable to redeemable noncontrolling interests(4,159) —  (8,245) —  
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P.$(326,714) $40,120  $(301,805) $56,074  
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684) (17,257) (37,099) (34,145)Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684) (18,684) (37,368) (37,099) 
NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS$21,436
 $(6,260) $18,975
 $(15,114)NET INCOME (LOSS) AVAILABLE TO COMMON UNITHOLDERS$(345,398) $21,436  $(339,173) $18,975  
NET INCOME (LOSS) PER COMMON UNIT (Note 11):       NET INCOME (LOSS) PER COMMON UNIT (Note 11):
Basic and Diluted$0.17
 $(0.05) $0.15
 $(0.12)Basic and Diluted$(2.82) $0.17  $(2.77) $0.15  
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:       WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted122,579
 122,579
 122,579
 122,579
Basic and Diluted122,579  122,579  122,579  122,579  
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.


4
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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Net income$41,652
 $10,871
 $57,599
 $18,769
Other comprehensive income:       
Change in benefit plan liability—
 —
 —
 —
Total Comprehensive income41,652
 10,871
 57,599
 18,769
Comprehensive (income) loss attributable to noncontrolling interests(1,532) 126
 (1,525) 262
Comprehensive income attributable to Genesis Energy, L.P.$40,120
 $10,997
 $56,074
 $19,031
Three Months Ended
June 30,		Six Months Ended
June 30,
2020201920202019
Net income (loss)$(322,565) $41,652  $(293,586) $57,599  
Other comprehensive income:
Amortization of prior service cost243  —  243  —  
Total Comprehensive income (loss)(322,322) 41,652  (293,343) 57,599  
Comprehensive loss (income) attributable to noncontrolling interests10  (1,532) 26  (1,525) 
Comprehensive income attributable to redeemable noncontrolling interests(4,159) —  (8,245) —  
Comprehensive income (loss) attributable to Genesis Energy, L.P.$(326,471) $40,120  $(301,562) $56,074  
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, 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 UnitsPartners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive IncomeTotal
Partners’ capital, March 31, 2019122,579  $1,621,314  $(10,601) $939  $1,611,652  
Net income—  40,120  1,532  —  41,652  
Cash distributions to partners—  (67,419) —  —  (67,419) 
Cash contributions from noncontrolling interests—  —  620  —  620  
Distributions to Class A Convertible Preferred unitholders—  (18,416) —  —  (18,416) 
Partners' capital, June 30, 2019122,579  $1,575,599  $(8,449) $939  $1,568,089  

 
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Income Total
Partners’ capital, March 31, 2019122,579
 $1,621,314
 $(10,601) $939
 $1,611,652
Net income—
 40,120
 1,532
 —
 41,652
Cash distributions to partners—
 (67,419) —
 —
 (67,419)
Cash contributions from noncontrolling interests—
 —
 620
 —
 620
Distributions to Class A Convertible Preferred unitholders—
 (18,416) —
 —
 (18,416)
Partners' capital, June 30, 2019122,579
 $1,575,599
 $(8,449) $939
 $1,568,089
 
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, March 31, 2018122,579
 $1,951,590
 $(7,815) $(604) $1,943,171
Net income—
 10,997
 (126) —
 10,871
Cash distributions to partners—
 (63,742) —
 —
 (63,742)
Cash contributions from noncontrolling interests—
 —
 920
 —
 920
Distributions to Class A Convertible Preferred unitholders—
 (16,888) —
 —
 (16,888)
Partners' capital, June 30, 2018122,579
 $1,881,957
 $(7,021) $(604) $1,874,332



Number of
Common Units		Partners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive
Loss		Total
Partners’ capital, January 1, 2020Partners’ capital, January 1, 2020122,579  $1,443,320  $(3,718) $(8,431) $1,431,171  
Net lossNet loss—  (301,805) (26) —  (301,831) 
Cash distributions to partnersCash distributions to partners—  (85,805) —  —  (85,805) 
Cash contributions from noncontrolling interestsCash contributions from noncontrolling interests—  —  1,844  —  1,844  
Other comprehensive incomeOther comprehensive income—  —  —  243  243  
Distributions to Class A Convertible Preferred unitholdersDistributions to Class A Convertible Preferred unitholders—  (37,368) —  —  (37,368) 
Partners' capital, June 30, 2020Partners' capital, June 30, 2020122,579  $1,018,342  $(1,900) $(8,188) $1,008,254  
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Income TotalNumber of
Common Units		Partners’ CapitalNoncontrolling InterestAccumulated Other Comprehensive IncomeTotal
Partners’ capital, January 1, 2019122,579
 $1,690,799
 $(11,204) $939
 $1,680,534
Partners’ capital, January 1, 2019122,579  $1,690,799  $(11,204) $939  $1,680,534  
Net income—
 56,074
 1,525
 —
 57,599
Net income—  56,074  1,525  —  57,599  
Cash distributions to partners—
 (134,838) —
 —
 (134,838)Cash distributions to partners—  (134,838) —  —  (134,838) 
Cash contributions from noncontrolling interests—
 —
 1,230
 —
 1,230
Cash contributions from noncontrolling interests—  —  1,230  —  1,230  
Distributions to Class A Convertible Preferred unitholders—
 (36,436) —
 —
 (36,436)Distributions to Class A Convertible Preferred unitholders—  (36,436) —  —  (36,436) 
Partners' capital, June 30, 2019122,579
 $1,575,599
 $(8,449) $939
 $1,568,089
Partners' capital, June 30, 2019122,579  $1,575,599  $(8,449) $939  $1,568,089  
Number of
Common Units
 Partners’ Capital Noncontrolling Interest Accumulated Other Comprehensive Loss Total
Partners’ capital, January 1, 2018122,579
 $2,022,597
 $(8,079) $(604) $2,013,914
Net income—
 19,031
 (262) —
 18,769
Cash distributions to partners—
 (126,257) —
 —
 (126,257)
Cash contributions from noncontrolling interests—
 —
 1,320
 —
 1,320
Distributions to Class A Convertible Preferred unitholders—
 (33,414) —
 —
 (33,414)
Partners' capital, June 30, 2018122,579
 $1,881,957
 $(7,021) $(604) $1,874,332
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Six Months Ended
June 30,		 Six Months Ended
June 30,
2019 2018 20202019
CASH FLOWS FROM OPERATING ACTIVITIES:   CASH FLOWS FROM OPERATING ACTIVITIES:
Net income$57,599
 $18,769
Net income (loss)Net income (loss)$(293,586) $57,599  
Adjustments to reconcile net income to net cash provided by operating activities -   Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion and amortization156,991
 152,935
Depreciation, depletion and amortization154,477  156,991  
Impairment expenseImpairment expense277,495  —  
Amortization and write-off of debt issuance costs and discount5,370
 6,820
Amortization and write-off of debt issuance costs and discount14,971  5,370  
Amortization of unearned income and initial direct costs on direct financing leases(6,227) (6,615)Amortization of unearned income and initial direct costs on direct financing leases(5,802) (6,227) 
Payments received under direct financing leases10,334
 10,334
Payments received under direct financing leases10,334  10,334  
Equity in earnings of investments in equity investees(28,043) (18,896)Equity in earnings of investments in equity investees(26,777) (28,043) 
Cash distributions of earnings of equity investees27,735
 20,162
Cash distributions of earnings of equity investees25,923  27,735  
Non-cash effect of long-term incentive compensation plans3,822
 1,662
Non-cash effect of long-term incentive compensation plans(3,647) 3,822  
Deferred and other tax liabilities335
 331
Deferred and other tax liabilities130  335  
Unrealized loss on derivative transactions13,304
 3,269
Unrealized (gains) losses on derivative transactionsUnrealized (gains) losses on derivative transactions(9,811) 13,304  
Cancellation of debt incomeCancellation of debt income(19,725) —  
Other, net(7,703) (3,800)Other, net8,662  (7,703) 
Net changes in components of operating assets and liabilities (Note 14)
(37,907) (34,155)
Net changes in components of operating assets and liabilities (Note 14)
19,518  (37,907) 
Net cash provided by operating activities195,610
 150,816
Net cash provided by operating activities152,162  195,610  
CASH FLOWS FROM INVESTING ACTIVITIES:   CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets(68,666) (110,970)Payments to acquire fixed and intangible assets(69,438) (68,666) 
Cash distributions received from equity investees - return of investment10,811
 17,828
Cash distributions received from equity investees - return of investment13,036  10,811  
Investments in equity investees—
 (395)
Proceeds from asset sales861
 1,192
Proceeds from asset sales304  861  
Net cash used in investing activities(56,994) (92,345)Net cash used in investing activities(56,098) (56,994) 
CASH FLOWS FROM FINANCING ACTIVITIES:   CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility387,000
 543,100
Borrowings on senior secured credit facility684,500  387,000  
Repayments on senior secured credit facility(390,100) (336,000)Repayments on senior secured credit facility(590,800) (390,100) 
Proceeds from issuance of senior unsecured notes due 2028Proceeds from issuance of senior unsecured notes due 2028750,000  —  
Repayment of senior unsecured notes—
 (145,170)Repayment of senior unsecured notes(820,713) —  
Debt issuance costs—
 (224)Debt issuance costs(13,297) —  
Contributions from noncontrolling interests1,230
 1,320
Contributions from noncontrolling interests1,844  1,230  
Distributions to common unitholders(134,838) (126,257)Distributions to common unitholders(85,805) (134,838) 
Distributions to preferred unitholders(6,138) —
Distributions to preferred unitholders(37,368) (6,138) 
Other, net3,509
 3,565
Other, net4,671  3,509  
Net cash used in financing activities(139,337) (59,666)Net cash used in financing activities(106,968) (139,337) 
Net decrease in cash and cash equivalents(721) (1,195)
Cash and cash equivalents at beginning of period10,300
 9,041
Cash and cash equivalents at end of period$9,579
 $7,846
Net decrease in cash, restricted cash, and cash equivalentsNet decrease in cash, restricted cash, and cash equivalents(10,904) (721) 
Cash, restricted cash and cash equivalents at beginning of periodCash, restricted cash and cash equivalents at beginning of period56,405  10,300  
Cash, restricted cash and cash equivalents at end of periodCash, restricted cash and cash equivalents at end of period$45,501  $9,579  
The accompanying notes are an integral part of these Unaudited Condensed Consolidated Financial Statements.

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


1. Organization and Basis of Presentation and Consolidation
Organization
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States and the Gulf of Mexico. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, our soda ash business (our "Alkali Business"), refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.
We currently manage our businesses through the following four4 divisions that constitute our reportable segments:
•Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;
•Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing of high sulfur (or "sour") gas streams for refineries to remove the sulfur, and selling the related by-product, sodium hydrosulfide (or "NaHS", commonly pronounced "nash");
•
•Onshore facilities and transportation, which include terminalling, blending, storing, marketing, and transporting crude oil, petroleum products, and CO2; and
•2; and
Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America.
Basis of Presentation and Consolidation
The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its subsidiaries, including our general partner, Genesis Energy, LLC.
Our results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The Condensed Consolidated Financial Statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"(the "SEC"). Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods. Certain information and notes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles ("GAAP") 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, 2018.2019 (our "Annual Report").
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
Covid-19 Update
In March 2020, the World Health Organization categorized Covid-19 as a pandemic, and the President of the United States declared the Covid-19 outbreak a national emergency. Our operations, which fall within the energy, mining and transportation sectors, are considered critical and essential by the Department of Homeland Security's Cybersecurity and Infrastructure Security Agency ("CISA") and we have continued to operate our assets during this pandemic.
Covid-19 has caused commodity prices to decline due to, among other things, reduced industrial activity and travel restrictions that are expected to continue in the near future. Our results for the second quarter of 2020 were negatively impacted, primarily through lower volumes and demand for our assets, by the macroeconomic conditions and current operating environment. We considered the impact of lower commodity prices and Covid-19 on the assumptions and estimates reflected in our financial statements. As a result, we concluded that the net fixed assets and right of use assets, net associated with our rail logistics business, which is included within our onshore facilities and transportation segment, was impaired and we recognized a non-cash impairment expense of $277.5 million to reduce the carrying value of the associated assets to their estimated realizable value (refer to Note 6 for additional discussion).
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In response to the pandemic and as part of our overall cost savings strategy, we recorded a one-time charge of approximately $13 million associated with restructuring and severance expenses incurred during the period. We believe we are still well positioned and have adequate liquidity, especially when considering our cash obligations, to operate through the rest of the pandemic and continue our natural path of deleveraging our balance sheet. See further discussion on Covid-19 in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
2. Recent Accounting Developments
Recently Adopted
We have adopted guidance under ASC Topic 606, Revenue from Contracts with Customers, and all related ASUs (collectively "ASC 606") as of January 1, 2018 utilizing the modified retrospective method of adoption. Our material equity method investment, Poseidon Oil Pipeline Company, LLC (“Poseidon”), adopted ASC 606 on January 1, 2019. The adoption did not have an impact to our investment balance or equity in earnings at the transition date or at June 30, 2019. Refer to Note 3 for further details.
We have adopted guidance under ASC Topic 842, Lease Accounting326, Financial Instruments - Credit Losses ("ASC 842"326"), as of January 1, 2019 utilizing the modified retrospective method of adoption. Additionally, we elected to implement the practical expedients that pertain to easements, separation of lease components, and the package of practical expedients which among other things, allows us to carry over previous lease conclusions reached under ASC 840. As a result of adopting the new lease2020 . The standard we recorded an operating lease right of use asset of approximately $209 million with a corresponding lease liability as of the transition date. Refer to Note 4 for further details.

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

Recently Issued
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” ("ASU 2016-13"). ASU 2016-13 changeschanged the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will beare required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effectiveWe have assessed our receivables for interimexpected losses by considering current and annual periods beginning after December 15, 2019. Earlyhistorical information pertaining to our trade accounts and existing contract assets. Our assessment resulted in an immaterial impact to our consolidated financial statements as of the adoption is permitted. The standard requires varying transition methodsdate and for the different categoriesthree and six months ended June 30, 2020.
        During the first quarter of amendments. We do not expect ASU 2016-132020, 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 a material impact on ourearly adopted the amendment and included the required summarized financial statements.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, 20192020 and 2018,2019, respectively:
 Three Months Ended
June 30, 2019
 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated
Fee-based revenues$37,764
 $—
 $78,427
 $58,706
 $174,897
Product Sales185,282
 252,089
 —
 —
 437,371
Refinery Services—
 22,517
 —
 —
 22,517
 $223,046
 $274,606
 $78,427
 $58,706
 $634,785

Three Months Ended
June 30, 2020
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$64,964  $—  $56,720  $21,845  $143,529  
Product Sales—  172,410  —  52,314  224,724  
Refinery Services—  20,214  —  —  20,214  
$64,964  $192,624  $56,720  $74,159  $388,467  
 Three Months Ended
June 30, 2018
 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated
Fee-based revenues$35,010
 $—
 $69,969
 $56,185
 $161,164
Product Sales292,343
 269,151
 —
 —
 561,494
Refinery Services—
 29,730
 —
 —
 29,730
 $327,353
 $298,881
 $69,969
 $56,185
 $752,388

Three Months Ended
June 30, 2019
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$78,427  $—  $58,706  $37,764  $174,897  
Product Sales—  252,089  —  185,282  437,371  
Refinery Services—  22,517  —  —  22,517  
$78,427  $274,606  $58,706  $223,046  $634,785  

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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, 20192020 and 2018,2019, respectively:
Six Months Ended
June 30, 2020
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities and TransportationConsolidated
Fee-based revenues$143,393  $—  $119,066  $62,835  $325,294  
Product Sales—  387,776  —  167,082  554,858  
Refinery Services—  48,238  —  —  48,238  
$143,393  $436,014  $119,066  $229,917  $928,390  
Six Months Ended
June 30, 2019		Six Months Ended
June 30, 2019
Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation ConsolidatedOffshore Pipeline TransportationSodium Minerals & Sulfur ServicesMarine TransportationOnshore Facilities & TransportationConsolidated
Fee-based revenues$75,776
 $—
 $156,744
 $115,356
 $347,876
Fee-based revenues$156,744  $—  $115,356  $75,776  $347,876  
Product Sales356,826
 509,932
 —
 —
 866,758
Product Sales—  509,932  —  356,826  866,758  
Refinery Services—
 40,160
 —
 —
 40,160
Refinery Services—  40,160  —  —  40,160  
$432,602
 $550,092
 $156,744
 $115,356
 $1,254,794
$156,744  $550,092  $115,356  $432,602  $1,254,794  
 Six Months Ended
June 30, 2018
 Onshore Facilities & Transportation Sodium Minerals & Sulfur Services Offshore Pipeline Transportation Marine Transportation Consolidated
Fee-based revenues$65,348
 $—
 $143,229
 $105,114
 $313,691
Product Sales579,714
 533,116
 —
 —
 1,112,830
Refinery Services—
 51,675
 —
 —
 51,675
 $645,062
 $584,791
 $143,229
 $105,114
 $1,478,196


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

Contract Assets and Liabilities
The table below depicts our contract asset and liability balances at December 31, 20182019 and June 30, 2019:2020:

Contract AssetsContract Liabilities
CurrentNon-CurrentCurrentNon-Current
Balance at December 31, 2019$21,912  $54,232  $2,896  $23,170  
Balance at June 30, 202035,913  28,013  3,081  21,597  
 Contract Assets Contract Liabilities
 Current Non-Current Non-Current
Balance at December 31, 2018$—
 $72,241
 $26,271
Balance at June 30, 20196,972
 74,279
 27,056


During both the three and six months ended June 30, 2019, $0.7 million that was previously classified as a contract liability at the beginning of the period was recognized as revenue. Additionally, no revenues were recognized in the period related to performance obligations satisfied or partially satisfied from a previous period. Accounts receivable-trade, net does not include consideration received in kind from our refinery services process. We did not have any material contract modifications during the period that would affect our contract asset and liability balances.

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, 2019. However,2020. We are exempted from disclosing performance obligations with a duration of one year or less, revenue recognized related to performance obligations where the consideration corresponds directly with the value provided to customers, and contracts with variable consideration that is allocated wholly to an unsatisfied performance obligation or promise to transfer a good or service that is part of a series in accordance with ASC 606 does provide the following practical expedients and exemptions that we utilized:606.

1)Performance obligations that are part of a contract with an expected duration of one year or less;

2)Revenue recognized from the satisfaction of performance obligations where we have a right to consideration in an amount that corresponds directly with the value provided to customers; and


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

3)Contracts that contain variable consideration, such as index-based pricing or variable volumes, that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that is part of a series.

We apply these practical expedients and exemptions to our revenue streams recognized over time.        The majority of our contracts qualify for one of these expedients or exemptions. After considering these practical expedients and identifyingFor the remaining contract types that involve revenue recognition over a long-term period and includewith long-term fixed consideration (adjusted for indexing as required), we determined our allocations of transaction price that relate to unsatisfied performance obligations. As it relates toFor our tiered pricing offshore transportation contracts, we provide firm capacity for both fixed and variable consideration over a long term period. Therefore, we have allocated the remaining contract value (as estimated and discussed above) to future periods.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following chart depicts how we expect to recognize revenues for future periods related to these contracts:
Offshore Pipeline TransportationOnshore Facilities and Transportation
Remainder of 2020$36,542  $31,735  
202160,357  22,271  
202270,546  4,703  
202359,698  —  
202453,778  —  
Thereafter156,136  —  
Total$437,057  $58,709  
 Offshore Pipeline TransportationOnshore Facilities and Transportation
Remainder of 2019$47,476
$32,170
202067,600
57,615
202152,479
20,269
202238,152
4,283
202325,353
—
Thereafter142,114
—
Total$373,174
$114,337




4. Lease Accounting
Lessee Arrangements
We lease a variety of transportation equipment (including trucks, trailers, and railcars), terminals, land and facilities, and office space and equipment. Lease terms vary and can range from short term (under 12 months) to long term (greater than 12 months). A majority of our leases contain options to extend the life of the lease at our sole discretion. We considered these options when determining the lease terms used to derive our right of use asset and associated lease liability. Leases with a term of less than 12 months are not recorded on our consolidated balance sheet and we recognize lease expense for these leasesUnaudited Condensed Consolidated Balance Sheets. Lease expenses are recognized on a straight line basis over the lease term.
Certain lease agreements include lease and non-lease components. We have elected to combine lease and non-lease components for all of our underlying assets for the purpose of deriving our right of use asset and lease liability. Additionally, certain lease payments are driven by variable factors, such as plant production or indexing rates. Variable costs are expensed as incurred and are not included in our determination for our lease liability and right of use asset.
As a lessee, we do not have any finance leases and none of our leases contain material residual value guarantees or material restrictive covenants. In addition, most of our leases do not provide an implicit rate, and as such, we determined our incremental borrowing rate based on the information available at January 1, 2019 in determining the present value of lease payments.

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

Our lease portfolio consists of operating leases within three major categories:
LeasesClassificationFinancial Statement CaptionJune 30,
2019		 January 1,
2019
Assets  

  
 Transportation EquipmentRight of Use Assets, net107,383
 117,727
 Office Space & EquipmentRight of Use Assets, net12,517
 14,194
 Facilities and EquipmentRight of Use Assets, net71,597
 77,008
Total Right of Use Assets, net  191,497

208,929
Liabilities     
 Current Accrued liabilities30,501
 33,016
 Non-Current Other long-term liabilities157,228
 171,348
Total Lease Liability  $187,729

$204,364


Our Right of Use Assets, net balance above 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 (Note 8).lease. Our lease liability includes our remaining provision for each period presented for our cease-use provision for railcars no longer in use.
We recorded total operating lease costs of $13.0 million Our short-term and $26.2 million during the three and six months ended June 30, 2019. The total operating cost includes the amounts associated with our existinglong-term lease liabilities along with both short termare recorded within "Accrued liabilities" and variable lease costs incurred during the period which are not significant to the operating lease cost individually, or in the aggregate.
The maturities of our operating lease"Other long-term liabilities, as of June 30, 2019 on an undiscounted cash flow basis reconciled to the present value recorded" respectively, on our Unaudited Condensed Consolidated Balance Sheet:
Maturity of Lease LiabilitiesTransportation EquipmentOffice Space and EquipmentFacilities and EquipmentOperating Leases
Remainder of 2019$16,213
$2,412
$6,219
$24,844
202025,996
4,069
9,383
39,448
202120,137
3,087
6,720
29,944
202217,980
2,376
5,410
25,766
202317,077
600
5,349
23,026
Thereafter43,619
2,307
129,085
175,011
Total Lease Payments141,022
14,851
162,166
318,039
Less: Interest(29,195)(2,264)(98,851)(130,310)
Present value of operating lease liabilities$111,827
$12,587
$63,315
$187,729


The following table presents the weighted average remaining term and discount rate related to our right of use assets:
Lease Term and Discount RateJune 30,
2019
Weighted-average remaining lease term12.24 years
Weighted-average discount rate7.56%



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

The following table provides information regarding the cash paid and right of use assets obtained related to our operating leases:
Cash Flows Information

June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities$23,868
Leased assets obtained in exchange for new operating lease liabilities197,877


Sheets.
Lessor Arrangements
We have the following contracts in which we act as a lessor. We also, from time to time, sublease certain of our transportation and facilities equipment to third parties.
Operating Leases
We act as a lessor in our revenue contract associated with the M/T American Phoenix, within theincluded in our marine transportation segment, and on our Free State pipeline system, included in our onshore facilities and transportation segment. The M/T American Phoenix ocean tanker is currently under charter alongThese revenues are recorded within its respective segment's revenues in the Gulf Coast until 2020 with a large refining customer. We recordedUnaudited Condensed Consolidated Statements of Operations. Our lease revenuerevenues for these arrangements (inclusive of $6.7 millionfixed and $13.4 millionvariable consideration) are reflected in the table below for the three and six months ended June 30, 2020 and 2019, and $7.1 million and $13.4 million for the three and six months ended June 30, 2018 , respectively, which is recorded in marine transportation revenues on the Unaudited Condensed Consolidated Statements of Operations.respectively:
Additionally, we act as a lessor on our Free State pipeline system, which is included in the onshore and facilities transportation segment. The Free State pipeline is an 86 mile pipeline in Eastern Mississippi used to transport CO2 that is recovered in the area downstream to several delivery points in and around the Mississippi region. Our Free State pipeline is currently under lease through 2028 to an affiliate of an independent crude oil company. We receive fixed installments through the life of the lease as well as variable consideration that is determined by average daily volumes of throughput. We recorded total revenue of $1.3 million and $2.9 million for the three and six months ended June 30, 2019 and $1.6 million and $3.1 million for the three and six months ended June 30, 2018, respectively, which is recorded in onshore facilities and transportation revenues on the Unaudited Condensed Consolidated Statements of Operations.
Three Months Ended
June 30,		Six Months Ended
June 30,
2020201920202019
M/T American Phoenix$6,734  $6,734  $13,377  $13,394  
Free State Pipeline1,499  1,272  3,422  2,884  
Direct Finance Lease
Our direct finance lease includes a lease of the Northeast Jackson Dome ("NEJD") Pipeline. Under the terms of the agreement, we are paid a quarterly payment, which commenced in August 2008. These payments are fixed at approximately $5.2 million per quarter during the lease term at an interest rate of 10.25%. At the end of the lease term in 2028, we will convey all of our interest in the NEJD Pipeline to the lessee for a nominal payment.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table details the fixed lease payments we will receive for our lessor arrangements as of June 30, 2019:2020: 
 Operating LeasesDirect Financing Lease
Maturity of Lessor ReceiptsMarine TransportationOnshore Facilities and TransportationOnshore Facilities and Transportation
Remainder of 2019$13,616
$600
$10,334
202020,128
1,200
20,668
2021—
1,200
20,668
2022—
1,200
20,668
2023—
1,200
20,668
Thereafter—
5,300
93,005
Total Lease Receipts33,744
10,700
186,011
Less: Interest—
—
(64,736)
Total Net Lease Receipts$33,744
$10,700
$121,275

Operating LeasesDirect Financing Lease
Maturity of Lessor ReceiptsMarine TransportationOnshore Facilities and TransportationOnshore Facilities and Transportation
Remainder of 2020$6,660  $600  $10,334  
2021—  1,200  20,668  
2022—  1,200  20,668  
2023—  1,200  20,668  
2024—  1,200  20,668  
Thereafter—  4,100  72,336  
Total Lease Receipts6,660  9,500  165,342  
Less: Interest—  —  (52,841) 
Total Net Lease Receipts$6,660  $9,500  $112,501  
The present value of our lease receivables for our direct finance lease includes a current portion of $8.8$9.8 million, which is recorded in other current assets on the Unaudited Condensed Consolidated Balance Sheet as of June 30, 2019.2020.


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

5. Inventories
The major components of inventories were as follows:
June 30,
2020		December 31,
2019
Petroleum products$4,235  $2,721  
Crude oil35,676  5,271  
Caustic soda4,973  5,965  
NaHS14,757  10,845  
Raw materials - Alkali operations7,320  6,238  
Work-in-process - Alkali operations12,784  8,579  
Finished goods, net - Alkali operations16,614  14,168  
Materials and supplies, net - Alkali operations13,172  11,350  
Total$109,531  $65,137  
 June 30,
2019		 December 31,
2018
Petroleum products$13,884
 $12,203
Crude oil21,231
 8,379
Caustic soda6,856
 10,372
NaHS7,277
 12,400
Raw materials - Alkali operations7,457
 5,952
Work-in-process - Alkali operations5,081
 2,322
Finished goods, net - Alkali operations11,172
 11,402
Materials and supplies, net - Alkali operations11,079
 10,490
Other57
 11
Total$84,094
 $73,531


Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were not recordedwas adjusted $3.7 million below cost as of June 30, 2019 and were recorded below cost by $1.0 million2020, with 0 such adjustment as of December 31, 2018.

2019.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. Fixed Assets, Mineral Leaseholds, and Asset Retirement Obligations
Fixed Assets
Fixed assets, net consisted of the following:
 
June 30,
2020		December 31,
2019
Crude oil pipelines and natural gas pipelines and related assets$2,883,553  $2,891,489  
Alkali facilities, machinery, and equipment600,325  591,547  
Onshore facilities, machinery, and equipment264,208  640,376  
Transportation equipment18,728  19,864  
Marine vessels991,623  979,171  
Land, buildings and improvements217,719  238,451  
Office equipment, furniture and fixtures22,001  22,645  
Construction in progress148,865  115,162  
Other41,891  41,891  
Fixed assets, at cost5,188,913  5,540,596  
Less: Accumulated depreciation(1,238,006) (1,246,121) 
Net fixed assets$3,950,907  $4,294,475  
 June 30,
2019		 December 31,
2018
Crude oil pipelines and natural gas pipelines and related assets$2,919,237
 $2,918,285
Alkali facilities, machinery, and equipment542,919
 533,924
Onshore facilities, machinery, and equipment640,129
 639,023
Transportation equipment19,573
 20,102
Marine vessels960,947
 951,597
Land, buildings and improvements223,341
 222,242
Office equipment, furniture and fixtures20,560
 20,505
Construction in progress136,763
 94,025
Other41,891
 41,155
Fixed assets, at cost5,505,360
 5,440,858
Less: Accumulated depreciation(1,160,353) (1,023,825)
Net fixed assets$4,345,007
 $4,417,033


Mineral Leaseholds
Our Mineral Leaseholds, relating to our Alkali Business, consist of the following:
June 30,
2020		December 31,
2019
Mineral leaseholds$566,019  $566,019  
Less: Accumulated depletion(11,998) (10,194) 
Mineral leaseholds, net of accumulated depletion$554,021  $555,825  
 June 30,
2019		 December 31,
2018
Mineral leaseholds$566,019
 $566,019
Less: Accumulated depletion(7,822) (5,538)
Mineral leaseholds, net$558,197
 $560,481


Our depreciation and depletion expense for the periods presented was as follows:
Three Months Ended
June 30,		Six Months Ended
June 30,
2020201920202019
Depreciation expense$75,089  $73,206  $144,331  $144,878  
Depletion expense841  965  1,804  2,284  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Depreciation expense$73,206
 $70,836
 $144,878
 $139,264
Depletion expense965
 1,054
 2,284
 2,191

During the second quarter of 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 has become uneconomic for producers and the current demand and outlook for our rail logistics assets has declined. Due to this, we identified a triggering event that required us to perform an impairment test.
For our recoverability test, we utilized management's estimates, including current contractual commitments, for our future cash inflows, and our costs and expenses were determined based on the estimated fixed and variable requirements to operate and maintain the related assets. As our rail logistics asset groups did not pass the initial recoverability assessment, we subsequently performed a fair value calculation using a discounted cash flow model under the income approach. As a result of this test, we recognized impairment expense of $277.5 million associated with the rail logistics assets in our onshore facilities and transportation segment, as the carrying value of our assets exceeded the estimated realizable value, 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 estimates used in the long-lived asset test were primarily based on level 3 inputs of the fair value hierarchy.

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


Asset Retirement Obligations
We record asset retirement obligations ("AROs") in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations.
The following table presents information regarding our AROs since December 31, 2018:
ARO liability balance, December 31, 2018$239,865
Accretion expense4,576
Changes in estimate(15,711)
Settlements(20,277)
ARO liability balance, June 30, 2019$208,453

2019:

ARO liability balance, December 31, 2019$175,081 
Accretion expense4,510 
Changes in estimate560 
Settlements(9,851)
ARO liability balance, June 30, 2020$170,300 
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Of the ARO balances disclosed above, $62.2$11.6 million and $67.5$26.6 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of June 30, 20192020 and December 31, 2018,2019, respectively. The remainder of the ARO liability as of June 30, 20192020 and December 31, 20182019 is included in "Other long-term liabilities" on our Unaudited Condensed Consolidated Balance Sheet. During 2019, we recorded a change in estimate of $15.7 million related to revisions in our estimated abandonment costs for certain of our non-operating offshore gas assets.
With respect to our AROs, the following table presents our estimate of accretion expense for the periods indicated:
Remainder of2019$5,136
 2020$9,053
 2021$9,297
 2022$9,892
 2023$10,586

Remainder of2020$4,868  
2021$9,497  
2022$9,513  
2023$10,183  
2024$10,900  
Certain of our unconsolidated affiliates have AROs recorded at June 30, 20192020 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Unaudited Condensed Consolidated Financial Statements.
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 June 30, 20192020 and December 31, 2018,2019, the unamortized excess cost amounts totaled $358.6$343.1 million and $366.4$350.9 million, respectively. We amortize the excess cost as a reduction in equity earnings.
The following table presents information included in our Unaudited Condensed Consolidated Financial Statements related to our equity investees.
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
Genesis’ share of operating earnings$16,490  $18,918  $34,522  $35,788  
Amortization of excess purchase price(3,872) (3,872) (7,745) (7,745) 
Net equity in earnings$12,618  $15,046  $26,777  $28,043  
Distributions received$18,394  $20,721  $38,959  $38,546  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Genesis’ share of operating earnings$18,918
 $12,266
 $35,788
 $26,780
Amortization of excess purchase price$(3,872) (3,942) (7,745) (7,884)
Net equity in earnings$15,046
 $8,324
 $28,043
 $18,896
Distributions received$20,721
 $18,361
 $38,546
 $37,990

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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,
2020		December 31,
2019
BALANCE SHEET DATA:
Assets
Current assets$19,440  $30,307  
Fixed assets, net179,471  187,091  
Other assets1,933  2,113  
Total assets$200,844  $219,511  
Liabilities and equity
Current liabilities$11,385  $15,558  
Other liabilities238,223  245,976  
Equity(48,764) (42,023) 
Total liabilities and equity$200,844  $219,511  
 June 30,
2019		 December 31,
2018
BALANCE SHEET DATA:   
Assets   
Current assets$17,230
 $18,911
Fixed assets, net194,398
 202,116
Other assets2,310
 886
Total assets$213,938
 $221,913
Liabilities and equity   
Current liabilities$16,611
 $15,909
Other liabilities237,158
 242,881
Equity(39,831) (36,877)
Total liabilities and equity$213,938
 $221,913
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
INCOME STATEMENT DATA:
Revenues$30,419  $34,387  $63,311  $65,439  
Operating income$21,922  $25,655  $45,528  $47,960  
Net income$20,636  $23,295  $42,219  $43,145  



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

 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
INCOME STATEMENT DATA:       
Revenues$34,387
 $27,250
 $65,439
 $56,194
Operating income$25,655
 $19,325
 $47,960
 $39,672
Net income$23,295
 $17,432
 $43,145
 $36,010


Poseidon's Revolving Credit Facility
Borrowings under Poseidon’s revolving credit facility, which was amended and restated in March 2019, are primarily used to fund spending on capital projects. The March 2019 credit facility is non-recourse to Poseidon’s owners and secured by substantially all of Poseidon's assets and has a new maturity date of March 2024. The March 2019 credit facility contains customary covenants such as restrictions on debt levels, liens, guarantees, mergers, sale of assets and distributions to owners. A breach of any of these covenants could result in acceleration of the maturity date of Poseidon’s debt. Poseidon was in compliance with the terms of its credit agreement for all periods presented in these Unaudited Condensed Consolidated Financial Statements.
8. Intangible Assets
The following table summarizes the components of our intangible assets at the dates indicated:
 
 June 30, 2019 December 31, 2018
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Carrying
Value
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Carrying
Value
Intangibles associated with lease (1)
$—
 $—
 $—
 $13,260
 $5,407
 $7,853
Marine contract intangibles27,800
 20,313
 7,487
 27,800
 17,593
 10,207
Offshore pipeline contract intangibles158,101
 32,591
 125,510
 158,101
 28,431
 129,670
Other33,123
 18,942
 14,181
 31,747
 16,875
 14,872
Total$219,024
 $71,846
 $147,178
 $230,908
 $68,306
 $162,602

 June 30, 2020December 31, 2019
 Gross
Carrying
Amount		Accumulated
Amortization		Carrying
Value		Gross
Carrying
Amount		Accumulated
Amortization		Carrying
Value
Marine contract intangibles$27,800  $25,752  $2,048  $27,800  $23,033  $4,767  
Offshore pipeline contract intangibles158,101  40,912  117,189  158,101  36,752  121,349  
Other26,045  13,313  12,732  34,291  21,480  12,811  
Total$211,946  $79,977  $131,969  $220,192  $81,265  $138,927  
(1) Intangible assets associated with a lease in our onshore facilities & transportation segment are now classified as part of our Right or Use Assets, net as part of our adoption of ASC 842 as of January 1, 2019 (Note 4).
Our amortization of intangible assets for the periods presented was as follows:
Three Months Ended
June 30,		Six Months Ended
June 30,
2020201920202019
Amortization of intangible assets$4,146  $4,812  $8,262  $9,101  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Amortization of intangible assets$4,812
 $5,461
 $9,101
 $10,894
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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 of2019$8,616
 2020$15,910
 2021$10,421
 2022$10,247
 2023$9,975

Remainder of2020$7,355  
2021$10,553  
2022$10,394  
2023$10,126  
2024$9,811  

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


9. Debt
Our obligations under debt arrangements consisted of the following:
 June 30, 2020December 31, 2019
 Principal
Unamortized Debt Issuance Costs (1)
Net ValuePrincipal
Unamortized Discount and Debt Issuance Costs (1)
Net Value
Senior secured credit facility$1,053,000  $—  $1,053,000  $959,300  $—  $959,300  
6.750% senior unsecured notes due 2022—  —  —  750,000  9,349  740,651  
6.000% senior unsecured notes due 2023398,905  3,015  395,890  400,000  3,557  396,443  
5.625% senior unsecured notes due 2024341,135  3,391  337,744  350,000  3,923  346,077  
6.500% senior unsecured notes due 2025535,498  6,241  529,257  550,000  7,020  542,980  
6.250% senior unsecured notes due 2026406,980  5,179  401,801  450,000  6,214  443,786  
7.750% senior unsecured notes due 2028727,044  12,160  714,884  —  —  —  
Total long-term debt$3,462,562  $29,986  $3,432,576  $3,459,300  $30,063  $3,429,237  
 June 30, 2019 December 31, 2018
 Principal 
Unamortized Discount and Debt Issuance Costs (1)
 Net Value Principal 
Unamortized Discount and Debt Issuance Costs (1)
 Net Value
Senior secured credit facility$967,000
 $—
 $967,000
 $970,100
 $—
 $970,100
6.750% senior unsecured notes750,000
 11,069
 738,931
 750,000
 12,763
 737,237
6.000% senior unsecured notes400,000
 4,090
 395,910
 400,000
 4,624
 395,376
5.625% senior unsecured notes350,000
 4,372
 345,628
 350,000
 4,820
 345,180
6.500% senior unsecured notes550,000
 7,631
 542,369
 550,000
 8,241
 541,759
6.250% senior unsecured notes450,000
 6,701
 443,299
 450,000
 7,189
 442,811
Total long-term debt$3,467,000
 $33,863
 $3,433,137
 $3,470,100
 $37,637
 $3,432,463
(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 $6.0 million and $7.6 million as of June 30, 2020 and December 31, 2019, respectively.

(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 $9.2 million and $10.8 million as of June 30, 2019 and December 31, 2018, respectively.
As of June 30, 2019,2020, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.
Senior Secured Credit Facility
The key terms for rates under our $1.7 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:
•The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At June 30, 2019,2020, the applicable margins on our borrowings were 1.75% for alternate base rate borrowings and 2.75% for Eurodollar rate borrowings.
•Letter of credit fee rates range from 1.50% to 3.00% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At June 30, 2019,2020, our letter of credit rate was 2.75%.
•We pay a commitment fee on the unused portion of the $1.7 billion maximum facility amount. The commitment fee rates on the unused committed amount will range from 0.25% to 0.50% per annum depending on our leverage ratio. At June 30, 2019,2020, our commitment fee rate on the unused committed amount was 0.50%.
•The accordion feature is $300.0 million, giving us the ability to expand the size of the facility to up to $2.0 billion for acquisitions or growth projects, subject to lender consent.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

        On March 25, 2020, we amended our credit agreement. This amendment, among other things, (i) sets the maximum Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) at 3.25 to 1.00 throughout the remaining term of the facility, and (ii) allows us to purchase certain of our outstanding senior unsecured notes, subject to certain customary conditions.
On July 24, 2020, we further amended our credit agreement. The amendment increases our Consolidated Leverage Ratio from 5.50X to 5.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 5.50X for the remaining term of the agreement. Additionally, it decreases our Consolidated Interest Coverage Ratio from 3.0X to 2.75X from September 30, 2020 through March 31, 2021, after which time it reverts back to 3.0X for the remaining term of the agreement.
At June 30, 2019,2020, we had $967.0$1,053.0 million borrowed under our $1.7 billion credit facility, with $30.3$32.3 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100.0 million of the capacity to be used for letters of credit, of which $1.1 million was outstanding at June 30, 2019.2020. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our credit facility at June 30, 2020 was $645.9 million, subject to compliance with covenants.
As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries (as defined below in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations), and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Genesis Alkali Holdings Company, LLC ("Alkali Holdings") and Genesis Energy, L.P., to the extent agreed to in the services agreement between Genesis Energy, L.P. and Alkali Holdings dated as of September 23, 2019 was $731.9 million.(the "Services Agreement").
Senior Unsecured Note Issuances, Redemption, and ExtinguishmentTransactions
On December 11, 2017,January 16, 2020, we issued $450$750.0 million in aggregate principal amount of 6.25%our 7.75% senior unsecured notes due MayFebruary 15, 20262028 (the "2026 Notes"“2028 Notes”). Interest payments are due May 15February 1 and November 15August 1 of each year with the initial interest

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


payment due May 15, 2018. Our 2026 Notes mature on May 15, 2026.August 1, 2020. That issuance generated net proceeds of $441.8$736.7 million net of issuance costs incurred. WeThe net proceeds were used $204.8to purchase $527.9 million of the net proceeds to redeem the portion of theour existing 6.75% senior unsecured notes due February 15, 2021August 1, 2022 (the "2021 Notes"“2022 Notes”) that were validly tendered, including the related accrued interest and tender premium on those notes, and the remaining net proceeds at the time 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 15, 2018, we redeemed our remaining 2021 Notes in full at a redemption price of 101.438% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. 16, 2020. We incurred a total loss of approximately $3.3$23.5 million relating to the extinguishment of thoseour 2022 senior unsecured notes, (includinginclusive of our transactions costs and the write-off of the related unamortized debt issuance costs),costs and discount, which is recorded as "Other expense"income (expense)" in our Unaudited Consolidated Statements of Operations for the six months ended June 30, 2018.2020.

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.


10. Partners’ Capital, Mezzanine Capital and Distributions
At June 30, 2019,2020, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Distributions
We paid or will pay the following distributions to our common unitholders in 20182019 and 2019:2020:
Distribution For Date Paid 
Per Unit
Amount
 
Total
Amount
 Distribution ForDate PaidPer Unit
Amount		Total
Amount
2018     
20192019
1st Quarter
 
May 15, 2018
 $0.5200
 $63,741
 
1st Quarter
May 15, 2019$0.5500  $67,419  
2nd Quarter
 
August 14, 2018
 $0.5300
 $64,967
 
2nd Quarter
August 14, 2019$0.5500  $67,419  
3rd Quarter
 
November 14, 2018
 $0.5400
 $66,193
 
3rd Quarter
November 14, 2019$0.5500  $67,419  
4th Quarter
 
February 14, 2019
 $0.5500
 $67,419
 
4th Quarter
February 14, 2020$0.5500  $67,419  
2019     
20202020
1st Quarter
 
May 15, 2019
 $0.5500
 $67,419
 
1st Quarter
May 15, 2020$0.1500  $18,387  
2nd Quarter
 
August 14, 2019
(1) 
$0.5500
 $67,419
 
2nd Quarter
August 14, 2020
(1)
$0.1500  $18,387  
(1) This distribution was declared on July 9, 20198, 2020 and will be paid to unitholders of record as of July 31, 2019.2020.


Class A Convertible Preferred Units
On September 1, 2017,At June 30, 2020 we sold $750 million of ourhad 25,336,778 Class A Convertible Preferred unitsUnits (our "preferred units""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”) 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. 
Accounting for the Class A Convertible Preferred Units
Our preferred unitsClass A Convertible Preferred Units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event that is outside our control. Therefore, we present them as temporary equity in the mezzanine section of the Unaudited Condensed Consolidated Balance Sheet.Sheets. Because our preferred unitsClass 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 preferred unitsClass A Convertible Preferred Units at their initial carrying amount. However, we would be required to adjust that carrying amount if it becomes probable that we would be required to redeem our preferred units.Class A Convertible Preferred Units.
Initial and Subsequent Measurement
We initially recognized our preferred unitsClass A Convertible Preferred Units at their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of our preferred unitsClass A Convertible Preferred Units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our preferred unitsClass A Convertible Preferred Units to the redemption value over a period of time comprising the date the feature first becomes probable and the date the units can first be redeemed. Our Class A Convertible Preferred Units contain a distribution Rate Reset Election (as defined in Note 15) option. This Rate Reset Election is bifurcated and accounted for separately as an embedded derivative and recorded at fair value at each reporting period. Refer to Note 15 and Note 16 for additional discussion.

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

        Class A Convertible Preferred unitUnit distributions are recognized on the date in which they are declared. Paid-in-kind ("PIK") distributions were declared and issued as follows:
Distribution ForDate Issued
Number of Units (1)
Total Amount
2019
1st Quarter
May 15, 2019364,180  $12,277  
Distribution ForDate Issued Number of Units Total Amount
2018     
1st Quarter
May 15, 2018
 500,976
 $16,888
2nd Quarter
August 14, 2018
 511,934
 $17,527
3rd Quarter
November 14, 2018
 523,132
 $17,635
4th Quarter
February 14, 2019
 534,576
 $18,021
2019     
1st Quarter
May 15, 2019
 364,180
 $12,277
         (1) Subsequent to the first quarter of 2019, all distributions have been and will be paid in cash.


Net Income (Loss) Attributable to Genesis Energy, L.P. is reduced by preferred unitClass A Convertible Preferred Unit distributions in the form of PIK and cash that accumulated during the period. ForNet income (loss) attributable to Genesis Energy, L.P. was reduced by $18.7 million and
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
$37.4 million for the three and six months ended June 30, 2019, net income attributable to common unitholders was reduced by2020, and $18.7 million and $37.1 million respectively. Infor the first quarter of 2019, we declared a PIK for a portion of the quarterly distribution attributable to the first twothree and six months of the first quarter of 2019 (as defined below), resulting in the issuance of 364,180 preferred units. For the portion of the quarterly distribution attributable to the final month of the first quarter of 2019, we paid a cash distribution of $0.2458 for each preferred unit. This total quarterly distribution to the preferred unitholders equates to a quarterly distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis). With respect to our preferred units related to the second quarter of 2019, we declared a cash distribution of $0.7374 per preferred unit (or $2.9496 on an annualized basis), that will be payable on August 14, 2019 to preferred unitholders of record at the close of business on July 31,ended June 30, 2019.

We paid or will pay the following cash distributions to our preferredClass A Convertible Preferred unitholders in 2019: and 2020:
Distribution ForDate PaidPer Unit
Amount		Total
Amount
2019
1st Quarter
May 15, 2019$0.2458  $6,138  
2nd Quarter
August 14, 2019$0.7374  $18,684  
3rd Quarter
November 14, 2019$0.7374  $18,684  
4th Quarter
February 14, 2020$0.7374  $18,684  
2020
1st Quarter
May 15, 2020$0.7374  $18,684  
2nd Quarter
August 14, 2020
(1)
$0.7374  $18,684  
Distribution For Date Paid Per Unit
Amount		 Total
Amount
2019      
1st Quarter
 
May 15, 2019
 $0.2458
 $6,138
2nd Quarter
 
August 14, 2019
 $0.7374
 $18,684
(1) This distribution was declared on July 8, 2020 and will be paid to unitholders of record as of July 31, 2020.


Redeemable Noncontrolling Interests
        On September 23, 2019, we, through a subsidiary, 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 55,000 Alkali preferred units) and committed to purchase up to $350,000,000 of preferred units in Alkali Holdings, the entity that holds our trona and trona-based exploring, mining, processing, producing, marketing and selling business, including its Granger facility near Green River, Wyoming. Alkali Holdings will use the net proceeds from the Alkali Holdings preferred units to fund up to 100% of the anticipated cost of expansion of the Granger facility. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. In consideration for the amendment, we issued 1,750 Alkali preferred units to GSO, which was accounted for as issuance costs.
As of June 30, 2020, we have received cash of $122.9 million for the 131,750 Alkali Holdings preferred units issued to date net of issuance costs, which is inclusive of our transaction related expenses and one-time commitment fee.
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 Sheets due to the redemption features for a change of control.
Initial and Subsequent Measurement
We recorded the Alkali Holdings preferred units at their issuance date fair value, net of issuance costs. The fair value as of June 30, 2020 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 Income (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 on the outstanding Alkali Holdings preferred units and $0.8 million was attributable to redemption accretion value adjustments. Additionally, Net Income (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, 2020 in-kind to our Alkali Holdings preferred unitholders. These PIK distributions increase the unitholders liquidation preference on each Alkali Holdings preferred unit.
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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
        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, 2020, the redemption amount would be equal to $194.7 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.
The following table shows the change in our mezzanine and preferred units balancesredeemable noncontrolling interest balance from December 31, 20182019 to June 30, 2019:2020:
Balance as of December 31, 2019$125,133 
PIK distributions6,708 
Redemption accretion1,537 
Balance as of June 30, 2020$133,378 
 Class A Convertible Preferred Units
 Units$
Balance as of December 31, 201824,438,022
$761,466
Distributions paid-in-kind898,756
30,298
Allocation of Distributions paid in-kind to Preferred Distribution Rate Reset Election (Note 16)
—
(1,649)
Balance as of June 30, 2019$25,336,778
$790,115



11. Net Income (Loss) Per Common Unit
Basic net income per common unit is computed by dividing net income, after considering income attributable to our preferred unitholders, by the weighted average number of common units outstanding.
The dilutive effect of our preferred unitsClass A Convertible Preferred Units is calculated using the if-converted method. Under the if-converted method, our preferredthese units are assumed to be converted at the beginning of the period (beginning with their respective issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit calculation for the

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

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 six months ended June 30, 2019,2020, the effect of the assumed conversion of the 25,336,778 preferred unitsClass A Convertible Preferred Units was anti-dilutive and was not included in the computation of diluted earnings per unit.
The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit amounts):
Three Months Ended
June 30,		Six Months Ended
June 30,
2020201920202019
Net Income (Loss) Attributable to Genesis Energy L.P.$(326,714) $40,120  $(301,805) $56,074  
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684) (18,684) (37,368) (37,099) 
Net Income (Loss) Available to Common Unitholders$(345,398) $21,436  $(339,173) $18,975  
Weighted Average Outstanding Units122,579  122,579  122,579  122,579  
Basic and Diluted Net Income (Loss) per Common Unit$(2.82) $0.17  $(2.77) $0.15  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Net Income Attributable to Genesis Energy L.P.$40,120
 10,997
 $56,074
 $19,031
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684) (17,257) (37,099) $(34,145)
Net Income (Loss) Available to Common Unitholders$21,436
 $(6,260) $18,975
 $(15,114)
        
Weighted Average Outstanding Units122,579
 122,579
 122,579
 122,579
        
Basic and Diluted Net Income (Loss) per Common Unit$0.17
 $(0.05) $0.15
 $(0.12)
        



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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
12. Business Segment Information
We currently manage our businesses through four4 divisions that constitute our reportable segments:
•Offshore pipeline transportation – offshore transportation of crude oil and natural gas in the Gulf of Mexico;
•Sodium minerals and sulfur services – trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as processing high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, NaHS;
•
•Onshore facilities and transportation – terminalling, blending, storing, marketing and transporting crude oil, petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and CO2 ;and
•2 ;and
Marine transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America.
Substantially all of our revenues are derived from, and substantially all of our assets are located in, the United States.
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation, depletion and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our long-term incentive compensation plan and includes the non-income portion of payments received under direct financing leases.
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. 

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

Segment information for the periods presented below was as follows:
Offshore Pipeline TransportationSodium Minerals & Sulfur ServicesOnshore Facilities & TransportationMarine TransportationTotal
Offshore Pipeline Transportation Sodium Minerals & Sulfur Services Onshore Facilities & Transportation Marine Transportation Total
Three Months Ended June 30, 2020Three Months Ended June 30, 2020
Segment margin (a)Segment margin (a)$75,148  $24,824  $21,215  $18,138  $139,325  
Capital expenditures (b)Capital expenditures (b)$1,983  $33,462  $829  $3,493  $39,767  
Revenues:Revenues:
External customersExternal customers$64,964  $194,543  $74,690  $54,270  $388,467  
Intersegment (c)Intersegment (c)—  (1,919) (531) 2,450  $—  
Total revenues of reportable segmentsTotal revenues of reportable segments$64,964  $192,624  $74,159  $56,720  $388,467  
Three Months Ended June 30, 2019         Three Months Ended June 30, 2019
Segment margin (a)$76,528
 $57,705
 $35,920
 $13,959
 $184,112
Segment margin (a)$76,528  $57,705  $35,920  $13,959  $184,112  
Capital expenditures (b)$2,521
 $26,137
 $3,009
 $7,696
 $39,363
Capital expenditures (b)$2,521  $26,137  $3,009  $7,696  $39,363  
Revenues:         Revenues:
External customers$78,427
 $276,513
 $223,778
 $56,067
 $634,785
External customers$78,427  $276,513  $223,778  $56,067  $634,785  
Intersegment (c)—
 (1,907) (732) 2,639
 —
Intersegment (c)—  (1,907) (732) 2,639  $—  
Total revenues of reportable segments$78,427
 $274,606
 $223,046
 $58,706
 $634,785
Total revenues of reportable segments$78,427  $274,606  $223,046  $58,706  $634,785  
Three Months Ended June 30, 2018         
Segment margin (a)$71,602
 $64,542
 $25,744
 $11,966
 $173,854
Six Months Ended June 30, 2020Six Months Ended June 30, 2020
Segment Margin (a)Segment Margin (a)$160,394  $61,765  $49,314  $37,140  $308,613  
Capital expenditures (b)$1,447
 $18,560
 $12,570
 $9,814
 $42,391
Capital expenditures (b)$3,010  $48,437  $1,986  $17,725  $71,158  
Revenues:         Revenues:
External customers$69,969
 $300,928
 $328,134
 $53,357
 $752,388
External customers$143,393  $440,078  $231,489  $113,430  $928,390  
Intersegment (c)—
 (2,047) (781) 2,828
 —
Intersegment (c)—  (4,064) (1,572) 5,636  $—  
Total revenues of reportable segments$69,969
 $298,881
 $327,353
 $56,185
 $752,388
Total revenues of reportable segments$143,393  $436,014  $229,917  $119,066  $928,390  
Six Months Ended June 30, 2019         Six Months Ended June 30, 2019
Segment Margin (a)$152,918
 $116,344
 $61,523
 $26,891
 $357,676
Segment Margin (a)$152,918  $116,344  $61,523  $26,891  $357,676  
Capital expenditures (b)$2,979
 $48,843
 $3,784
 $16,924
 $72,530
Capital expenditures (b)$2,979  $48,843  $3,784  $16,924  $72,530  
Revenues:         Revenues:
External customers$156,744
 $553,862
 $434,803
 $109,385
 1,254,794
External customers$156,744  $553,862  $434,803  $109,385  $1,254,794  
Intersegment (c)—
 (3,770) (2,201) 5,971
 —
Intersegment (c)—  (3,770) (2,201) 5,971  $—  
Total revenues of reportable segments$156,744
 $550,092
 $432,602
 $115,356
 $1,254,794
Total revenues of reportable segments$156,744  $550,092  $432,602  $115,356  $1,254,794  
Six Months Ended June 30, 2018         
Segment Margin (a)$144,775
 $128,933
 $47,433
 $22,953
 $344,094
Capital expenditures (b)$2,101
 $28,259
 $35,859
 $20,679
 $86,898
Revenues:         
External customers$143,229
 $588,331
 $648,349
 $98,287
 1,478,196
Intersegment (c)—
 (3,540) (3,287) 6,827
 —
Total revenues of reportable segments$143,229
 $584,791
 $645,062
 $105,114
 $1,478,196
Total assets by reportable segment were as follows:
 June 30,
2019		 December 31,
2018
Offshore pipeline transportation$2,336,898
 $2,359,013
Sodium minerals and sulfur services1,947,472
 1,844,845
Onshore facilities and transportation1,446,972
 1,431,910
Marine transportation780,565
 800,243
Other assets43,036
 43,060
Total consolidated assets$6,554,943
 $6,479,071

(a)A reconciliation of total Segment Margin to net income attributable to Genesis Energy, L.P. for the periods is presented below.
(b)Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of growth projects) as well as acquisitions of businesses and contributions to equity investees related to same.

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GENESIS ENERGY, L.P.
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,
2020		December 31,
2019
Offshore pipeline transportation$2,230,159  $2,306,946  
Sodium minerals and sulfur services1,976,792  2,019,905  
Onshore facilities and transportation1,083,460  1,457,190  
Marine transportation739,073  772,383  
Other assets39,953  41,217  
Total consolidated assets$6,069,437  $6,597,641  
(a)A reconciliation of total Segment Margin to net income (loss) 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 contributions to equity investees, if any.
(c)Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.
Reconciliation of total Segment Margin to net income (loss) attributable to Genesis Energy, L.P:L.P.:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
Total Segment Margin$139,325  $184,112  $308,613  $357,676  
Corporate general and administrative expenses(24,867) (13,502) (31,359) (24,602) 
Depreciation, depletion, amortization and accretion(82,580) (66,104) (158,558) (146,041) 
Interest expense(51,618) (55,507) (106,583) (111,208) 
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(5,776) (5,675) (12,182) (10,503) 
Other non-cash items (2)
(23,291) (11,012) 8,777  (17,103) 
Cash payments from direct financing leases in excess of earnings(2,294) (2,079) (4,532) (4,107) 
Cancellation of debt income (3)
18,532  —  19,725  —  
Loss on extinguishment of debt (3)
—  —  (23,480) —  
Differences in timing of cash receipts for certain contractual arrangements (4)
(11,638) 9,848  (16,128) 12,135  
Impairment expense (5)
(277,495) —  (277,495) —  
Provision for leased items no longer in use(58) 182  72  372  
Redeemable noncontrolling interest redemption value adjustments (6)
(4,159) —  (8,245) —  
Income tax expense(795) (143) (430) (545) 
Net income (loss) attributable to Genesis Energy, L.P.$(326,714) $40,120  $(301,805) $56,074  
(1) Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)  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 associated with our Class A Convertible Preferred Units. The three and six months ended June 30, 2019 include a $4.7 million unrealized loss and $7.7 million unrealized loss, respectively, from the valuation of the embedded derivative. Refer to Note 16 for details.
(3)  Refer to Note 9 for details surrounding the extinguishment of our 2022 notes and note repurchases.
(4) 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.
(5) Refer to Note 6 for details surrounding impairment expense.
(6) Includes PIK distributions attributable to the period and accretion on the redemption feature.
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Total Segment Margin$184,112
 $173,854
 $357,676
 $344,094
Corporate general and administrative expenses(13,502) (13,466) (24,602) (23,926)
Depreciation, depletion, amortization and accretion(66,104) (79,862) (146,041) (157,870)
Interest expense(55,507) (57,909) (111,208) (114,045)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(5,675) (10,037) (10,503) (19,094)
Other non-cash items(11,012) (638) (17,103) (6,775)
Cash payments from direct financing leases in excess of earnings(2,079) (1,884) (4,107) (3,723)
Loss on extinguishment of debt—
 —
 —
 (3,339)
Differences in timing of cash receipts for certain contractual arrangements (2)
9,848
 1,148
 12,135
 4,479
Non-cash provision for leased items no longer in use182
 47
 372
 (139)
Income tax expense(143) (256) (545) (631)
Net income attributable to Genesis Energy, L.P.$40,120
 $10,997
 $56,074
 $19,031
23

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(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)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.
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
13. Transactions with Related Parties
The transactions with related parties were as follows:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Revenues:       
Sales of CO2 to Sandhill Group, LLC (1)
$—
 $690
 $—
 $1,233
Revenues from services and fees to Poseidon(2)
3,236
 3,039
 6,401
 6,239
Revenues from product sales to ANSAC81,784
 93,938
 172,463
 184,734
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(2)
255
 250
 502
 499
Charges for services from ANSAC1,279
 1,256
 2,336
 3,034
(1)We owned a 50% interest in Sandhill Group, LLC which was sold during the third quarter of 2018.
(2)We own 64% interest in Poseidon

 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
Revenues:
Revenues from services and fees to Poseidon(1)
$3,035  $3,236  $6,182  $6,401  
Revenues from product sales to ANSAC48,695  81,784  121,774  172,463  
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)
249  255  503  502  
Charges for services from ANSAC629  1,279  1,461  2,336  
(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.

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


Poseidon
At both June 30, 20192020 and December 31, 20182019, Poseidon owed us $1.5 million and $2.4 million, respectively, for services rendered.
We are the operator of Poseidon and provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement. Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three and six months ended June 30, 20192020 reflect $2.2$2.3 million and $4.5$4.6 million, respectively. Our revenues for the three and six months ended June 30, 20182019 reflect $2.2 million and $4.3$4.5 million, respectively of fees we earned through the provision of services under that agreement.

ANSAC
We (through a subsidiary of our Alkali Business) are a member of the American Natural Soda Ash Corp. ("ANSAC"), 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 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 our Alkali Business on a stand-alone basis. We also benefit from favorable shipping rates for our direct exports when using ANSAC to arrange for ocean transport. Net Sales to ANSAC were $81.8 million and $172.5 million during the three and six months ended June 30, 2019 and were $93.9 million and $184.7 million during the three and six months ended June 30, 2018. The cost charges to us by ANSAC, included in operating costs, were $1.3 million and $2.3 million during the three and six months ended June 30, 2019 and were $1.3 million and $3.0 million during the three and six months ended June 30, 2018.
Receivables from and payables to ANSAC as of June 30, 2019 and December 31, 2018 are as follows:
 June 30, December 31,
 2019 2018
Receivables:   
ANSAC$58,871
 $60,594
Payables:   
ANSAC$1,139
 $815
    


ANSAC is considered a variable interest entity (VIE) because we experience certain risks and rewards from our relationship with it. BecauseAs 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, 2020, such amount is not estimable.
        Net Sales to ANSAC were $48.7 million and $121.8 million during the three and six months ended June 30, 2020 and were $81.8 million and $172.5 million during the three and six months ended June 30, 2019. The costs charged to us by ANSAC, included in operating costs, were $0.6 million and $1.5 million during the three and six months ended June 30, 2020 and were $1.3 million and $2.3 million during the three and six months ended June 30, 2019.


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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Receivables from and payables to ANSAC as of June 30, 2020 and December 31, 2019 are as follows:
 June 30,December 31,
 20202019
Receivables:
ANSAC$45,973  $68,075  
Payables:
ANSAC$630  $2,103  

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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
14. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
 Six Months Ended
June 30,
 2019 2018
(Increase) decrease in:   
Accounts receivable$34,843
 $15,834
Inventories(11,298) (1,436)
Deferred charges463
 (3,968)
Other current assets(14,804) (2,024)
Decrease in:   
Accounts payable(5,705) (26,596)
Accrued liabilities(41,406) (15,965)
Net changes in components of operating assets and liabilities$(37,907) $(34,155)

 Six Months Ended
June 30,
 20202019
(Increase) decrease in:
Accounts receivable$178,509  $34,843  
Inventories(44,394) (11,298) 
Deferred charges9,240  463  
Other current assets(9,919) (14,804) 
Decrease in:
Accounts payable(93,080) (5,705) 
Accrued liabilities(20,838) (41,406) 
Net changes in components of operating assets and liabilities$19,518  $(37,907) 
Payments of interest and commitment fees were $107.5$97.8 million and $115.9$107.5 million for the six months ended June 30, 20192020 and June 30, 2018,2019, respectively. We capitalized interest of $1.7$1.0 million and $2.0$1.7 million during the six months ended June 30, 20192020 and June 30, 2018,2019, respectively.
At June 30, 20192020 and June 30, 2018,2019, we had incurred liabilities for fixed and intangible asset additions totaling $15.1$25.5 million and $18.6$15.1 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

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 whether to designate derivative instruments as fair value hedges for accounting purposes relates to our expectations of the length of time we expect to have the commodity price exposure and our expectations as to whether the derivative contract will qualify as highly effective under accounting guidance in limiting our exposure to commodity price risk. Most of the petroleum products, including fuel oil that we supply, cannot be hedged with a high degree of effectiveness with derivative contracts available on the NYMEX; therefore, we do not designate derivative contracts utilized to limit our price risk related to these products as hedges for accounting purposes. Typically we utilize crude oil and other petroleum products futures and option contracts to limit our exposure to the effect of fluctuations in petroleum products prices on the future sale of our inventory or commitments to purchase petroleum products, and we recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales. The recognition of changes in fair value of the derivative contracts not designated as hedges for accounting purposes can occur in reporting periods that do not coincide with the recognition of gain or loss on the actual transaction being hedged. Therefore we will, on occasion, report gains or losses in one period that will be partially offset by gains or losses in a future period when the hedged transaction is completed.
We have designated certain crude oil futures contracts as hedges of crude oil inventory due to our expectation that these contracts will be highly effective in hedging our exposure to fluctuations in crude oil prices during the period that we expect to hold that inventory. We account for these derivative instruments as fair value hedges under the accounting guidance. Changes in the fair value of these derivative instruments designated as fair value hedges are used to offset related changes in the fair value of the hedged crude oil inventory. Any hedge ineffectiveness in these fair value hedges and any amounts excluded from effectiveness testing are recorded as a gain or loss in the Unaudited Condensed Consolidated Statements of Operations.
In accordance with NYMEX requirements, we fund the margin associated with our loss positions on commodity derivative contracts traded on the NYMEX. The amount of the margin is adjusted daily based on the fair value of the commodity contracts. The margin requirements are intended to mitigate a party's exposure to market volatility and the associated contracting party risk. We offset fair value amounts recorded for our NYMEX derivative contracts against margin funding as required by the NYMEX in Current Assets - Other in our Unaudited Condensed Consolidated Balance Sheets.

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Additionally, we enter into swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales.
At June 30, 2019,2020, we entered into the following outstanding derivative commodity contracts to economically hedge inventory or fixed price purchase commitments.
  
Sell (Short)
Contracts
 
Buy (Long)
Contracts
Designated as hedges under accounting rules:    
Crude oil futures:    
Contract volumes (1,000 bbls) 56
 —
Weighted average contract price per bbl $53.93
 $—
     
Not qualifying or not designated as hedges under accounting rules:    
Crude oil futures:    
Contract volumes (1,000 bbls) 384
 132
Weighted average contract price per bbl $55.62
 $61.38
Natural gas swaps:    
Contract volumes (10,000 MMBTU) 549
 —
Weighted average price differential per MMBTU $0.45
 $—
Natural gas futures:    
Contract volumes (10,000 MMBTU) 138
 637
Weighted average contract price per MMBTU $2.44
 $2.75
NYM NYHBRULSD:    
Contract volumes (42,000 gal) 35
 19
Weighted average contract price per gallon $1.97
 $1.87
NYM RBOB Gas futures:    
Contract volumes (42,000 gal) 5
 5
Weighted average contract price per gallon $1.75
 $1.73
Fuel oil futures:    
Contract volumes (1,000 bbls) 233
 —
Weighted average contract price per bbl $56.34
 $—
Crude oil options:    
Contract volumes (1,000 bbls) 65
 20
Weighted average premium received/paid $1.10
 $0.32

Sell (Short)
Contracts		Buy (Long)
Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)745  —  
Weighted average contract price per bbl$35.40  $—  
Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)460  333  
Weighted average contract price per bbl$35.77  $37.86  
Natural gas swaps:
Contract volumes (10,000 MMBTU)412  —  
Weighted average price differential per MMBTU$0.31  $—  
Natural gas futures:
Contract volumes (10,000 MMBTU)46  455  
Weighted average contract price per MMBTU$1.82  $2.40  
Crude oil options:
Contract volumes (1,000 bbls)27  5  
Weighted average premium received/paid$5.72  $12.22  
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 June 30, 20192020 and December 31, 2018:2019:
Fair Value of Derivative Assets and Liabilities
 Unaudited Condensed Consolidated Balance Sheets LocationFair Value
 June 30,
2020		 December 31,
2019
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assetsCurrent Assets - Other$921  $207  
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other(921) (207) 
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$—  $—  
Natural Gas Swap (undesignated hedge)Current Assets - Other937  1,382  
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assetsCurrent Assets - Other$283  $4  
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other(283) (4) 
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$—  $—  
Liability Derivatives:
Preferred Distribution Rate Reset Election (2)
Other long-term liabilities(40,809) (51,515) 
Natural Gas Swap (undesignated hedge)Accrued Liabilities(67) —  
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities
Current Assets - Other (1)
$(3,155) $(2,079) 
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
3,155  1,064  
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$—  $(1,015) 
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities
Current Assets - Other (1)
$(3,282) $(50) 
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
3,282  50  
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives$—  $—  
 (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
 June 30,
2019		 December 31,
2018
Asset Derivatives:     
Commodity derivatives - futures and call options (undesignated hedges):     
Gross amount of recognized assetsCurrent Assets - Other $613
 $3,431
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other (613) (1,361)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $—
 $2,070
Natural Gas Swap (undesignated hedge)Current Assets - Other 666
 1,274
Commodity derivatives - futures and call options (designated hedges):     
Gross amount of recognized assetsCurrent Assets - Other $6
 $469
Gross amount offset in the Unaudited Condensed Consolidated Balance SheetsCurrent Assets - Other (6) (44)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $—
 $425
Liability Derivatives:     
Preferred Distribution Rate Reset Election (2)
Other long-term liabilities (50,157) (40,840)
Natural Gas Swap (undesignated hedge)Current Liabilities - Accrued Liabilities (288) (125)
Commodity derivatives - futures and call options (undesignated hedges):     
Gross amount of recognized liabilities
Current Assets - Other (1)
 $(4,700) $(1,361)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 3,280
 1,361
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $(1,420) $—
Commodity derivatives - futures and call options (designated hedges):     
Gross amount of recognized liabilities
Current Assets - Other (1)
 $(260) $(44)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 260
 44
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives  $—
 $—
 (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 10 and Note 16 for additional discussion surrounding the Preferred Distribution Rate Reset Election derivative.
 
Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists.  Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin.  Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

established by the respective exchange.  On a daily basis, our account equity (consisting of the sum of our cash balance and the
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin.  As of June 30, 2019,2020, we had a net broker receivable of approximately $2.9$7.8 million (consisting of initial margin of $2.7$6.8 million increased by $0.2$1.0 million of variation margin).  As of December 31, 2018,2019, we had a net broker receivable of approximately $2.2$0.9 million (consisting of initial margin of $3.1$0.8 million decreased increased by $0.9$0.1 million of variation margin).  At June 30, 20192020 and December 31, 2018,2019, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. 
Preferred Distribution Rate Reset Election 
A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred unitsClass A Convertible Preferred Units may make a one-time election to reset the quarterly distribution amount (a "Rate Reset Election") 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 110% of the Issue Price. The Rate Reset Election of our preferred unitsClass 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 ExpenseIncome (Expense) in our Unaudited Condensed Consolidated Statement of Operations. At June 30, 2019,2020, the fair value of this embedded derivative was a liability of $50.2$40.8 million. See Note 10 for additional information regarding our preferred unitsClass A Convertible Preferred Units and the Rate Reset Election.
Effect on Operating Results 
   Amount of Gain (Loss) Recognized in Income
 Unaudited Condensed Consolidated Statements of Operations Location Three Months Ended
June 30,		 Six Months Ended
June 30,
  2019 2018 2019 2018
Commodity derivatives - futures and call options:         
Contracts designated as hedges under accounting guidanceOnshore facilities and transportation product costs $23
 $(1,421) $(719) $(2,787)
Contracts not considered hedges under accounting guidanceOnshore facilities and transportation product costs, sodium minerals and sulfur services operating costs (1,399) (5,344) (8,091) (5,676)
Total commodity derivatives  $(1,376) $(6,765) $(8,810) $(8,463)
          
Natural Gas Swap LiabilitySodium minerals and sulfur services operating costs $(284) $90
 $1,235
 $(185)
          
Preferred Distribution Rate Reset ElectionOther expense $(4,692) $(188) $(7,668) $(2,094)

Amount of Gain (Loss) Recognized in Income
 Unaudited Condensed Consolidated Statements of Operations LocationThree Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidanceOnshore facilities and transportation product costs$(10,936) $23  $(10,207) $(719) 
Contracts not considered hedges under accounting guidanceOnshore facilities and transportation product costs, sodium minerals and sulfur services operating costs(2,642) (1,399) (4,017) (8,091) 
Total commodity derivatives$(13,578) $(1,376) $(14,224) $(8,810) 
Natural Gas Swap LiabilitySodium minerals and sulfur services operating costs$983  $(284) $551  $1,235  
Preferred Distribution Rate Reset ElectionOther income (expense)$(21,839) $(4,692) $10,706  $(7,668) 
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

(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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(3)Level 3 fair values are based on unobservable inputs in which little or no market data exists.
As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 20192020 and December 31, 2018.2019. 
 Fair Value atFair Value at
June 30, 2020December 31, 2019
Recurring Fair Value MeasuresLevel 1Level 2Level 3Level 1Level 2Level 3
Commodity derivatives:
Assets$1,204  $937  $—  $211  $1,382  $—  
Liabilities$(6,437) $(67) $—  $(2,129) $—  $—  
Preferred Distribution Rate Reset Election$—  $—  $(40,809) $—  $—  $(51,515) 
  Fair Value at Fair Value at
  June 30, 2019 December 31, 2018
Recurring Fair Value Measures Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Commodity derivatives:            
Assets $619
 $666
 $—
 $3,900
 $1,274
 $—
Liabilities $(4,960) $(288) $—
 $(1,405) $(125) $—
Preferred Distribution Rate Reset Election $—
 $—
 $(50,157) $—
 $—
 $(40,840)


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,
2020
Balance as of December 31, 2019$(51,515)
Unrealized gain for the period included in earnings10,706 
Balance as of June 30, 2020$(40,809)
 Six Months Ended
June 30,
 2019
Balance as of December 31, 2018$(40,840)
Net loss for the period included in earnings(7,668)
Allocation of Distributions Paid-in-kind(1,649)
Balance as of June 30, 2019$(50,157)



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, 2019.2020.
The fair value of the embedded derivative feature is based on a valuation model that estimates the fair value of our preferred unitsClass 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, 2020. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We reportDuring second quarter of 2020, we recorded an unrealized gainsloss 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 losses associated with this embedded derivativefluctuations in the energy industry credit markets and our common unit price during the period. These effects are recorded within "Other income (expense)" on the Unaudited Condensed Consolidated Statements of Operations as Other expense, net.Operations.
See Note 15 for additional information on our derivative instruments.
Other Fair Value Measurements
We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At June 30, 20192020 our senior unsecured notes had a carrying value of $2.4 billion and fair value of $2.2 billion compared to a carrying value and fair value of $2.5 billion compared to $2.5 billion and $2.3 billion, respectively, at December 31, 2018.2019. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.
        

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17. Commitments and Contingencies
We are subject to various environmental laws and regulations. Policies and procedures are in place to aid in monitoring compliance and detecting and addressing releases of crude oil from our pipelines or other facilities and from our mining operations relating to our Alkali Business; however, no assurance can be made that such environmental releases may not substantially affect our business.
We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations, or cash flows.

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18. Condensed Consolidating Financial Information
Our $2.5 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, 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 9 for additional information regarding our consolidated debt obligations.
The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.


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

Unaudited Condensed Consolidating Balance Sheet
June 30, 2019

 
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
 $—
 $7,390
 $2,183
 $—
 $9,579
Other current assets—
 —
 414,971
 11,866
 (19) 426,818
Total current assets6
 —
 422,361
 14,049
 (19) 436,397
Fixed assets, at cost—
 —
 5,427,775
 77,585
 —
 5,505,360
Less: Accumulated depreciation—
 —
 (1,129,886) (30,467) —
 (1,160,353)
Net fixed assets—
 —
 4,297,889
 47,118
 —
 4,345,007
Mineral Leaseholds, net of accumulated depletion—
 —
 558,197
 —
 —
 558,197
Goodwill—
 —
 301,959
 —
 —
 301,959
Other assets, net9,179
 —
 428,860
 113,183
 (173,919) 377,303
Advances to affiliates3,189,059
 —
 —
 110,077
 (3,299,136) —
Equity investees—
 —
 344,583
 —
 —
 344,583
Investments in subsidiaries2,690,066
 —
 78,474
 —
 (2,768,540) —
Right of Use Assets, net$—
 $—
 $191,497
 $—
 $—
 191,497
Total assets$5,888,310
 $—
 $6,623,820
 $284,427
 $(6,241,614) $6,554,943
LIABILITIES AND CAPITAL           
Current liabilities$39,302
 $—
 $273,130
 $40,692
 $(123) $353,001
Senior secured credit facility967,000
 —
 —
 —
 —
 967,000
Senior unsecured notes, net of debt issuance costs2,466,137
 —
 —
 —
 —
 2,466,137
Deferred tax liabilities—
 —
 12,911
 —
 —
 12,911
Advances from affiliates—
 —
 3,299,146
 —
 (3,299,146) —
Other liabilities50,157
 —
 353,169
 168,149
 (173,785) 397,690
Total liabilities3,522,596
 —
 3,938,356
 208,841
 (3,473,054) 4,196,739
Mezzanine Capital:           
Class A Convertible Preferred Units790,115
 —
 —
 —
 —
 790,115
Partners’ capital, common units1,575,599
 —
 2,684,525
 84,035
 (2,768,560) 1,575,599
Accumulated other comprehensive income(1)
—
 —
 939
 —
 —
 939
Noncontrolling interests—
 —
 —
 (8,449) —
 (8,449)
Total liabilities, mezzanine capital and partners’ capital$5,888,310
 $—
 $6,623,820
 $284,427
 $(6,241,614) $6,554,943
(1)The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension held within our Guarantor Subsidiaries.


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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet
Year Ended December 31, 2018
 
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
 $—
 $8,968
 $1,326
 $—
 $10,300
Other current assets50
 —
 419,809
 13,285
 (165) 432,979
Total current assets56
 —
 428,777
 14,611
 (165) 443,279
Fixed assets, at cost—
 —
 5,363,274
 77,584
 —
 5,440,858
Less: Accumulated depreciation—
 —
 (994,609) (29,216) —
 (1,023,825)
Net fixed assets—
 —
 4,368,665
 48,368
 —
 4,417,033
Mineral Leaseholds, net of accumulated depletion—
 —
 560,481
 —
 —
 560,481
Goodwill—
 —
 301,959
 —
 —
 301,959
Other assets, net10,776
 —
 440,312
 117,766
 (167,620) 401,234
Advances to affiliates3,305,568
 —
 —
 103,061
 (3,408,629) —
Equity investees and other investments—
 —
 355,085
 —
 —
 355,085
Investments in subsidiaries2,648,510
 —
 60,532
 —
 (2,709,042) —
Total assets$5,964,910
 $—
 $6,515,811
 $283,806
 $(6,285,456) $6,479,071
LIABILITIES AND CAPITAL           
Current liabilities$39,342
 $—
 $266,252
 $27,350
 $(110) $332,834
Senior secured credit facilities970,100
 —
 —
 —
 —
 970,100
Senior unsecured notes, net of debt issuance costs2,462,363
 —
 —
 —
 —
 2,462,363
Deferred tax liabilities—
 —
 12,576
 —
 —
 12,576
Advances from affiliates—
 —
 3,408,659
 —
 (3,408,659) —
Other liabilities40,840
 —
 188,181
 197,658
 (167,481) 259,198
Total liabilities3,512,645
 —
 3,875,668
 225,008
 (3,576,250) 4,037,071
Mezzanine Capital:           
Class A Convertible Preferred Units761,466
 —
 —
 —
 —
 761,466
Partners’ capital, common units1,690,799
 —
 2,639,204
 70,002
 (2,709,206) 1,690,799
Accumulated other comprehensive income(1)
—
 —
 939
 —
 —
 939
Noncontrolling interests—
 —
 —
 (11,204) —
 (11,204)
Total liabilities, mezzanine capital and partners’ capital$5,964,910
 $—
 $6,515,811
 $283,806
 $(6,285,456) $6,479,071
(1)The entire balance and activity within Accumulated Other Comprehensive Income is related to our pension plan held within our Guarantor Subsidiaries.






32
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2019
 
Genesis
Energy, L.P.
(Parent and
Co-Issuer)
 
Genesis
Energy Finance
Corporation
(Co-Issuer)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations 
Genesis
Energy, L.P.
Consolidated
REVENUES:           
Offshore pipeline transportation services$—
 $—
 $78,427
 $—
 $—
 78,427
Sodium minerals and sulfur services—
 —
 273,833
 2,101
 (1,328) 274,606
Marine transportation—
 —
 58,706
 —
 —
 58,706
Onshore facilities and transportation—
 —
 218,685
 4,361
 —
 223,046
Total revenues—
 —
 629,651
 6,462
 (1,328) 634,785
COSTS AND EXPENSES:           
Onshore facilities and transportation costs—
 —
 185,909
 316
 —
 186,225
Marine transportation costs—
 —
 44,836
 —
 —
 44,836
Sodium minerals and sulfur services operating costs—
 —
 218,761
 2,461
 (1,328) 219,894
Offshore pipeline transportation operating costs—
 —
 11,780
 (7,663) —
 4,117
General and administrative—
 —
 13,412
 —
 —
 13,412
Depreciation, depletion and amortization—
 —
 78,728
 625
 —
 79,353
Total costs and expenses—
 —
 553,426
 (4,261) (1,328) 547,837
OPERATING INCOME—
 —
 76,225
 10,723
 —
 86,948
Equity in earnings of subsidiaries101,107
 —
 6,094
 —
 (107,201) —
Equity in earnings of equity investees—
 —
 15,046
 —
 —
 15,046
Interest (expense) income, net(56,295) —
 3,911
 (3,123) —
 (55,507)
Other expense(4,692) —
 —
 —
 —
 (4,692)
Income before income taxes40,120
 —
 101,276
 7,600
 (107,201) 41,795
Income tax expense—
 —
 (135) (8) —
 (143)
NET INCOME40,120
 —
 101,141
 7,592
 (107,201) 41,652
Net income attributable to noncontrolling interest—
 —
 —
 (1,532) —
 (1,532)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.$40,120
 $—
 $101,141
 $6,060
 $(107,201) $40,120
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(18,684) —
 —
 —
 —
 (18,684)
NET INCOME AVAILABLE TO COMMON UNIT HOLDERS$21,436
 $—
 $101,141
 $6,060
 $(107,201) $21,436






33
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2018
 
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$—
 $—
 $69,969
 $—
 $—
 69,969
Sodium minerals and sulfur services—
 —
 297,929
 3,068
 (2,116) 298,881
Marine transportation—
 —
 56,185
 —
 —
 56,185
Onshore facilities and transportation—
 —
 322,469
 4,884
 —
 327,353
Total revenues—
 —
 746,552
 7,952
 (2,116) 752,388
COSTS AND EXPENSES:           
Onshore facilities and transportation costs—
 —
 305,828
 277
 —
 306,105
Marine transportation costs—
 —
 44,217
 —
 —
 44,217
Sodium minerals and sulfur services operating costs—
 —
 232,021
 2,612
 (2,116) 232,517
Offshore pipeline transportation operating costs—
 —
 16,809
 631
 —
 17,440
General and administrative—
 —
 13,529
 —
 —
 13,529
Depreciation, depletion and amortization—
 —
 77,055
 625
 —
 77,680
Total costs and expenses—
 —
 689,459
 4,145
 (2,116) 691,488
OPERATING INCOME—
 —
 57,093
 3,807
 —
 60,900
Equity in earnings of subsidiaries69,433
 —
 897
 —
 (70,330) —
Equity in earnings of equity investees—
 —
 8,324
 —
 —
 8,324
Interest (expense) income, net(58,248) —
 3,660
 (3,321) —
 (57,909)
Other expense(188) —
 —
 —
 —
 (188)
Income before income taxes10,997
 —
 69,974
 486
 (70,330) 11,127
Income tax expense—
 —
 (478) 222
 —
 (256)
NET INCOME10,997
 —
 69,496
 708
 (70,330) 10,871
Net loss attributable to noncontrolling interest—
 —
 —
 126
 —
 126
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.$10,997
 $—
 $69,496
 $834
 $(70,330) $10,997
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(17,257) —
 —
 —
 —
 (17,257)
NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS$(6,260) $—
 $69,496
 $834
 $(70,330) $(6,260)


















34
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2019
 
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$—
 $—
 $156,744
 $—
 $—
 $156,744
Sodium minerals and sulfur services—
 —
 549,010
 4,210
 (3,128) 550,092
Marine transportation—
 —
 115,356
 —
 —
 115,356
Onshore facilities and transportation—
 —
 423,491
 9,111
 —
 432,602
Total revenues—
 —
 1,244,601
 13,321
 (3,128) 1,254,794
COSTS AND EXPENSES:           
Onshore facilities and transportation costs—
 —
 373,306
 676
 —
 373,982
Marine transportation costs—
 —
 88,569
 —
 —
 88,569
Sodium minerals and sulfur services
 operating costs
—
 —
 436,979
 4,751
 (3,128) 438,602
Offshore pipeline transportation operating costs—
 —
 30,201
 (7,626) —
 22,575
General and administrative—
 —
 25,098
 —
 —
 25,098
Depreciation, depletion and amortization—
 —
 155,741
 1,250
 —
 156,991
Total costs and expenses—
 —
 1,109,894
 (949) (3,128) 1,105,817
OPERATING INCOME—
 —
 134,707
 14,270
 —
 148,977
Equity in earnings of subsidiaries176,394
 —
 6,511
 —
 (182,905) —
Equity in earnings of equity investees—
 —
 28,043
 —
 —
 28,043
Interest (expense) income, net(112,652) —
 7,742
 (6,298) —
 (111,208)
Other expense(7,668) —
 —
 —
 —
 (7,668)
Income before income taxes56,074
 —
 177,003
 7,972
 (182,905) 58,144
Income tax expense—
 —
 (537) (8) —
 (545)
NET INCOME56,074
 —
 176,466
 7,964
 (182,905) 57,599
Net income attributable to noncontrolling interest—
 —
 —
 (1,525) —
 (1,525)
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.$56,074
 $—
 $176,466
 $6,439
 $(182,905) $56,074
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(37,099) —
 —
 —
 —
 $(37,099)
NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS$18,975
 $—
 $176,466
 $6,439
 $(182,905) $18,975


35
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2018
 
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$—
 $—
 $143,229
 


 $—
 $143,229
Sodium minerals and sulfur services—
 —
 583,026
 6,134
 (4,369) 584,791
Marine transportation—
 —
 105,114
 —
 —
 105,114
Onshore facilities and transportation—
 —
 635,343
 9,719
 —
 645,062
Total revenues—
 —
 1,466,712
 15,853
 (4,369) 1,478,196
COSTS AND EXPENSES:           
Onshore facilities and transportation costs—
 —
 605,669
 549
 —
 606,218
Marine transportation costs—
 —
 82,064
 —
 —
 82,064
Sodium minerals and sulfur services operating costs—
 —
 455,268
 5,116
 (4,369) 456,015
Offshore pipeline transportation operating costs—
 —
 34,471
 1,309
 —
 35,780
General and administrative—
 —
 25,203
 —
 —
 25,203
Depreciation, depletion and amortization—
 —
 151,685
 1,250
 —
 152,935
Total costs and expenses—
 —
 1,354,360
 8,224
 (4,369) 1,358,215
OPERATING INCOME—
 —
 112,352
 7,629
 —
 119,981
Equity in earnings of subsidiaries139,025
 —
 1,529
 —
 (140,554) —
Equity in earnings of equity investees—
 —
 18,896
 —
 —
 18,896
Interest (expense) income, net(114,562) —
 7,204
 (6,687) —
 (114,045)
Other expense(5,432) —
 —
 —
 —
 (5,432)
Income before income taxes19,031
 —
 139,981
 942
 (140,554) 19,400
Income tax expense—
 —
 (855) 224
 —
 (631)
NET INCOME19,031
 —
 139,126
 1,166
 (140,554) 18,769
Net loss attributable to noncontrolling interest—
 —
 —
 262
 —
 262
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.$19,031
 $—
 $139,126
 $1,428
 $(140,554) $19,031
Less: Accumulated distributions attributable to Class A Convertible Preferred Units(34,145) —
 —
 —
 —
 (34,145)
NET INCOME (LOSS) AVAILABLE TO COMMON UNIT HOLDERS$(15,114) $—
 $139,126
 $1,428
 $(140,554) $(15,114)





36
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2019
 
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$33,704
 $—
 $292,202
 $380
 $(130,676) $195,610
CASH FLOWS FROM INVESTING ACTIVITIES:           
Payments to acquire fixed and intangible assets—
 —
 (68,666) —
 —
 (68,666)
Cash distributions received from equity investees - return of investment—
 —
 10,811
 —
 —
 10,811
Intercompany transfers110,372
 —
 —
 —
 (110,372) —
Repayments on loan to non-guarantor subsidiary—
 —
 4,036
 —
 (4,036) —
Proceeds from asset sales—
 —
 861
 —
 —
 861
Net cash used in investing activities110,372
 —
 (52,958) —
 (114,408) (56,994)
CASH FLOWS FROM FINANCING ACTIVITIES:           
Borrowings on senior secured credit facility387,000
 —
 —
 —
 —
 387,000
Repayments on senior secured credit facility(390,100) —
 —
 —
 —
 (390,100)
Intercompany transfers—
 —
 (103,355) (7,017) 110,372
 —
Distributions to common unitholders(134,838) —
 (134,838) —
 134,838
 (134,838)
Distributions to preferred unitholders(6,138) —
 (6,138) —
 6,138
 (6,138)
Contributions from noncontrolling interest—
 —
 —
 1,230
 —
 1,230
Other, net—
 —
 3,509
 6,264
 (6,264) 3,509
Net cash used in financing activities(144,076) —
 (240,822) 477
 245,084
 (139,337)
Net decrease in cash and cash equivalents—
 —
 (1,578) 857
 —
 (721)
Cash and cash equivalents at beginning of period6
 —
 8,968
 1,326
 —
 10,300
Cash and cash equivalents at end of period$6
 $—
 $7,390
 $2,183
 $—
 $9,579

37
Table of Contents
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2018
 
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$9,724
 $—
 $255,552
 $1,494
 $(115,954) $150,816
CASH FLOWS FROM INVESTING ACTIVITIES:           
Payments to acquire fixed and intangible assets—
 —
 (110,970) —
 —
 (110,970)
Cash distributions received from equity investees - return of investment—
 —
 17,828
 —
 —
 17,828
Investments in equity investees—
 —
 (395) —
 —
 (395)
Acquisitions—
 —
 —
 —
 —
 —
Intercompany transfers54,827
 —
 —
 —
 (54,827) —
Repayments on loan to non-guarantor subsidiary—
 —
 3,647
 —
 (3,647) —
Proceeds from asset sales—
 —
 1,192
 —
 —
 1,192
Net cash used in investing activities54,827
 —
 (88,698) —
 (58,474) (92,345)
CASH FLOWS FROM FINANCING ACTIVITIES:           
Borrowings on senior secured credit facility543,100
 —
 —
 —
 —
 543,100
Repayments on senior secured credit facility(336,000) —
 —
 —
 —
 (336,000)
Repayment of senior unsecured notes(145,170) —
 —
 —
 —
 (145,170)
Debt issuance costs(224) —
 —
 —
 —
 (224)
Intercompany transfers—
 —
 (46,605) (8,222) 54,827
 —
Distributions to common unitholders(126,257) —
 (126,257) —
 126,257
 (126,257)
Contributions from noncontrolling interest—
 —
 —
 1,320
 —
 1,320
Other, net—
 —
 3,565
 6,656
 (6,656) 3,565
Net cash used in financing activities(64,551) —
 (169,297) (246) 174,428
 (59,666)
Net increase (decrease) in cash and cash equivalents—
 —
 (2,443) 1,248
 —
 (1,195)
Cash and cash equivalents at beginning of period6
 —
 8,340
 695
 —
 9,041
Cash and cash equivalents at end of period$6
 $—
 $5,897
 $1,943
 $—
 $7,846





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, 2018.2019.
Included in Management’s Discussion and Analysis of Financial Condition and Results of Operations are the following sections:
•Overview
•Results of Operations
•Liquidity and Capital Resources
•Guarantor Summarized Financial Information
•Non-GAAP Financial Measures
•Commitments and Off-Balance Sheet Arrangements
•Forward Looking Statements
Overview

We reported Net Loss Attributable to Genesis Energy, L.P. of $326.7 million during the three months ended June 30, 2020 (“2020 Quarter”) compared to Net Income Attributable to Genesis Energy, L.P. of $40.1 million during the three months ended June 30, 2019 (“2019 Quarter”) compared to Net Income Attributable to Genesis Energy, L.P. of $11.0 million during the three months ended June 30, 2018 (“2018 Quarter”). Net IncomeLoss Attributable to Genesis Energy, L.P. in the 2020 Quarter was negatively impacted, relative to the 2019 Quarter, benefited from an increase inby: (i) impairment expense of $277.5 million associated with the rail logistics assets included within our onshore and facilities segment; (ii) lower segment margin of $10.3$44.8 million; (iii) an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $21.8 million compared to an unrealized (non-cash) loss of $4.7 million during the 2019 Quarter (which is recorded within "other income (expense)" on the Unaudited Condensed Consolidated Statements of Operations); (iv) higher general and administrative expenses primarily due to a one-time charge of approximately $13 million associated with certain severance and restructuring costs; and (v) lower non-cash revenues of $21.5 million within our offshore pipeline transportation and onshore facilities and transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts. Additionally, the 2019 Quarter included positive changes in estimated abandonment costs for certain of our non-operating offshore gas assets of $15.7 million (which is includedrecorded within "offshore pipeline transportation operating costs" on the Unaudited Condensed Consolidated Statements of Operations), and an increase in equity in earnings of equity investees of $6.7 million.. These decreases were partially offset by higher depreciation, depletion,cancellation of debt income of $18.5 million associated with the open market repurchase and amortizationextinguishment of certain of our senior unsecured notes and lower interest expense of $1.7 million and an unrealized loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred units of $4.7$3.9 million during the 2019 Quarter compared to an unrealized loss of $0.2 million during the 20182020 Quarter.
Cash flow from operating activities was $62.6 million for the 2020 Quarter compared to $81.6 million for the 2019 Quarter compared to $64.5 million for the 2018 Quarter. This increasedecrease is primarily attributable to our increase inlower segment margin during the 2019 Quarter.2020 Quarter partially offset by positive working capital changes.
Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") to our common unitholders was $93.5$50.4 million for the 20192020 Quarter, a decrease of $7.5$43.1 million, or 7.5%46.1%, from the 2018 Quarter. Available Cash before Reserves for the 2019 Quarter, is inclusive of the $18.7 million declared cash distributionprimarily due to a decline in our preferred unitholders that is attributable to the 2019 Quarter and will be paid on August 14, 2019.reported Segment Margin. 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 $184.1$139.3 million for the 20192020 Quarter, an increasea decrease of $10.3$44.8 million, or 6%24%, from the 20182019 Quarter. A more detailed discussion of our segment results and other costs is included below in "Results of Operations".
        See “Non-GAAP Financial Measures” below for additional information on Available Cash before Reserves and Segment Margin.
Distribution
In July 2019,2020, we declared our quarterly distribution to our common unitholders of $0.55$0.15 per unit related to the 20192020 Quarter. With respect to our Class A Convertible Preferred Units, (our "preferred units"), we declared a quarterly cash distribution of $0.7374 per preferred unitClass A Convertible Preferred Unit (or $2.9496 on an annualized basis) for each preferred unitClass A Convertible Preferred Unit held of record. These distributions will be payable on August 14, 20192020 to unitholders of record at the close of business on July 31, 2019.2020.


32
Table of Contents
 

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.
        Covid-19 has caused commodity prices to decline due to, among other things, reduced industrial activity and travel restrictions that are expected to continue in the near future. Additionally, actions taken by OPEC and other oil exporting nations beginning in early March 2020 caused additional significant declines and volatility in the price of oil and gas. These low and volatile commodity prices are expected to continue at least for the near-term and possibly longer, reflecting fears of a global recession and potential further global economic damage from Covid-19, including factory shutdowns, travel bans, closings of schools and stores, and cancellations of conventions and similar events, resulting in, among other things, reduced fuel demand, lower manufacturing activity, and high inventories of oil, natural gas, and petroleum products, which could further negatively impact oil, natural gas, and petroleum products and industrial products.
        Due to the economic effects from commodity prices and Covid-19, demand and volumes throughout our businesses were negatively impacted during the 2020 Quarter (which is further discussed in Results from Operations on a segment by segment basis). As a result of lower current demand and the outlook for our crude-by-rail logistics assets, and rail becoming an uneconomic means of transportation for producers to get crude oil to their refineries, we recorded a non-cash impairment charge of $277.5 million in our onshore facilities and transportation segment. We will continue to monitor the market environment and will evaluate whether additional 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 further deteriorate, we may identify additional 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 further impairment charges that could be material to our results of operations.
Although the potential future limitations and impact of Covid-19 are still unknown at this time, and although we tend to experience less demand for certain of our services and products when commodity prices decrease significantly over extended periods of time (and we expect a similar impact on demand when global restrictions are in place limiting the economy and industrial product use), we believe the fundamentals of our core businesses continue to remain strong and, given the current industry environment and capital market behavior, we have continued our focus on de-leveraging our balance sheet, which included the reduction of our distribution to common unitholders. We also took the opportunity to repurchase certain of our senior unsecured notes on the open market for a gain of $18.5 million during the 2020 Quarter, which allowed us to reduce our overall outstanding indebtedness and related interest charges. Additionally, given the current operating environment and our overall cost savings initiative, we recorded a one-time charge of approximately $13 million associated with certain severance and restructuring expenses. During April 2020, we also amended our agreements with GSO associated with the expansion of our Granger soda ash facility to, among other things, extend the construction timeline of the project by as much as one year.



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Results of Operations
Revenues and Costs and Expenses
Our revenues for the 20192020 Quarter decreased $117.6$246.3 million, or 16%39%, from the 2018 Quarter. In addition,2019 Quarter and our total costs and expenses (excluding impairment expense) as presented on the Unaudited Condensed Consolidated Statements of Operations decreased $143.7$158.6 million, or 21%29%, between the two periods.periods, with a net change to our operating income of $87.7 million. During the 20192020 Quarter, we reported an increasea decrease in segment margin of $10.3$44.8 million, relativean increase to general and administrative expenses primarily due to a one-time charge of approximately $13 million associated with certain severance and restructuring expenses, and an increase to offshore pipeline transportation operating costs of $12.3 million, which is primarily due to the 20182019 Quarter and a reductionincluding positive changes in our estimated abandonment costs for certain of our non-operating offshore gas assets of $15.7 million, which is includedmillion. Additionally, non-cash revenues within our offshore pipeline transportation operating costs. In additionand onshore facilities and transportation segments were $21.5 million lower in the 2020 Quarter due to these items,how we recognize recognize in accordance with GAAP on certain contracts. We describe the impact on revenues and costs from each of our businesses below.
A substantial portion of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products in our legacycrude oil marketing business, which is included in the onshore facilities and transportation segment, and revenues and costs associated with our Alkali Business, which is included in the sodium minerals and sulfur services segment. The decrease in our revenues and our costs in this segmentand expenses between the 20192020 Quarter and the 20182019 Quarter is primarily attributable toto: (i) decreases in crude oil and petroleum product prices and, to an extent, sales volumes. Thevolumes; and (ii) lower sales volumes in our sodium minerals and sulfur services segment due to lower economic and market demand as a result of Covid-19 and lower contractual export pricing as it relates to our Alkali Business.
        As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased 11.9%53% to $27.85 per barrel in the 2020 Quarter, as compared to $59.79 per barrel in the 2019 Quarter, as comparedQuarter. Additionally, impacts from Covid-19 along with actions taken by OPEC and other oil exporting nations beginning in early March 2020 caused additional significant price declines and volatility in oil and gas prices. These low and volatile commodity prices are expected to $67.85 per barrel incontinue at least for the 2018 Quarter.near term and possibly longer. We would expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil and petroleum products, producing minimal direct impact on Segment Margin, Net Income, and Available Cash before Reserves. We have limited our direct commodity price exposure related to crude oil and petroleum products through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller net impact on our Segment Margin. However, we do have some indirect exposure to certain changes in prices for 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 Related to Our Business."
        As it relates to our Alkali Business, our revenues are derived from the extraction of trona, as well as the activities surrounding the processing and sale of natural soda ash and other alkali specialty products, including sodium sesquicarbonate (S-Carb) and sodium bicarbonate (Bicarb), and are a function of our selling prices and volume sold. We sell our products to an industry-diverse and worldwide customer base. Our selling prices are contracted at various times throughout the year and for different durations. Typically, our selling prices for volumes sold internationally and through ANSAC are contracted for the current year (in a majority of cases, annually) in the prior December and January of the current year, and our volumes priced and sold domestically are contracted at various times and can be of varying durations, often multi-year terms. Our sales volumes can fluctuate from period to period and are dependent upon many factors, of which the main drivers are the global market, customer demand and economic growth. Positive or negative changes to our revenue, through fluctuations in sales volumes or selling prices, can have a direct impact to Segment Margin, Net Income and Available Cash before Reserves as these fluctuations have a lesser impact to operating costs due to the fact that a portion of our costs are fixed in nature. Our costs, of which some are variable in nature and others are fixed in nature, relate primarily to the processing and producing of soda ash (and other alkali specialty products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore, including energy costs and employee compensation. In our Alkali Business, during the 2020 Quarter as noted above, we had negative effects to our revenues (with a lesser impact to costs) due to lower export pricing and lower sales volumes of soda ash during the 2020 Quarter as a result of lower economic and market demand. For additional information, see our segment-by-segment analysis below.
In addition to our legacycrude oil marketing business and Alkali Business discussed above, we continue to operate in our other core businesses including: (i) our offshore Gulf of Mexico crude oil and natural gas pipeline transportation and handling operations, focusing on integrated and large independent energy companies who make intensive capital investments (often in excess of billions of dollars) to develop numerous large reservoir, long-lived crude oil and natural gas properties; (ii) our sodium minerals and sulfur
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services businesses, which includes our Alkali Business,business, which is one of the leading producers and marketers of natural soda ash worldwide,NaHS in North and our legacy sulfur removal business;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 approximatelyover 95% of the volumes transported on our onshore crude pipelines, and refiners contract for over 90% 80% 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 whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Their large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in relatively low commodity price 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.
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 2019 Quarter and the 2018 Quarter was as follows:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
 (in thousands)(in thousands)
Offshore pipeline transportation$75,148  $76,528  $160,394  $152,918  
Sodium minerals and sulfur services24,824  57,705  61,765  116,344  
Onshore facilities and transportation21,215  35,920  49,314  61,523  
Marine transportation18,138  13,959  37,140  26,891  
Total Segment Margin$139,325  $184,112  $308,613  $357,676  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
 (in thousands) (in thousands)
Offshore pipeline transportation$76,528
 $71,602
 $152,918
 $144,775
Sodium minerals and sulfur services57,705
 64,542
 116,344
 128,933
Onshore facilities and transportation35,920
 25,744
 61,523
 47,433
Marine transportation13,959
 11,966
 26,891
 22,953
Total Segment Margin$184,112
 $173,854
 $357,676
 $344,094
We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of 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 Income (Loss) Attributable to Genesis Energy, L.P. for the periods presented is as follows:
 Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
Total Segment Margin$139,325  $184,112  $308,613  $357,676  
Corporate general and administrative expenses(24,867) (13,502) (31,359) (24,602) 
Depreciation, depletion, amortization and accretion(82,580) (66,104) (158,558) (146,041) 
Interest expense(51,618) (55,507) (106,583) (111,208) 
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(5,776) (5,675) (12,182) (10,503) 
Other non-cash items (2)
(23,291) (11,012) 8,777  (17,103) 
Cash payments from direct financing leases in excess of earnings(2,294) (2,079) (4,532) (4,107) 
Cancellation of debt income18,532  —  19,725  —  
Provision for leased items no longer in use(58) 182  72  372  
Differences in timing of cash receipts for certain contractual arrangements (3)
(11,638) 9,848  (16,128) 12,135  
Loss on debt extinguishment (4)
—  —  (23,480) —  
Impairment expense(277,495) —  (277,495) —  
Redeemable noncontrolling interest redemption value adjustments (5)
(4,159) —  (8,245) —  
Income tax expense(795) (143) (430) (545) 
Net Income (Loss) Attributable to Genesis Energy, L.P.$(326,714) $40,120  $(301,805) $56,074  
(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)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 associated with our Class A Convertible Preferred Units. The three and six months ended June 30, 2019 include a $4.7 million unrealized loss and $7.7 million unrealized loss, respectively, from the valuation of the embedded derivative.
(3)Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts.
(4)Includes our transaction costs associated with the tender of $527.9 million and redemption of $222.1 million of our 2022 Notes in the first quarter of 2020, along with the write-off of our unamortized issuance costs and discount associated with these notes.
(5) Includes PIK distributions attributable to the period and accretion on the redemption feature.

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 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Total Segment Margin$184,112
 $173,854
 $357,676
 $344,094
Corporate general and administrative expenses(13,502) (13,466) (24,602) (23,926)
Depreciation, depletion, amortization and accretion(66,104) (79,862) (146,041) (157,870)
Interest expense(55,507) (57,909) (111,208) (114,045)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(5,675) (10,037) (10,503) (19,094)
Other non-cash items(11,012) (638) (17,103) (6,775)
Cash payments from direct financing leases in excess of earnings(2,079) (1,884) (4,107) (3,723)
Non-cash provision for leased items no longer in use182
 47
 372
 (139)
Differences in timing of cash receipts for certain contractual arrangements (2)
9,848
 1,148
 12,135
 4,479
Loss on debt extinguishment—
 —
 —
 (3,339)
Income tax expense(143) (256) (545) (631)
Net Income Attributable to Genesis Energy, L.P.$40,120
 $10,997
 $56,074
 $19,031
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(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)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.


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,		 Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
(in thousands) (in thousands) (in thousands)(in thousands)
Offshore crude oil pipeline revenue, excluding non-cash revenues$59,976
 $56,672
 $124,170
 $113,805
Offshore crude oil pipeline revenue, excluding non-cash revenues$61,003  $59,976  $130,584  $124,170  
Offshore natural gas pipeline revenue, excluding non-cash revenues13,415
 12,024
 24,348
 24,684
Offshore natural gas pipeline revenue, excluding non-cash revenues10,302  13,415  23,639  24,348  
Offshore pipeline operating costs, excluding non-cash expenses(17,159) (15,180) (33,238) (30,803)Offshore pipeline operating costs, excluding non-cash expenses(14,010) (17,159) (31,742) (33,238) 
Distributions from equity investments (1)
20,296
 18,086
 37,638
 37,089
Distributions from equity investments (1)
17,853  20,296  37,913  37,638  
Offshore pipeline transportation Segment Margin$76,528
 $71,602
 $152,918
 $144,775
Offshore pipeline transportation Segment Margin$75,148  $76,528  $160,394  $152,918  
       
Volumetric Data 100% basis:       Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):       Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS228,931
 181,291
 235,307
 190,455
CHOPS196,962  228,931  219,572  235,307  
Poseidon264,802
 225,559
 259,167
 232,090
Poseidon253,341  264,802  266,261  259,167  
Odyssey150,039
 90,326
 150,953
 99,793
Odyssey114,006  150,039  133,375  150,953  
GOPL (2)
11,990
 9,110
 10,173
 9,431
GOPL (3)
GOPL (3)
2,631  11,990  4,940  10,173  
Total crude oil offshore pipelines655,762
 506,286
 655,600
 531,769
Total crude oil offshore pipelines566,940  655,762  624,148  655,600  
       
Natural gas transportation volumes (MMBtus/d)445,734
 431,853
 432,888
 453,910
Natural gas transportation volumes (MMBtus/d)329,876  445,734  375,283  432,888  
       
Volumetric Data net to our ownership interest (2):
       
Volumetric Data net to our ownership interest (2):
Crude oil pipelines (average barrels/day unless otherwise noted):       Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS228,931
 181,291
 235,307
 190,455
CHOPS196,962  228,931  219,572  235,307  
Poseidon169,473
 144,358
 165,867
 148,538
Poseidon162,138  169,473  170,407  165,867  
Odyssey43,511
 26,195
 43,776
 28,940
Odyssey33,062  43,511  38,679  43,776  
GOPL (3)
11,990
 9,110
 10,173
 9,431
GOPL (3)
2,631  11,990  4,940  10,173  
Total crude oil offshore pipelines453,905
 360,954
 455,123
 377,364
Total crude oil offshore pipelines394,793  453,905  433,598  455,123  
       
Natural gas transportation volumes (MMBtus/d)174,490
 156,412
 167,748
 169,887
Natural gas transportation volumes (MMBtus/d)106,919  174,490  127,695  167,748  
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2019 and 2018, respectively.
(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.
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2020 and 2019, respectively.
(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 June 30, 20192020 Compared with Three Months Ended June 30, 20182019
Offshore pipeline transportation Segment Margin for the 20192020 Quarter increased $4.9decreased $1.4 million, or 7%2%, from the 20182019 Quarter, primarily due to higherlower volumes on our crude oil and natural gas pipeline systems. These increasedlower volumes are attributable to planned downtime, which in some cases was extended due to the result of: (i)economic environment, certain producer shut-ins (specifically in May) that impacted the continued receipt of additional volumesthroughput on our CHOPScrude oil systems, and Poseidon systems due to deliveriesweather interruptions from a third party pipeline that had insufficient capacity to deliver its committedTropical Storm Cristobal. For the most part, the production from these fields came back online during June at or near their normal levels. These lower volumes to shore, and (ii) first oilwere almost fully offset by increased flow in the second half of the 2019 Quarter from the Buckskin and Hadrian North fields during the 2020 Quarter, which saw first production late in the 2019 Quarter. The Buckskin and Hadrian North fields are both of which are fully dedicated to our 100% owned SEKCO pipeline, and further downstream, our 64% owned Poseidon oil pipeline system. As the Buckskin and Hadrian North volumes noted above began near the end

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Table of the 2019 Quarter, contributions to segment margin were minimal in the period. However, we expect the contributions to increase throughout the remainder of 2019 and beyond. These increased volumes during the 2019 Quarter more than offset the approximately $3.9 million in platform fees, related to our interest in Poseidon Oil Pipeline, LLC ("Poseidon"), that we received during the 2018 Quarter. These minimum bill payments ended during June 2018.Contents


Six Months Ended June 30, 20192020 Compared with Six Months Ended June 30, 20182019
Offshore pipeline transportation Segment Margin for the first six months of 20192020 increased $8.1$7.5 million, or 6%5%, from the first six months of 2018,2019, primarily due to higher volumes on our crude oil pipeline systems. These increased volumes are the result of: (i) the continued receipt of additional volumes on our CHOPS and Poseidon systems due to deliveries from a third party pipeline that had insufficient capacity to deliver its committed volumes to shore, and (ii) first oil flow in the second half of June 2019flowing from the Buckskin and Hadrian North production fields (which had first oil towards the end of the 2019 Quarter), which both areis fully dedicated to our 100% owned SEKCO pipeline, and further downstream, our 64% owned Poseidon oil pipeline system. As the Buckskin and Hadrian NorthThis increase was partially offset by lower volumes noted above began near the end of the 2019 Quarter, contributions to segment margin were minimal in 2019. However, we expect the contributions to increase throughout the remainder of 2019 and beyond. Additionally, the first six months of 2018 was negatively impacted by a significant amount of temporary downtime on certain lateralsof our other crude oil and the underperformance of several major oilfieldsnatural gas pipelines during 2020, primarily in the deepwater Gulf of Mexico. These increased volumes duringsecond quarter, due to planned downtime, weather interruptions, and producer shut-ins. For the first half of 2019 more than offsetmost part, the approximately $7.8 million in platform fees, related to our interest in Poseidon, that we received during the first six months of 2018. These minimum bill payments endedproduction from these fields came back online during June 2018.at or near their normal levels.

Sodium Minerals and Sulfur Services Segment
Operating results for our sodium minerals and sulfur services segment were as follows:
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
Volumes sold:       Volumes sold:
NaHS volumes (Dry short tons "DST")34,527
 38,090
 70,270
 75,304
NaHS volumes (Dry short tons "DST")21,942  34,527  52,024  70,270  
Soda Ash volumes (short tons sold)824,881
 936,000
 1,695,410
 1,853,000
Soda Ash volumes (short tons sold)594,810  824,881  1,417,057  1,695,410  
NaOH (caustic soda) volumes (dry short tons sold)20,525
 27,573
 41,327
 57,833
NaOH (caustic soda) volumes (dry short tons sold)20,326  20,525  36,629  41,327  
Total879,933
 1,001,663
 1,807,007
 1,986,137
       
Revenues (in thousands):       Revenues (in thousands):
NaHS revenues, excluding non-cash revenues$41,054
 $45,884
 $84,002
 $89,240
NaHS revenues, excluding non-cash revenues$23,326  $41,054  $56,517  $84,002  
NaOH (caustic soda) revenues10,745
 16,111
 22,558
 31,978
NaOH (caustic soda) revenues8,644  10,745  16,085  22,558  
Revenues associated with Alkali Business200,871
 207,121
 404,201
 412,004
Revenues associated with Alkali Business141,898  200,871  318,134  404,201  
Other revenues1,325
 2,082
 2,941
 3,434
Other revenues462  1,325  1,105  2,941  
Total external segment revenues, excluding non-cash revenues$253,995
 $271,198
 $513,702
 $536,656
Total external segment revenues, excluding non-cash revenues(1)
Total external segment revenues, excluding non-cash revenues(1)
$174,330  $253,995  $391,841  $513,702  
       
Segment Margin (in thousands)$57,705
 $64,542
 $116,344
 $128,933
Segment Margin (in thousands)$24,824  $57,705  $61,765  $116,344  
       
Average index price for NaOH per DST(1)
$697
 $795
 $707
 $772
Average index price for NaOH per DST(2)
Average index price for NaOH per DST(2)
$698  $697  $673  $707  
(1) Totals are for external revenues and costs prior to intercompany elimination upon consolidation.
(2) Source: IHS Chemical.
Three Months Ended June 30, 20192020 Compared with Three Months Ended June 30, 20182019
Sodium minerals and sulfur services Segment Margin for the 20192020 Quarter decreased $6.8$32.9 million, or 11%.57% from the 2019 Quarter. This decrease is primarily due to lower volumes during the 2019 Quarter, including both our soda ash and refinery services businesses. Soda ash volumespricing in the 2019 Quarter were negatively impacted by longer than expected mine downtime due to hoist maintenance and repairs performed during the move of our longwall mining machine to a different section of our mine. Costs impacting the results of our Alkali Business manyand lower NaHS volumes in our refinery services business. During the 2020 Quarter, we experienced lower export pricing due to supply and demand imbalances that existed at the time of our re-contracting phase in December 2019 and January 2020, which are similar in natureis expected to costs relatedcontinue, to our sulfur removal business, include costs associatedsome extent, for at least the rest of 2020. This was coupled with processinglower ANSAC and producingdomestic sales volumes of soda ash (and other alkali products)during the 2020 Quarter due to the demand destruction from the worldwide economic shutdowns and marketinguncertainty from the pandemic, which we expect to continue until restrictions are lifted globally. During the 2020 Quarter, we also made the decision to cold stack our existing Granger facility, removing approximately 550,000 tons of annual soda ash production to facilitate balancing supply with the significantly reduced demand worldwide resulting from Covid-19. As currently configured, Granger is our highest cost production facility. While we could resume operations at Granger within a 3-6 month period subject to market requirements, it is our intent at this point to keep it in cold stack mode and selling activities.bring an optimized Granger facility, expanded to more than 1.2 million tons a year of production capacity, into full production mode in late 2023. Such optimized and expanded Granger facility will have production costs in-line with our Westvaco facility, which is one of the most economic soda ash production facilities in the world. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). Ourour refinery services business, continues to perform as expected.we experienced a decline in NaHS volumes slightly decreased during the 20192020 Quarter due to lower demand from certain of our internationalmining customers, primarily locatedboth domestically and in South America, and lower demand from our domestic pulp and paper customers. In South America (primarily in Peru), the lower volume demand is directly a result of customer shut-ins amidst the spread of Covid-19 and we expect these volumes to return to their normal levels later in 2020. Domestically, many of our pulp and paper customers' spring turnarounds and outages were pushed back or even

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cancelled due to Covid-19. We saw improvement near the end of the 2020 Quarter as it relates to these domestic customers with pulp mills back up and running at their normal capacity.

Six Months Ended June 30, 20192020 Compared with Six Months Ended June 30, 20182019
Sodium minerals and sulfur services Segment Margin for the first six months of 20192020 decreased $12.6$54.6 million, or 10% from the first six months of 2018.47%. This decrease is primarily due to lower volumes including bothand pricing in our Alkali Business and lower NaHS volumes in our refinery services business. In our Alkali Business, the six months ended June 30, 2020 was negatively impacted by lower export pricing due to supply and demand imbalances that existed at the time of our re-contracting phase in December 2019 and January 2020, which is expected to continue, to some extent, for at lease the rest of 2020. Demand for our soda ash volumes declined during 2020, primarily in the second quarter, as a result of economic shutdowns and refinery services businesses. Duringuncertainty from the first half of 2019, ourCovid-19 pandemic. We expect to see lower soda ash business experienced more downtime relative to 2018 due to certain planned maintenance activities (includingsales volumes in the planned replacementnext few quarters as a result of Covid-19 and upgrade of a heat exchanger and a move ofuntil restrictions are lifted globally. In our longwall mining machine) and a temporary electrical equipment failure during the first quarter that impacted our production volumes at our plant sites. Overall, the contributions from our Alkali Business have continued to exceed our expectations. Costs impacting the results of our Alkali Business, many of which are similar in nature to costs related to our sulfur removal business, include costs associated with processing and producing soda ash (and other alkali products) and marketing and selling activities. In addition, costs include activities associated with mining and extracting trona ore (including energy costs and employee compensation). Our refinery services business, continues to perform as expected.we experienced a decline in NaHS volumes slightly decreased during the first six months of 20192020 due to lower demand from our mining customers in South America as a result of customer shut-ins, primarily in Peru, due to the spread of Covid-19 and we expect these volumes to return to normal levels later in 2020, and further upon the economy restrictions being lifted globally. This decline was coupled with lower demand from certain of our international customers, primarily located in South America,domestic mining and our domestic pulp and paper customers.
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Onshore Facilities and Transportation Segment
Our onshore facilities and transportation segment utilizes an integrated set of pipelines and terminals, as well as trucks, railcars, and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals, rail facilities and CO2 pipelines operating primarily within the United States Gulf Coast crude oil 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;
•2 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;
•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. During the 2020 Quarter, crude oil price markets were in contango, and we were able to use our available capacity to profit from this strategy during the period.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills and assets to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.
In our refined products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.


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Operating results from our onshore facilities and transportation segment were as follows:
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
(in thousands) (in thousands) (in thousands)(in thousands)
Gathering, marketing, and logistics revenue$204,607
 $307,724
 $396,138
 $607,185
Gathering, marketing, and logistics revenue$59,830  $204,607  $195,137  $396,138  
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines17,157
 16,606
 34,252
 35,054
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines
Crude oil and CO2 pipeline tariffs and revenues from direct financing leases of CO2 pipelines
14,145  17,157  34,006  34,252  
Payments received under direct financing leases not included in income2,079
 1,884
 4,107
 3,723
Payments received under direct financing leases not included in income2,294  2,079  4,532  4,107  
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions(165,398) (282,020) (332,776) (559,912)Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions(42,783) (165,398) (154,277) (332,776) 
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses(18,271) (23,092) (36,989) (44,675)Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses(17,877) (18,271) (36,370) (36,989) 
Other(4,254) 4,642
 (3,209) 6,058
Other5,606  (4,254) 6,286  (3,209) 
Segment Margin$35,920
 $25,744
 $61,523
 $47,433
Segment Margin$21,215  $35,920  $49,314  $61,523  
       
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:
Texas47,229
 20,643
 45,117
 25,060
Texas62,261  47,229  73,380  45,117  
Jay10,171
 13,004
 10,823
 14,947
Jay5,067  10,171  7,540  10,823  
Mississippi6,032
 6,367
 5,974
 6,986
Mississippi4,883  6,032  5,646  5,974  
Louisiana (1)
131,456
 151,807
 113,738
 133,598
Louisiana (1)
62,537  131,456  112,637  113,738  
Wyoming (2)
—
 32,210
 —
 31,703
Onshore crude oil pipelines total194,888
 224,031
 175,652
 212,294
Onshore crude oil pipelines total134,748  194,888  199,203  175,652  
       
CO2 pipeline (average Mcf/day):
       
CO2 pipeline (average Mcf/day):
Free State76,297
 103,867
 91,062
 100,308
Free State94,282  76,297  114,558  91,062  
       
Crude oil and petroleum products sales:       Crude oil and petroleum products sales:
Total crude oil and petroleum products sales30,788
 49,278
 32,262
 50,818
Total crude oil and petroleum products sales21,874  30,788  23,996  32,262  
Rail unload volumes99,519
 53,005
 92,345
 52,844
Rail unload volumes4,150  99,519  49,095  92,345  
(1) Total daily volume for the three and six months ended June 30, 20192020 include 64,57428,851 and 58,47236,586 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. Total daily volume for the three and six months ended June 30, 20182019 includes 69,61464,574 and 55,05358,472 barrels per day respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
(2) Our Powder River Basin midstream assets were divested during the fourth quarter of 2018.
Three Months Ended June 30, 20192020 Compared with Three Months Ended June 30, 20182019
Onshore facilities and transportation Segment Margin for the 20192020 Quarter increased $10.2decreased by $14.7 million, or 40%. This increase is partially due to increased volumes at our Raceland and Scenic Station rail facilities during the 2019 Quarter. Our main customer associated with our Baton Rouge infrastructure exceeded the minimum take-or-pay volumes, including rail, terminal and pipeline movements, during40.9%, from the 2019 Quarter primarily due to a level that utilized and exceeded 100%the 2019 Quarter including the receipt of the prepaid transportation credits that accumulated during the first quarter of 2019. We also received a cash payment of $10 million during the 2019 Quarter associated with the resolution of a crude oil supply agreement. Additionally, whileduring the 2020 Quarter, we had lower volumes throughout our onshore facilities and transportation asset base, primarily in Louisiana at our Baton Rouge corridor assets and our Raceland rail facility. Due to the decline in crude oil prices and the collapse in the differential of Western Canadian Select (WCS) to the Gulf Coast, which has made crude-by-rail to the Gulf Coast uneconomic, the volumes onat our Texas system increased during the 2019 Quarter,Baton Rouge facilities were below our minimum take-or-pay levels and we were only able to recognize our minimum volume commitment because our main customer utilized some of its prepaid transportation credits. This was offset partially by thein segment margin recognized during the 2018 Quarter associated with2020 Quarter. We anticipate volumes will remain below our previously owned Powder River midstream assets thatminimum take-or-pay levels at our Baton Rouge facilities throughout the remainder of 2020. These lower volumes were divested inpartially offset by our ability to use our available crude oil storage capacity to profit on contango opportunities during the fourth quarter of 2018.

2020 Quarter.
Six Months Ended June 30, 20192020 Compared with Six Months Ended June 30, 20182019
        Onshore facilities and transportation Segment Margin for our onshore facilities and transportation segment increased by $14.1the six months ended June 30, 2020 decreased $12.2 million, or 30%19.8%, between the first six months of 2019 and the first six months of 2018. This increase is partiallyprimarily due to increased volumes at our Raceland and Scenic Station rail facilities during 2019 relative to 2018. Even after reflectingincluding the curtailments on production in Alberta in 2019, our Baton Rouge corridor assets still exceeded the contributions to Segment Margin from the first six monthsreceipt of 2018. We also received a cash payment of $10 million during 2019 associated with the resolution of a crude oil supply agreement. Additionally, althoughwe had lower rail unload volumes during 2020 at our Raceland rail facility. These decreases
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were partially offset by higher volumes on our Texas system, increased during the first halfwhich is capable of 2019, we were only able to recognize our minimum volume commitment because our main customer utilized some of its prepaid transportation credits. This was offset partially by the margin recognized during the 2018 Quarter associated with our previously owned Powder River midstream assetsreceiving and transporting barrels that were divestedoriginate in the fourth quarterGulf of 2018.Mexico, including our 100% owned CHOPS pipeline to markets in Webster and Texas City.

Marine Transportation Segment
Within our marine transportation segment, we own a fleet of 91 barges (82 inland and 9 offshore) with a combined transportation capacity of 3.2 million barrels, 42 push/tow boats (33 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows: 
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
Revenues (in thousands):       Revenues (in thousands):
Inland freight revenues$26,312
 $22,560
 $51,438
 $44,117
Inland freight revenues$25,805  $26,312  $53,377  $51,438  
Offshore freight revenues18,272
 17,557
 36,572
 34,060
Offshore freight revenues22,268  18,272  43,359  36,572  
Other rebill revenues (1)
14,122
 16,068
 27,346
 26,937
Other rebill revenues (1)
8,647  14,122  22,330  27,346  
Total segment revenues$58,706
 $56,185
 $115,356
 $105,114
Total segment revenues$56,720  $58,706  $119,066  $115,356  
       
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses$44,747
 $44,219
 $88,465
 $82,161
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses$38,582  $44,747  $81,926  $88,465  
       
Segment Margin (in thousands)$13,959
 $11,966
 $26,891
 $22,953
Segment Margin (in thousands)$18,138  $13,959  $37,140  $26,891  
       
Fleet Utilization: (2)
       
Fleet Utilization: (2)
Inland Barge Utilization98.7% 93.5% 97.7% 92.9%Inland Barge Utilization87.6 %98.7 %90.5 %97.7 %
Offshore Barge Utilization93.9% 92.0% 95.1% 93.4%Offshore Barge Utilization96.8 %93.9 %98.1 %95.1 %
(1) Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.
(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and dry-docking.
Three Months Ended June 30, 20192020 Compared with Three Months Ended June 30, 20182019
Marine transportation Segment Margin for the 20192020 Quarter increased $2.0$4.2 million, or 17%30%, from the 20182019 Quarter. This increaseDuring the 2020 Quarter, in Segment Margin is primarily attributable to higher inland andour offshore barge utilization duringoperation, we benefited from the 2019 Quarter along with an increase in average daycontinual improving rates in the market that have been advantageous in both spot and short term contracts. Whilemarkets coupled with increased utilization relative to the 2019 Quarter. In our inland business, we have seen a slight uptick incontinued to see increased day rates wethroughout the period which offset the lower utilization. We expect to see continued pressure on our utilization, and to an extent, the spot rates in our inland business as refineries continue to lower their utilization rates to better 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) in both the inland and offshore markets because we believe the day rates currently being offered by the market are still nearhave yet to fully recover from their cyclical lows. This was partially offset by an increase in operating costs during the 2019 Quarter relative to the 2018 Quarter due to an increase in dry-docking costs in both our inland and offshore fleet.
Six Months Ended June 30, 20192020 Compared with Six Months Ended June 30, 20182019
Marine transportation Segment Margin for the first six months of 2019ended June 30, 2020 increased $3.9$10.2 million, or 17%,38%. During 2020, in our offshore barge operation, we benefited from the first six months of 2018. The increase in Segment Margin is primarily attributable to higher inland and offshore barge utilization and an increase in average daycontinual improving rates in the market that have been advantageous in both spot and short term contracts. Whilemarkets coupled with increased utilization relative to 2019. In our inland business, we have seen a slight uptick incontinued to see increased day rates wethroughout the period which offset the lower utilization. We expect to see continued pressure on our utilization, and to an extent, the spot rates on our inland business as refineries continue to lower their utilization rates to better 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) in both the inland and offshore markets because we believe the day rates currently being offered by the market are still nearhave yet to fully recover from their cyclical lows. These increases were partially offset by an increase in operating costs during 2019 due to an increase in our dry-docking costs in both our inland and offshore fleet.







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Other Costs, Interest, and Income Taxes
General and administrative expenses
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2019 2018 2019 2018 2020201920202019
(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$11,048
 $8,612
 $20,528
 $17,286
Corporate$23,364  $11,048  $34,157  $20,528  
Segment1,059
 579
 2,218
 1,716
Segment1,073  1,059  2,138  2,218  
Long-term incentive compensation expense964
 1,442
 1,894
 1,618
Long-term incentive compensation expense955  964  (1,530) 1,894  
Third party costs related to business development activities and growth projects341
 2,896
 458
 4,583
Third party costs related to business development activities and growth projects21  341  21  458  
Total general and administrative expenses$13,412
 $13,529
 $25,098
 $25,203
Total general and administrative expenses$25,413  $13,412  $34,786  $25,098  

Three Months Ended June 30, 2020 Compared with Three Months Ended June 30, 2019
Total general and administrative expenses decreased by $0.1 million for the three2020 Quarter increased by $12.0 million primarily due to the effects of a one-time charge of approximately $13 million related to certain severance and six month periods.restructuring expenses incurred during the period. This decrease is primarily attributable towas partially offset by lower third party transaction costs associated with business development activities and growth projects during the 2020 Quarter.
Six Months Ended June 30, 2020 Compared with Six Months Ended June 30, 2019 as 2018 included
Total general and administrative expenses for the six months ended June 30, 2020 increased by $9.7 million primarily due to the effects of a one-time charge of approximately $13 million related to certain severance and restructuring expenses incurred during the acquisition and integration of our Alkali Business.period. This decrease was almost fullypartially offset by higher corporate generallower long-term incentive compensation (LTIP) expense due to the effect of changes in assumptions used to value our outstanding LTIP awards and administrative costs.lower third party costs associated with business development activities and growth projects during 2020.

Depreciation, depletion, and amortization expense
Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
 (in thousands)(in thousands)
Depreciation and depletion expense$75,930  $74,171  $146,135  $147,162  
Amortization expense4,190  4,812  8,342  9,101  
Amortization of CO2 volumetric production payments
—  370  —  728  
Total depreciation, depletion and amortization expense$80,120  $79,353  $154,477  $156,991  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
 (in thousands) (in thousands)
Depreciation and depletion expense$74,171
 $71,890
 $147,162
 $141,455
Amortization of intangible assets4,812
 5,461
 9,101
 10,894
Amortization of CO2 volumetric production payments
370
 329
 728
 586
Total depreciation, depletion and amortization expense$79,353
 $77,680
 $156,991
 $152,935
Three Months Ended June 30, 2020 Compared with Three Months Ended June 30, 2019
        Total depreciation, depletion, and amortization expense for the 2020 Quarter increased by $0.8 million. This increase is primarily due to additional assets being placed into service during the 2020 Quarter, partially offset by a decline in amortization expense during the period.
Six Months Ended June 30, 2020 Compared with Six Months Ended June 30, 2019
Total depreciation, depletion, and amortization expense increased $1.7for the six months ended June 30, 2020 decreased $2.5 million primarily due to the six months ended June 30, 2019 including an increase in depreciation charges associated with one of our non-core gas offshore assets in which the abandonment timing was accelerated and $4.1 million betweenhigher amortization expense. This was partially offset by an overall increase in our depreciable asset base due to our continued growth and maintenance capital
expenditures and placing new assets into service during 2019 and 2020.

Impairment Expense
As previously discussed, during the three and six month periods, respectively, primarily as a resultmonths ended June 30, 2020, we recorded impairment expense of placing additional$277.5 million associated with the rail logistics assets into service that were completed during 2019.included within our onshore facilities and transportation segment.
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Interest expense, net
Three Months Ended
June 30,		Six Months Ended
June 30,
 2020201920202019
 (in thousands)(in thousands)
Interest expense, senior secured credit facility (including commitment fees)$9,664  $14,304  $20,409  $28,462  
Interest expense, senior unsecured notes40,202  39,547  82,560  79,094  
Amortization of debt issuance costs and discount2,200  2,688  4,591  5,370  
Capitalized interest(448) (1,032) (977) (1,718) 
Net interest expense$51,618  $55,507  $106,583  $111,208  
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
 (in thousands) (in thousands)
Interest expense, senior secured credit facility (including commitment fees)$14,304
 $16,347
 $28,462
 $30,441
Interest expense, senior unsecured notes39,547
 39,547
 79,094
 80,081
Amortization of debt issuance costs and discount2,688
 2,659
 5,370
 5,569
Capitalized interest(1,032) (644) (1,718) (2,046)
Net interest expense$55,507
 $57,909
 $111,208
 $114,045

Three Months Ended June 30, 20192020 Compared with Three Months Ended June 30, 20182019
Net interest expense for the 2020 Quarter decreased $2.4$3.9 million during the 2019 Quarter primarily due to a lower average outstanding balanceinterest rate on our revolving credit facility during the 2019period. The decline in our interest rate during the 2020 Quarter is due to the decrease in LIBOR rates during the 2020 Quarter, which wasis one of the main drivers of interest expense on our credit facility. Additionally, we repurchased $86.2 million of our senior unsecured notes on the open market during the 2020 Quarter for a gain of $18.5 million, which reduced our overall outstanding indebtedness and interest expense during the period.
These decreases were partially offset by an increase in LIBOR rates relative tohigher interest expense on our senior unsecured notes and lower capitalized interest during the 20182020 Quarter.

On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75%, and we purchased and extinguished $527.9 million of our $750 million 2022 Notes that accrued interest at 6.75% on January 15, 2020 through a tender offer and we redeemed the remaining $222.1 million of our 2022 Notes on February 16, 2020.
Six Months Ended June 30, 20192020 Compared with Six Months Ended June 30, 20182019
Net interest expense decreased $2.8 million duringfor the first six months of 2019ended June 30, 2020 decreased by $4.6 million primarily due to a lower average outstanding balanceinterest rate on our revolving credit facility during the period which was partially offset by an increaseperiod. The decline in our interest rate during 2020 is due to the decrease in LIBOR rates relative toduring the first six monthsperiod, which is one of 2018. Additionally, during 2018, we recorded $1.0 millionthe main drivers of interest expense on our previously held 2021credit facility. Additionally, we repurchased $86.2 million of our senior unsecured notes on the open market during the 2020 Quarter for a gain of $18.5 million, which reduced our overall outstanding indebtedness and interest expense during 2020.
These decreases were partially offset by higher interest expense on our senior unsecured notes and lower capitalized interest during the 2020 Quarter. On January 16, 2020, we issued our $750 million 2028 Notes that accrue interest at 7.75%, and we purchased and extinguished $527.9 million of our $750 million 2022 Notes that accrued interest at 6.75% on January 15, 2020 through a tender offer and we redeemed inthe remaining $222.1 million of our 2022 Notes on February 2018.16, 2020.
 Income tax expense
A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

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Liquidity and Capital Resources
General
As of June 30, 2019,2020, our balance sheet and liquidity position remained strong, including $731.9$645.9 million of remaining borrowing capacity under our $1.7$1.7 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.
Our primary cash requirements consist of:
•working capital, primarily inventories and trade receivables and payables;
•routine operating expenses;
•capital growth and maintenance projects;
•acquisitions of assets or businesses;
•payments related to servicing and reducing outstanding debt; and
•quarterly cash distributions to our preferred and common unitholders.
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 necessary funds on satisfactory terms or implement our growth strategy successfully.
At June 30, 2019,2020, our long-term debt totaled approximately $3.4 billion, consisting$3,432.6 million, which is a reduction of $1.0 billion$8.0 million sequentially from March 31, 2020, and consists of $1,053.0 million outstanding under our credit facility (including $30.3$32.3 million borrowed under the inventory sublimit tranche) and $2.5 billion$2,379.6 million of senior unsecured notes, comprising $750 million carrying amount due August 1, 2022, $400$395.9 million carrying amount due on May 15, 2023, $350$337.7 million carrying amount due on June 15, 2024, $550$529.3 million carrying amount due October 2025, and $450$401.8 million carrying amount due May 2026.2026, and $714.9 million carrying amount due February 15, 2028. Given the market conditions during the 2020 Quarter, we took the opportunity to repurchase approximately $86.2 million of our senior unsecured notes on the open market in exchange for $67.7 million, which was borrowed under our credit facility, and reduced our total indebtedness by $18.5 million.
        On September 23, 2019, we announced the expansion of our existing Granger facility (the "Granger Optimization Project" or "GOP"). We entered into agreements with GSO for the purchase of up to approximately $350 million of preferred units of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. The extended completion date of the project is anticipated in mid to late 2023. The Alkali Holdings preferred unitholders will receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of June 30, 2020 we had issued 131,750 Alkali Holdings preferred units for the construction. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.
Equity Distribution Program and Shelf Registration Statements
We expect to issue additional equity and debt securities in the future to assist us in meeting our future liquidity requirements, particularly those related to opportunistically acquiring assets and businesses and constructing new facilities and refinancing outstanding debt.
In 2016, we implemented an equity distribution program that will allow us to consummate “at the market” offerings of common units from time to time through brokered transactions, which should help mitigate certain adverse consequences of underwritten offerings, including the downward pressure on the market price of our common units and the expensive fees and other costs associated with such public offerings. We entered into an equity distribution agreement with a group of banks who will act as sales agents or principals for up to $400.0 million of our common units, if and when we should elect to issue additional common units from time to time, although there are limits to the amount of our “at the market” offerings the market can absorb from time to time.transactions. In connection with implementing our equity distribution program, we filed a universal shelf registration statement (our "EDP Shelf") with the SEC. Our EDP Shelf allows us to issue up to $1.0 billion of equity and debt securities, whether pursuant to our equity distribution program or otherwise. Our EDP Shelf will expire in October 2020. As of June 30, 2019,2020, we had issued no units under this program.

We have another universal shelf registration statement (our "2018 Shelf") on file with the SEC. Our 2018 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2018 Shelf will expire in April 2021. We expect to file a replacement universal shelf registration statement before our 2018 Shelf expires.
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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 acquire it, so we do not need to rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem, as we make payments and receive payments for the purchase and sale of crude oil.
In our petroleum products onshore facilities and transportation activities, we purchase products and typically either move those products to one of our storage facilities for further blending or sell those products within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.
In our Alkali Business, we typically extract trona from our mining facilities, process it into soda ash and other alkali products, and deliver and sell the alkali products to our customers all within a relatively short time frame. If we do experience any differences in timing of extraction, processing and sales of our trona or alkali products, it could impact the cash requirements for these activities in the short term.
The storage of our inventory of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the crude oil or petroleum products, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, we may be required to deposit margin funds with the NYMEX when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.
 See Note 14 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the six months ended June 30, 20192020 and June 30, 2018.2019.
Net cash flows provided by our operating activities for the six months ended June 30, 20192020 were $195.6$152.2 million compared to $150.8$195.6 million for the six months ended June 30, 2018.2019. This increase in operating cash flowdecrease is primarily dueattributable to an increase in overalllower segment margin and transactions costs incurred during 20192020 associated with the tender and higher distributions from equity investees during 2019 that were classified as operating.redemption of our previously held 2022 Notes, partially offset by positive changes in working capital.
Capital Expenditures, Distributions and Certain Cash Requirements
We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, organic growth projects, maintenance capital expenditures and distributions we pay to our preferred and common unitholders. We finance maintenance capital expenditures and smaller organic growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and organic growth projects) with borrowings under our credit facility, equity issuances and/or issuances of senior unsecured notes. We currently plan to allocate a substantial portion of our excess cash flow to reduce the balance outstanding under our revolving credit facility.facility and to opportunistically repurchase our outstanding senior unsecured notes.

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Capital Expenditures
A summary of our expenditures for fixed assets, business and other asset acquisitions for the six months ended June 30, 20192020 and June 30, 20182019 is as follows:
Six Months Ended
June 30,
 20202019
 (in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets$2,097  $2,942  
Sodium minerals and sulfur services assets12,051  21,581  
Marine transportation assets17,725  16,924  
Onshore facilities and transportation assets1,618  1,132  
Information technology systems99  672  
Total maintenance capital expenditures33,590  43,251  
Growth capital expenditures:
Offshore pipeline transportation assets913  37  
Sodium minerals and sulfur services assets36,386  27,262  
Marine transportation assets—  —  
Onshore facilities and transportation assets368  2,652  
Information technology systems2,515  1,226  
Total growth capital expenditures40,182  31,177  
Total capital expenditures$73,772  $74,428  
 Six Months Ended
June 30,
 2019 2018
 (in thousands)
Capital expenditures for fixed and intangible assets:   
Maintenance capital expenditures:   
Offshore pipeline transportation assets$2,942
 $1,432
Sodium minerals and sulfur services assets21,581
 21,130
Marine transportation assets16,924
 8,665
Onshore facilities and transportation assets1,132
 886
Information technology systems672
 64
Total maintenance capital expenditures43,251
 32,177
Growth capital expenditures:   
Offshore pipeline transportation assets37
 669
Sodium minerals and sulfur services assets27,262
 7,129
Marine transportation assets—
 12,014
Onshore facilities and transportation assets2,652
 34,973
Information technology systems1,226
 2,647
Total growth capital expenditures31,177
 57,432
Total capital expenditures for fixed and intangible assets$74,428
 $89,609
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We continue to pursue a long-term growth strategy that may require significant capital.
Growth Capital Expenditures
        On September 23, 2019, we announced the Granger Optimization Project. We entered into agreements with GSO for the purchase of up to approximately $350 million of preferred units (or 350,000 preferred units) of Alkali Holdings. The proceeds received from GSO will fund up to 100% of the anticipated cost of the GOP. On April 14, 2020, we entered into an amendment to our agreements with GSO to, among other things, extend the construction timeline of the Granger expansion project by one year. The extended completion date of the project is anticipated in mid to late 2023. We issued 1,750 preferred units to GSO in consideration for the amendment. The Alkali Holdings preferred unitholders will receive PIK distributions in lieu of cash distributions during the new anticipated construction period. As of June 30, 2020 we had issued 131,750 Alkali Holdings preferred units for the construction. The expansion is expected to increase our production at the Granger facilities by approximately 750,000 tons per year.
        Except for the Granger Optimization Project, we do not anticipate spending material growth capital expenditures on any individual projects during the remainder of 2019.2020.
Maintenance Capital Expenditures
Maintenance capital expenditures incurred during the 2019 Quarter primarily2020 relate to expenditures in our Alkali Business and in our marine transportation segment. Our Alkali Business, which is included in our sodium minerals and sulfur services segment, incurs expenditures to maintain its equipment and replace its plant equipmentfacilities due to the nature of its operations. Our marine transportation segment incurs expenditures as we frequently replace and upgrade certain equipment associated with our barge and vessel fleet during our planned and unplanned drydocks. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.
Distributions to Unitholders
On August 14, 2019,2020, we will pay a distribution of 0.55$0.15 per common unit totaling $67.4$18.4 million with respect to the 20192020 Quarter. Information on our recent distribution history is included in Note 10 to our Unaudited Condensed Consolidated Financial Statements.
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With respect to our Class A Convertible Preferred Units, (our "preferred units"), we declared a quarterly cash distribution of $0.7374 per preferred unitClass A Convertible Preferred Unit (or $2.9496 on an annualized basis) for each preferred unitClass A Convertible Preferred Unit held of record. These distributions will be payable on August 14, 20192020 to unitholders holders of record at the close of business on July 31, 2019.2020.

Guarantor Summarized 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 (the "Guarantor Subsidiaries), except the subsidiaries that hold our Alkali Business (collectively, the "Alkali Subsidiaries"), Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC, and certain other subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business other than our Alkali Business. As a general rule, the assets and credit of our unrestricted subsidiaries are not available to satisfy the debts of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries, and the liabilities of our unrestricted subsidiaries do not constitute obligations of Genesis Energy, L.P., Genesis Energy Finance Corporation or the Guarantor Subsidiaries except, in the case of Alkali Holdings and Genesis Energy, L.P., to the extent agreed to in the Services Agreement. Genesis Energy Finance Corporation has no independent assets or operations. See Note 9 for additional information regarding our consolidated debt obligations.
        The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes, the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution of such Guarantor Subsidiary (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.
        The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.
        The following is the summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a combined basis after elimination of intercompany transactions, which includes related receivable and payable balances, and the investment in and equity earnings from the Non-Guarantor Subsidiaries.
Balance SheetsGenesis Energy, L.P. and Guarantor Subsidiaries
June 30, 2020December 31, 2019
ASSETS:
Current assets$250,138  $323,492  
Fixed assets, net3,182,335  3,538,450  
Non-current assets892,423  951,276  
LIABILITIES AND CAPITAL:(1)
Current liabilities201,043  292,941  
Non-current liabilities3,736,282  3,738,816  
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, 2020		Twelve Months Ended
December 31. 2019
Revenues$597,774  $1,617,170  
Operating costs819,840  1,454,040  
Operating income (loss)(222,066) 163,130  
Income (loss) before income taxes(289,749) 566  
Net loss(1)
(290,179) (122) 
Less: Accumulated distributions to Class A Convertible Preferred Units(37,368) (74,467) 
Net loss available to common unitholders(327,547) (74,589) 
(1) There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for either period presented.
        Excluded from non-current assets in the table above are $76.7 million and $76.2 million of net intercompany receivables due to Genesis Energy, L.P. and the Guarantor Subsidiaries from the Non-Guarantor Subsidiaries as of June 30, 2020 and December 31, 2019, respectively.
Non-GAAP Financial Measure Reconciliations
For definitions and discussion of our Non-GAAP financial measures refer to the "Non-GAAP Financial Measures" as later discussed and defined.
Available Cash before Reserves for the periods presented below was as follows:
 Three Months Ended
June 30,
 20202019
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P.$(326,714) $40,120  
Income tax expense795  143  
Depreciation, depletion, amortization and accretion82,580  66,104  
Impairment expense277,495  —  
Plus (minus) Select Items, net40,809  12,270  
Maintenance capital utilized (1)
(9,900) (6,425) 
Cash tax expense(150) (60) 
Distributions to preferred unitholders(18,684) (18,684) 
Redeemable noncontrolling interest redemption value adjustments (2)
4,159  —  
Available Cash before Reserves$50,390  $93,468  
 Three Months Ended
June 30,
 2019 2018
 (in thousands)
Net income attributable to Genesis Energy, L.P.$40,120
 $10,997
Income tax expense143
 256
Depreciation, depletion, amortization and accretion66,104
 79,862
Plus (minus) Select Items, net12,270
 14,742
Maintenance capital utilized (1)
(6,425) (4,700)
Cash tax expense(60) (150)
Distributions to preferred unitholders(18,684) —
Other—
 (7)
Available Cash before Reserves$93,468
 $101,000
(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 2019 Quarter and 2018 Quarter were $25.2 million and $22.2 million, respectively.

(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 2020 Quarter and 2019 Quarter were $13.0 million and $25.2 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
June 30,		 Three Months Ended
June 30,
 2019 2018 20202019
 (in thousands) (in thousands)
I.Applicable to all Non-GAAP Measures   I.Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements1
$(9,848) $(1,148)
Differences in timing of cash receipts for certain contractual arrangements (1)
$11,638  $(9,848) 
Adjustment regarding direct financing leases2
2,079
 1,884
Adjustment regarding direct financing leases (2)
2,294  2,079  
Certain non-cash items:   
Unrealized loss on derivative transactions excluding fair value hedges, net of changes in inventory value9,065
 641
Certain non-cash items:
Adjustment regarding equity investees3
5,675
 10,037
Unrealized losses on derivative transactions excluding fair value hedges, net of changes in inventory value (3)
21,108  9,065  
Other1,947
 (53)
             Sub-total Select Items, net4
8,918
 11,361
Adjustment regarding equity investees (4)
5,776  5,675  
Other2,183  1,947  
             Sub-total Select Items, net (5)
42,999  8,918  
II.Applicable only to Available Cash before Reserves   II.Applicable only to Available Cash before Reserves
Certain transaction costs5
341
 2,896
Certain transaction costs (6)
21  341  
Equity compensation adjustments—
 61
Other3,011
 424
Other(2,211) 3,011  
Total Select Items, net6
$12,270
 $14,742
Total Select Items, net (7)
$40,809  $12,270  
(1) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.
(2) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.
(3) The 2020 Quarter includes a $21.8 million unrealized loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and the 2019 Quarter includes a $4.7 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.
(4)(5) Represents all Select Items applicable to Segment Margin and Available Cash before Reserves.
(5)(6) Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in advance of acquisition.
(6)(7) Represents Select Items applicable to Available Cash before Reserves.

Non-GAAP Financial Measures
General
To help evaluate our business, we use the non-generally accepted accounting principle (“non-GAAP”) financial measure of Available Cash before Reserves. We also present total Segment Margin as if it were a non-GAAP measure. Our non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The schedules above provide reconciliations of Available Cash before Reserves to its most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States of America (GAAP). A reconciliation of total Segment Margin to net income is also included in our segment disclosure in Note 12 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just two of the relevant data points considered from time to time.
When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user. Our non-GAAP financial measures should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

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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, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results.
A reconciliation of total Segment Margin to net income is included in our segment disclosure in Note 12 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, often referred to by others as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:
(1)the financial performance of our assets;
(2)our operating performance;
(3)the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;
(4)the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and
(5)our ability to make certain discretionary payments, such as distributions on our preferred and common units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.
(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.
Disclosure Format Relating to Maintenance Capital
We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.
Maintenance Capital Requirements
Maintenance Capital Expenditures
Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.
Initially, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.
As we exist today, a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not 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

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of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.
In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s recently increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves. Our maintenance capital utilized measure, which is described in more detail below, constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.
Maintenance Capital Utilized
We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.
Because we did not initially use our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.
Commitments and Off-Balance Sheet Arrangements
Contractual Obligations and Commercial Commitments
There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2018.Report.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report, on Form 10-K for the year ended December 31, 2018, 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, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, pandemics (including Covid-19), the actions of OPEC and other oil exporting nations, conservation and technological advances;
•our ability to successfully execute our business and financial strategies;
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•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;
•2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;
throughput levels and rates;
•changes in, or challenges to, our tariff rates;

•our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
•service equipment interruptions in our pipeline transportation systems, processing 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 soda ash, petroleum, or other products;
•risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
•changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;
•the effects of production declines and resulting from a suspension of drilling in the Gulf of Mexico or otherwise;
•the effects of future laws and government regulation;regulations;
•planned capital expenditures and availability of capital resources to fund capital expenditures;expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;
•our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;
•loss of key personnel;
•cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions at the current level or 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;
•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; and
•a cyber-attackcyberattack 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, 2018.. These risks may also
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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, 2018.Report. There have been no material changes

that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 15 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 second quarter of 20192020 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, 2018.2019. 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 and Quarterly Report on Form 10-K10-Q for the fiscal yearquarter ended DecemberMarch 31, 2018.2020.
For additional information about our risk factors, see Item 1A of our Annual Report and Item 1A of our Quarterly Report on Form 10-K10-Q for the yearquarter ended DecemberMarch 31, 2018,2020, 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 20192020 Quarter.

Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Information regarding mine safety and other regulatory action at our mines 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
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
3.8
3.9
3.10
4.1
*31.110.1
22.1
*31.1
*31.2
*32
*95
101.INS XBRL Instance Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH XBRL Schema 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
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By:
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By:
GENESIS ENERGY, LLC,

as General Partner
 
Date:August 6, 20195, 2020By:
/s/ ROBERT V. DEERE
Robert V. Deere
Chief Financial Officer
(Duly Authorized Officer)


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