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

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2018
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)
 
 
 
 
 

Delaware
76-0513049
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
919 Milam, Suite 2100,
Houston, TX
77002
(Address of principal executive offices)
(Zip code)
Registrant’s telephone number, including area code: (713) 860-2500
 
 
 
 
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  x
 
Accelerated filer  ¨
Non-accelerated filer  ¨ (Do not check if a smaller reporting company)
 
Smaller reporting company  ¨
 
 
Emerging growth company  ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act).    Yes  ¨    No  ý

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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 May 4, 2018.


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GENESIS ENERGY, L.P.
TABLE OF CONTENTS
 

 
 
Page
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.

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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)
 
 
March 31, 2018
 
December 31, 2017
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
16,092

 
$
9,041

Accounts receivable - trade, net
419,903

 
495,449

Inventories
95,667

 
88,653

Other
48,432

 
42,890

Total current assets
580,094

 
636,033

FIXED ASSETS, at cost
5,652,880

 
5,601,015

Less: Accumulated depreciation
(802,261
)
 
(734,986
)
Net fixed assets
4,850,619

 
4,866,029

MINERAL LEASEHOLDS, net of accumulated depletion
563,369

 
564,506

NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
123,270

 
125,283

EQUITY INVESTEES
372,493

 
381,550

INTANGIBLE ASSETS, net of amortization
178,755

 
182,406

GOODWILL
325,046

 
325,046

OTHER ASSETS, net of amortization
116,190

 
56,628

TOTAL ASSETS
$
7,109,836

 
$
7,137,481

LIABILITIES AND CAPITAL
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable - trade
$
263,527

 
$
270,855

Accrued liabilities
152,163

 
185,409

Total current liabilities
415,690

 
456,264

SENIOR SECURED CREDIT FACILITY
1,279,000

 
1,099,200

SENIOR UNSECURED NOTES, net of debt issuance costs
2,456,749

 
2,598,918

DEFERRED TAX LIABILITIES
12,138

 
11,913

OTHER LONG-TERM LIABILITIES
290,401

 
256,571

Total liabilities
4,453,978

 
4,422,866

 
 
 
 
MEZZANINE CAPITAL:
 
 
 
Class A Convertible Preferred Units, 22,901,980 and 22,411,728 issued and outstanding at March 31, 2018 and December 31, 2017, respectively
712,687

 
697,151

 
 
 
 
PARTNERS’ CAPITAL:
 
 
 
Common unitholders, 122,579,218 and 122,579,218 units issued and outstanding at March 31, 2018 and December 31, 2017, respectively
1,951,590

 
2,026,147

Accumulated other comprehensive loss
(604
)
 
(604
)
Noncontrolling interests
(7,815
)
 
(8,079
)
Total partners' capital
1,943,171

 
2,017,464

TOTAL LIABILITIES, MEZZANINE CAPITAL AND PARTNERS’ CAPITAL
$
7,109,836

 
$
7,137,481

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

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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
 
 
Three Months Ended
March 31,
 
2018
 
2017
REVENUES:
 
 
 
Offshore pipeline transportation services
73,260

 
85,128

Sodium minerals and sulfur services
285,910

 
45,046

Marine transportation
48,929

 
50,302

Onshore facilities and transportation
317,709

 
235,015

Total revenues
725,808

 
415,491

COSTS AND EXPENSES:
 
 
 
Onshore facilities and transportation product costs
277,818

 
192,093

Onshore facilities and transportation operating costs
22,295

 
22,239

Marine transportation operating costs
37,847

 
37,242

Sodium minerals and sulfur services operating costs
223,498

 
27,364

Offshore pipeline transportation operating costs
18,340

 
17,868

General and administrative
11,674

 
9,976

Depreciation, depletion and amortization
75,255

 
56,112

Total costs and expenses
666,727

 
362,894

OPERATING INCOME
59,081

 
52,597

Equity in earnings of equity investees
10,572

 
11,335

Interest expense
(56,136
)
 
(36,739
)
Other expense
(5,244
)
 
—

Income before income taxes
8,273

 
27,193

Income tax expense
(375
)
 
(255
)
NET INCOME
7,898

 
26,938

Net loss attributable to noncontrolling interests
136

 
152

NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
$
8,034

 
$
27,090

Less: Accumulated distributions attributable to Class A Convertible Preferred Units
(16,888
)
 
—

NET INCOME(LOSS) AVAILABLE TO COMMON UNITHOLDERS
$
(8,854
)
 
$
27,090

NET INCOME(LOSS) PER COMMON UNIT (Note 11):
 
 
 
Basic and Diluted
$
(0.07
)
 
$
0.23

WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
 
 
 
Basic and Diluted
122,579

 
118,388

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 COMPREHENSIVE INCOME
(In thousands)

 
Three Months Ended
March 31,
 
2018
 
2017
Net income
7,898

 
26,938

Other comprehensive loss:
 
 
 
Change in benefit plan liability
—

 
—

Total Comprehensive income
7,898

 
26,938

Comprehensive loss attributable to non-controlling interests
136

 
152

Comprehensive income attributable to Genesis Energy, L.P.
8,034

 
27,090

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


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GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In thousands)
 
 
Number of
Common Units
 
Partners’ Capital
 
Noncontrolling Interest
 
Accumulated Other Comprehensive Loss
 
Total
Partners’ capital, December 31, 2017
122,579

 
$
2,026,147

 
$
(8,079
)
 
$
(604
)
 
$
2,017,464

Impact of adoption of ASC 606
—

 
(3,550
)
 
—

 
—

 
(3,550
)
Partners’ capital, January 1, 2018
122,579

 
2,022,597

 
(8,079
)
 
(604
)
 
2,013,914

Net income (loss)
—

 
8,034

 
(136
)
 
—

 
7,898

Cash distributions to partners
—

 
(62,515
)
 
—

 
—

 
(62,515
)
Cash contributions from noncontrolling interests
—

 
—

 
400

 
—

 
400

Distributions to Class A Convertible Preferred unitholders
—

 
(16,526
)
 
—

 
—

 
(16,526
)
Partners' capital, March 31, 2018
122,579

 
$
1,951,590

 
$
(7,815
)
 
$
(604
)
 
$
1,943,171

 
Number of
Common Units
 
Partners’ Capital
 
Noncontrolling Interest
 
Accumulated Other Comprehensive Loss
 
Total
Partners’ capital, January 1, 2017
117,979

 
$
2,130,331

 
$
(10,281
)
 
$
—

 
$
2,120,050

Net income (loss)
—

 
27,090

 
(152
)
 
—

 
26,938

Cash distributions to partners
—

 
(83,765
)
 
—

 
—

 
(83,765
)
Issuance of common units for cash, net
4,600

 
140,537

 
—

 
—

 
140,537

Partners' capital, March 31, 2017
122,579

 
$
2,214,193

 
$
(10,433
)
 
$
—

 
$
2,203,760

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)
 
 
Three Months Ended
March 31,
 
2018
 
2017
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
7,898

 
$
26,938

Adjustments to reconcile net income to net cash provided by operating activities -
 
 
 
Depreciation, depletion and amortization
75,255

 
56,112

Amortization and writeoff of debt issuance costs and discount
4,161

 
2,582

Amortization of unearned income and initial direct costs on direct financing leases
(3,330
)
 
(3,500
)
Payments received under direct financing leases
5,167

 
5,167

Equity in earnings of investments in equity investees
(10,572
)
 
(11,335
)
Cash distributions of earnings of equity investees
10,352

 
11,542

Non-cash effect of equity-based compensation plans
(136
)
 
864

Deferred and other tax liabilities
225

 
205

Unrealized loss on derivative transactions
2,642

 
142

Other, net
(1,552
)
 
1,391

Net changes in components of operating assets and liabilities (Note 14)
(3,782
)
 
(29,068
)
Net cash provided by operating activities
86,328

 
61,040

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Payments to acquire fixed and intangible assets
(66,051
)
 
(61,292
)
Cash distributions received from equity investees - return of investment
9,277

 
9,083

Contributions in aid of construction costs
—

 
124

Proceeds from asset sales
6

 
1,234

Net cash used in investing activities
(56,768
)
 
(50,851
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Borrowings on senior secured credit facility
333,800

 
216,700

Repayments on senior secured credit facility
(154,000
)
 
(284,900
)
Repayment of senior unsecured notes
(145,170
)
 
—

Debt issuance costs
(159
)
 
—

Issuance of common units for cash, net
—

 
140,968

Contributions from noncontrolling interests
400

 
—

Distributions to common unitholders
(62,515
)
 
(83,765
)
Other, net
5,135

 
4,552

Net cash used in financing activities
(22,509
)
 
(6,445
)
Net increase in cash and cash equivalents
7,051

 
3,744

Cash and cash equivalents at beginning of period
9,041

 
7,029

Cash and cash equivalents at end of period
$
16,092

 
$
10,773

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

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


1. Organization and Basis of Presentation and Consolidation
Organization
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the crude oil and natural gas industry in the Gulf Coast region of the United States, Wyoming and the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, soda ash businesses, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and other vessels, and trucks. We are owned 100% by our limited partners. Genesis Energy, LLC, our general partner, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.
On September 1, 2017, we acquired our trona and trona-based exploring, mining, processing, producing, marketing and selling business (our"Alkali Business") for approximately $1.325 billion in cash. We funded that acquisition and the related transaction costs with proceeds from a $750 million private placement of Class A Convertible Preferred units (our "preferred units"), a $550 million public offering of notes, our revolving credit facility, and cash on hand. At the closing, we entered into transition service agreements to facilitate the transition of operations and uninterrupted services for both employees and customers. We report the results of our Alkali Business in our renamed sodium minerals and sulfur services segment, which includes our Alkali Business as well as our legacy refinery services operations.
We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation.
These four divisions that constitute our reportable segments consist of the following:
•
Offshore pipeline transportation and processing of crude oil and natural gas in the Gulf of Mexico;
•
Sodium minerals and sulfur services involving trona and trona-based exploring, mining, processing, producing, marketing and selling activities, as well as 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
•
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”). 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, 2017.
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
2. Recent Accounting Developments
Recently Issued
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. The adoption date for

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our material equity method investment in the Poseidon Oil Pipeline Company, LLC will follow the non-public business entity adoption date of January 1, 2019 for its stand-alone financial statements. Refer to Note 3 for further details.
In February 2016, the FASB issued guidance to improve the transparency and comparability among companies by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. The guidance also requires additional disclosure about leasing arrangements. The guidance is effective for interim and annual periods beginning after December 15, 2018 and requires a modified retrospective approach to adoption. Early adoption is permitted. We are currently evaluating this guidance.
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash flow, and other Topics. ASU 2016-15 is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2017. We have adopted this guidance as of January 1, 2018 using the retrospective transition method to each period presented on the Consolidated Statements of Cash Flows. We reclassified $3.6 million from operating cash flows to investing cash flows for the three months ended March 31, 2017.
In January 2017, the FASB issued guidance to simplify the goodwill impairment testing at annual or interim periods. The guidance eliminates Step 2 from the goodwill impairment testing process, and any identified impairment charge would be simplified to be the difference between the carrying value and fair value of a reporting unit, but would not exceed the total amount of goodwill allocated to the reporting unit in question. The guidance is effective for annual reporting periods, and interim periods therein, beginning after December 15, 2019, with early adoption permitted. We early adopted this guidance and it did not have an impact on our consolidated financial statements.
In March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715). ASU 2017-07 requires employers to separate the service cost component from the other components of net benefit cost in the period. The new standard requires the other components of net benefit costs (excluding service costs), be reclassified to "Other expense" from "General and administrative." We adopted this standard as of January 1, 2018. This standard is applied retrospectively. The effect was not material to our financial statements.

3. Revenue Recognition
Adoption of ASC 606 and its related Transition effects
The modified retrospective method of adoption required us to apply the new revenue standard to all new revenue contracts entered into after January 1, 2018 and revenue contracts that were not completed as of January 1, 2018. Our consolidated revenues for periods prior to January 1, 2018 were not revised and the cumulative effect of our adoption of ASC 606 was recorded as an adjustment to partners' capital at January 1, 2018. Based on this application, the following adjustments were made to our consolidated balance sheet as of January 1, 2018:

 
December 31, 2017
 
Adjustments
 
January 1,
2018
ASSETS
 
 
 
 
 
Accounts receivable- trade, net
$
495,449

 
$
(48,028
)
 
$
447,421

Inventories
88,653

 
5,138

 
93,791

Other assets, net of amortization
56,628

 
59,204

 
115,832

 
 
 
 
 
 
LIABILITIES AND CAPITAL
 
 
 
 
 
Other long-term liabilities
256,571

 
19,864

 
276,435

 
 
 
 
 
 
Partners' capital
2,026,147

 
(3,550
)
 
2,022,597


Current Impact of New Revenue Recognition Guidance
The tables below summarize the impact of adoption on our unaudited condensed consolidated balance sheet and statement of operations as of and for the three months ended March 31, 2018:


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As of March 31, 2018
Unaudited Condensed Consolidated Balance Sheet
As Reported
 
Without adoption of ASC 606
 
Effect of Change Increase/(Decrease)
ASSETS
 
 
 
 
 
Accounts receivable-trade, net
419,903

 
472,116

 
(52,213
)
Inventories
95,667

 
92,628

 
3,039

Other Assets, net of amortization
116,190

 
51,948

 
64,242

 
 
 
 
 
 
LIABILITIES AND CAPITAL
 
 
 
 
 
Other Long-Term Liabilities
290,401

 
268,832

 
21,569

Partners' Capital
1,951,590

 
1,958,091

 
(6,501
)

 
Three months ended March 31, 2018
Unaudited Condensed Consolidated Statement of Operations
As Reported
 
Without adoption of ASC 606
 
Effect of Change Increase/(Decrease)
 
 
 
 
 
 
Offshore pipeline transportation services
73,260

 
74,111

 
(851
)
Sodium minerals and sulfur services
285,910

 
263,965

 
21,945

Marine transportation
48,929

 
48,929

 
—

Onshore facilities and transportation
317,709

 
317,709

 
—

Total revenues
725,808

 
704,714

 
21,094

 
 
 
 
 
 
Onshore facilities and transportation product costs
277,818

 
277,818

 
—

Onshore facilities and transportation operating costs
22,295

 
22,295

 
—

Marine transportation operating costs
37,847

 
37,847

 
—

Sodium minerals and sulfur services operating costs
223,498

 
199,454

 
24,044

Offshore pipeline transportation operating costs
18,340

 
18,340

 
—

 
 
 
 
 
 
OPERATING INCOME
59,081

 
62,032

 
(2,951
)

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The effects of changes pursuant to ASC 606 in the tables above are attributable to our offshore pipeline transportation services operating segment and our sodium minerals and sulfur services operating segment.
In our offshore pipeline transportation services segment, we have certain contracts with customers that contain tiered pricing structures that are dependent upon reaching certain cumulative milestones of throughput volumes on our pipelines. In addition, we have a contract that contains fixed and variable consideration for us to stand ready and provide reservation capacity for a fixed minimum quantity on our pipeline. Pursuant to the new guidance, we have allocated our estimated total transaction price over the life of the contract to the related performance obligation and recognized the effects in our Consolidated Financial Statements. In our sodium minerals and sulfur services operating segment, specifically our legacy refinery services business, we have two distinct performance obligations, including the completion of our refinery sulfur removal process, for which we receive in-kind consideration, and our sale of NaHS to our customers. Due to this, we have recorded revenue and the related cost of sales in the Consolidated Financial Statements for the three months ended March 31, 2018 (the "2018 Quarter") for services performed for the in-kind consideration for our services. Further discussion of our performance obligations by type and segment are below.
Revenue from Contracts with Customers
The following table reflects the disaggregation of our revenues by major category for the three months ended March 31, 2018:
 
Period ended March 31, 2018
 
Onshore Facilities & Transportation
 
Sodium Minerals & Sulfur Services
 
Offshore Pipeline Transportation
 
Marine Transportation
 
Consolidated
Fee-based revenues
30,338

 
—

 
73,260

 
48,929

 
152,527

Product Sales
287,371

 
263,965

 
—

 
—

 
551,336

Refinery Services
—

 
21,945

 
—

 
—

 
21,945

 
$
317,709

 
$
285,910

 
$
73,260

 
$
48,929

 
$
725,808


The Company recognizes revenue upon the satisfaction of its performance obligations under its contracts. The timing of revenue recognition varies for the revenue streams described in more detail below. 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.

Fee-based Revenues
We provide a variety of fee-based transportation and logistics services to our customers across several of our reportable segments as outlined below.

Offshore Pipeline Transportation
Revenue from our offshore pipelines is generally based upon a fixed fee per unit of volume (typically per Mcf of natural gas or per barrel of crude oil) gathered, transported, or processed multiplied by the volume delivered. Fees are based either on contractual arrangements or tariffs regulated by the FERC. Revenue associated with these fee-based services is recognized as volumes are delivered over the performance obligation period.

In addition to the offshore pipeline transportation revenue discussed above, we also have certain contracts with customers in which we earn either demand-type fees or firm capacity reservation fees. These fees are charged to a customer regardless of the volume the customer actually delivers to the platform or through the pipeline. These contracts include a single performance obligation to stand ready, on a monthly basis, to provide capacity on our assets.

In addition to these offshore pipeline transportation services revenue streams, we also have certain customer contracts in which the transportation fee has a tiered pricing structure based on cumulative milestones of throughput on the related pipeline asset and contract, or on a specified date. The performance obligation for these contracts is to transport, gather or process commodity volumes for the customer based on firm (stand ready) service or from monthly nominations made by our customers, which can also be on an interruptible basis. While our transportation rate changes when milestones are achieved for certain cumulative throughput, the performance obligation satisfied by us does not change throughout the life of the contract. Therefore revenue is recognized on an average rate basis throughout the life of the contract. We have estimated the total consideration to be received under the contract beginning at the contract inception date based on the estimated volumes (including certain minimum volumes we are required to stand ready for), price indexing, estimated production or contracted volumes, and the contract period. We have constrained the estimates of variable consideration such that it is probable that a significant reversal of previously recognized revenue will not occur throughout the life of the contract. These estimates will be reassessed at each reporting period

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as required. Billings to our customers are reflected at the contract rate. This variability between the consideration received from our customers from invoicing compared to the revenue recognized creates a contract asset or liability. In circumstances where the estimated average contract rate is less than the billed current price tier in the contract, we will recognize a contract liability. In circumstances where the estimated average contract rate is higher than the billed current price tier in the contract, we will recognize a contract asset.

Onshore Facilities and Transportation
Within our onshore facilities and transportation segment, we provide our customers with pipeline transportation, terminalling services, and rail loading/unloading services, among others, primarily on a per barrel fee basis.

Revenues from contracts for the transportation of crude oil by our pipelines are based on actual volumes at a published tariff and some contain minimum throughput provisions which reset within one year. We recognize revenues for transportation and other services over the performance obligation period, which is the contract term. Revenues for both firm and interruptible transportation and other services are recognized when product is delivered to the agreed upon delivery point or at the point of receipt because they specifically relate to our efforts to transfer the distinct services.

Service contracts contain a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over the contract period, and therefore qualify as a single performance obligation that is satisfied over time. The customer receives and consumes the benefit of our services simultaneous with the provision of those services.

Pricing for our services is determined through a variety of mechanisms, including specified contract pricing or regulated tariff pricing. Consideration to be received by us under these contracts is variable, as the volume of the commodity to be transported is unknown at contract inception. At the end of a day or month (as specified in the contract), both the price and volume are known (or “fixed”) in order to allow us to accurately calculate the amount of consideration we are entitled to invoice. The measurement of these services and invoicing occurs on a monthly basis.

Pipeline Loss Allowances
In order to compensate us for bearing the risk of volumetric losses of crude oil in transit in our pipelines (for our onshore and offshore pipelines) due to temperature, crude quality, and the inherent difficulties of measurement of liquids in a pipeline, our tariffs and agreements include the right for us to make volumetric deductions from the customer for quality and volumetric fluctuations. We refer to these deductions as pipeline loss allowances ("PLA"). We compare these allowances to the actual volumetric gains and losses of the pipeline and the net gain or loss is recorded as revenue or a reduction of revenue. As the allowance is related to our pipeline transportation services, the performance obligation is the obligation to transport and deliver the barrels and is considered a single obligation.

When net gains occur, we have crude oil inventory. When net losses occur, we reduce any recorded inventory on hand and record a liability for the purchase of crude oil required to replace the lost volumes. Under ASC 606, we record excess oil as non-cash consideration at the lower of the recorded value or the market value and include this amount in the transaction price. The crude oil in inventory can then be sold at current prevailing market prices, resulting in additional revenue if the sales price exceeds the inventory value when control transfers to the customer.

Marine Transportation
Our marine transportation business consists of revenues from the inland and offshore marine transportation of heavy refined petroleum products, asphalt and crude oil, using our barges or vessels. This revenue is recognized over the passage of time of individual trips as determined on an individual contract basis. Revenue from these contracts is typically based on a set day-rate or a set fee per cargo movement. The costs of fuel and certain other operational costs may be directly reimbursed by the customer, if stipulated in the contract.

A performance obligation is driven by providing transportation services using our vessels for a single day either under a term or spot based contract. The transaction price is usually fixed per the contract either as a day rate or as a lump sum to be allocated over days required to complete the service. Revenue is recognizable as the transportation service utilizing our vessels occurs, as the customer simultaneously receives and consumes these services as they are provided. If provided in the contract, certain items such as fuel or operational costs can be rebilled to the customer in the same period in which the costs are incurred. In the event timing of a trip to provide our services crosses a reporting period under a lump sum fee contract, the revenue earned is accrued based on the progress completed in the current period on the related performance obligation as we are entitled to payment for each day. Customer invoicing occurs at the completion of a trip, or earlier at the customer’s request.

Product Sales

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Sodium Minerals and Sulfur Services
Product sales in our sodium minerals and sulfur services segment primarily involve the sales of caustic soda, NaHS, soda ash and other alkali products. As it relates to revenue recognition, these sales transactions contain a single performance obligation, which is the delivery of the product to the customer at the agreed upon point of sale. For some transactions, control of product transfers to the customer at the shipping point, but we are obligated to arrange for shipment of the product as directed by the customer. Rather than treat these shipping activities as separate performance obligations, our policy is to account for them as fulfillment costs in accordance with ASC 606.

The transaction price for these product sales are determined by specific contracts, typically at a fixed rate or based on a market or indexed rate. This pricing is known, or is “fixed,” at the time of revenue recognition. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing. The entirety of the transaction price is allocated to the performance obligation which is delivery of the product at the agreed upon point of sale. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations.

Onshore Facilities and Transportation
Product sales in our onshore facilities and transportation segment primarily involve the sales of crude oil and petroleum products. These contracts contain a single performance obligation, which is the delivery of the product to the customer at a specified location. These contracts are settled on a monthly basis for term contracts, or on a spot basis. Invoicing and related payment terms are in accordance with industry standard or contract specification based on final pricing.

Pricing is designated within the contracts and is either fixed, index-based or formulaic, utilizing an average price for the month or for a specified range of days, regardless of when delivery occurs. In either case, pricing is known at the time of invoicing. The entirety of the consideration is allocated to a single performance obligation which is delivery of the product to a specified location. As this type of revenue is earned at a point in time, there is no allocation of transaction price to future performance obligations.

Refinery Services
Our refinery services business primarily provides sulfur extraction services to refiners’ high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses caustic soda to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. The technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. Units of NaHS are produced ratably as a gas stream is processed. We obtain control and ownership of the NaHS immediately upon production which constitutes the sole consideration received for our sulfur removal services. We later market this product to third parties as part of our product sales, as described above. As part of some of our arrangements, we pay a refinery access fee (“RSA fee”) for any benefits received by virtue of our plant’s proximity to the customer’s refinery. Our RSA fee is recorded as a reduction of revenue.

Providing sulfur removal services is the singular performance obligation in our refinery service agreements. As our customers simultaneously receive and consume the refinery service benefits, control is transferred and revenue is recognized over time based on the extent of progress towards completion of the performance obligations. We use units of NaHS produced during a period to measure progress as the amount we receive corresponds directly with the efforts to provide our services completed to date. The transaction price for each performance obligation is determined using the fair value of a unit of NaHS on the contract inception date for each refinery services agreement. Accordingly, we record the value of NaHS received as non cash consideration in inventory until it is subsequently sold to our customers (see Product Sales, above).
Contract Assets and Liabilities
The table below depicts our contract asset and liability balances and related activity from January 1, 2018 to March 31, 2018:

 
Contract Assets
 
Contract Liabilities
 
Non-Current
 
Non-Current
Balance at January 1, 2018
59,204

 
19,864

Balance at March 31, 2018
64,240

 
21,570


During the three months ended March 31, 2018 there were no balances that were previously classified as contract liabilities at the beginning of the period that were recognized as revenues. Accounts receivable-trade, net does not include

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consideration received in kind from our refinery services process. We did not have any contract modifications during the period that would affect our contract asset and liability balances.

Transaction Price Allocations to Future Performance Obligations
We are required to disclose the amount of our transaction prices that are allocated to future unrecognized performance obligations as of March 31, 2018. However, ASC 606 does provide the following practical expedients and exemptions that we utilized:

1)
Performance obligations 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

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 exceptions to our revenue streams recognized over time. The majority of our contracts qualify for one of these expedients or exceptions. After considering these practical expedients and identifying the remaining contract types that involve revenue recognition over a long-term period and include 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 to 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 our remaining contract value (as estimated and discussed above) to future periods. As of March 31, 2018 have an estimated aggregate transaction price allocated to unsatisfied performance obligations of $379.9 million for our offshore transportation segment.

Similarly, in our marine transportation segment, our contract related to our M/T American Phoenix contains minimum fixed consideration over the life of the contract, which ends in September 2020. The estimated aggregate transaction price allocated to unsatisfied performance obligations is $67.5 million as of March 31, 2018. In our onshore facilities and transportation segment, we have certain contractual arrangements in which we receive fixed minimum payments for our obligation to provide minimum capacity on our pipelines and related assets.  These fixed minimum billings totaling $202.7 million will be recognized over their remaining contract period as shown below.

The following chart depicts how we expect to recognize revenues for future periods related to these contracts:
 
Offshore Pipeline Transportation
Marine Transportation
Onshore Facilities and Transportation
 
 
 
 
Remainder of 2018
$
63,672

$
20,350

$
49,773

2019
73,918

27,010

66,267

2020
50,883

20,128

60,689

2021
34,261

—

21,714

2022
22,558

—

4,283

Thereafter
134,623

—

—

Total
$
379,915

$
67,488

$
202,726








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4. Acquisition
Acquisition
Alkali Business
On September 1, 2017, we acquired our Alkali Business for approximately $1.325 billion (inclusive of approximately $105 million in working capital). Our Alkali Business produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. To finance that transaction and the related costs, we used proceeds from (i) a $550.0 million public offering of 6.50% senior unsecured notes due 2025 in August 2017, generating net proceeds of $540.1 million after issuance discount and underwriting fees, (ii) a $750 million private placement of our preferred units in September 2017, generating net proceeds of $726.2 million, (iii) borrowings under our revolving credit facility and (iv) cash on hand.
We have reflected the financial results of our Alkali Business in our sodium minerals and sulfur services segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Those preliminary fair values were developed by management with the assistance of a third-party valuation firm and we do not expect any material adjustments to these preliminary purchase allocations. We expect to finalize the purchase price allocation for this transaction during the first half of 2018. Our preliminary purchase price allocation remains unchanged from what was disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.
Our Consolidated Financial Statements include the results of our Alkali Business since September 1, 2017, the closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:
 
Three Months Ended March 31, 2018
Revenues
208,549

Net income
31,740

The table below presents selected unaudited pro forma financial information incorporating the historical results of our Alkali Business. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2017 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. This pro forma information was prepared using historical financial data of the Tronox trona and trona-based exploring, mining, processing, producing, marketing and selling business and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had our Alkali Business acquisition been completed on January 1, 2017. Pro forma net income includes the effects of distributions on our preferred units and interest expense on incremental borrowings. The dilutive effect of our preferred units is calculated using the if-converted method.
 
Three Months Ended
March 31,
 
2017
Pro forma consolidated financial operating results:
 
Revenues
$
606,100

Net Income Attributable to Genesis Energy, L.P.
36,490

Net Income Available to Common Unitholders
20,083

Basic and diluted earnings per common unit:
 
As reported net income per common unit
$
0.23

Pro forma net income per common unit
$
0.17



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

5. Inventories
The major components of inventories were as follows:
 
March 31,
2018
 
December 31,
2017
Petroleum products
$
20,048

 
$
8,731

Crude oil
25,133

 
29,873

Caustic soda
5,016

 
5,755

NaHS
9,655

 
8,277

Raw materials - Alkali operations
4,648

 
4,550

Work-in-process - Alkali operations
9,747

 
7,355

Finished goods, net - Alkali operations
10,914

 
14,075

Materials and supplies, net - Alkali operations
10,498

 
10,030

Other
8

 
7

Total
$
95,667

 
$
88,653


Inventories are valued at the lower of cost or net realizable value. The net realizable value of inventories were not below cost as of March 31, 2018 and December 31, 2017.

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

6. Fixed Assets and Mineral Leaseholds
Fixed Assets
Fixed assets consisted of the following:
 
 
March 31,
2018
 
December 31,
2017
Crude oil pipelines and natural gas pipelines and related assets
$
3,081,841

 
$
3,028,657

Alkali facilities, machinery, and equipment
499,539

 
497,601

Onshore facilities, machinery, and equipment
725,217

 
692,364

Transportation equipment
21,468

 
21,483

Marine vessels
934,315

 
918,953

Land, buildings and improvements
224,055

 
223,186

Office equipment, furniture and fixtures
18,162

 
18,112

Construction in progress
96,800

 
151,768

Other
51,483

 
48,891

Fixed assets, at cost
5,652,880

 
5,601,015

Less: Accumulated depreciation
(802,261
)
 
(734,986
)
Net fixed assets
$
4,850,619

 
$
4,866,029


Mineral Leaseholds
Our Mineral Leaseholds, as relating to our recently acquired Alkali Business, consist of the following:
 
March 31,
2018
 
December 31,
2017
Mineral leaseholds
566,019

 
566,019

Less: Accumulated depletion
(2,650
)
 
(1,513
)
Mineral leaseholds, net
$
563,369

 
$
564,506


Our depreciation and depletion expense for the periods presented was as follows:
 
Three Months Ended
March 31,
 
2018
 
2017
Depreciation expense
$
68,428

 
$
49,924

Depletion expense
1,137

 
—

    


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

Asset Retirement Obligations
We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations.
The following table presents information regarding our AROs since December 31, 2017:
ARO liability balance, December 31, 2017
$
198,187

Accretion expense
2,718

Change in estimate
1,163

Settlements
(2,836
)
ARO liability balance, March 31, 2018
$
199,232

Of the ARO balances disclosed above, $11.8 million and $20.9 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017, respectively. The remainder of the ARO liability as of March 31, 2018 and December 31, 2017 is included in "Other long-term liabilities" on our Unaudited Condensed Consolidated Balance Sheet.
With respect to our AROs, the following table presents our forecast of accretion expense for the periods indicated:
Remainder of
2018
$
8,264

 
2019
$
9,908

 
2020
$
8,743

 
2021
$
9,337

 
2022
$
9,972

Certain of our unconsolidated affiliates have AROs recorded at March 31, 2018 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our 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 March 31, 2018 and December 31, 2017, the unamortized excess cost amounts totaled $378.4 million and $382.4 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.
The following table presents information included in our Unaudited Condensed Consolidated Financial Statements related to our equity investees.
 
Three Months Ended
March 31,
 
2018
 
2017
Genesis’ share of operating earnings
$
14,514

 
$
15,277

Amortization of excess purchase price
(3,942
)
 
(3,942
)
Net equity in earnings
$
10,572

 
$
11,335

Distributions received
$
19,629

 
$
20,625


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

The following tables present the unaudited balance sheet and income statement information (on a 100% basis) for Poseidon Oil Pipeline Company (which is our most significant equity investment):
 
March 31,
2018
 
December 31,
2017
BALANCE SHEET DATA:
 
 
 
Assets
 
 
 
Current assets
$
13,626

 
$
18,711

Fixed assets, net
213,472

 
217,343

Other assets
1,123

 
1,203

Total assets
$
228,221

 
$
237,257

Liabilities and equity
 
 
 
Current liabilities
$
17,846

 
$
17,560

Other liabilities
235,834

 
237,434

Equity
(25,459
)
 
(17,737
)
Total liabilities and equity
$
228,221

 
$
237,257


 
Three Months Ended
March 31,
 
2018
 
2017
INCOME STATEMENT DATA:
 
 
 
Revenues
$
28,944

 
$
28,905

Operating income
$
20,347

 
$
20,787

Net income
$
18,578

 
$
19,435


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

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

8. Intangible Assets
The following table summarizes the components of our intangible assets at the dates indicated:
 
 
March 31, 2018
 
December 31, 2017
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Carrying
Value
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Carrying
Value
Sodium minerals and sulfur services:
 
 
 
 
 
 
 
 
 
 
 
Customer relationships
$
94,654

 
$
93,033

 
$
1,621

 
$
94,654

 
$
92,493

 
$
2,161

Licensing agreements
38,678

 
37,066

 
1,612

 
38,678

 
36,528

 
2,150

Non-compete agreement
800

 
156

 
644

 
800

 
89

 
711

Segment total
134,132

 
130,255

 
3,877

 
134,132

 
129,110

 
5,022

Onshore Facilities & Transportation:
 
 
 
 
 
 
 
 
 
 
 
Customer relationships
35,430

 
35,093

 
337

 
35,430

 
35,082

 
348

Intangibles associated with lease
13,260

 
5,051

 
8,209

 
13,260

 
4,933

 
8,327

Segment total
48,690

 
40,144

 
8,546

 
48,690

 
40,015

 
8,675

Marine contract intangibles
27,000

 
13,050

 
13,950

 
27,000

 
11,700

 
15,300

Offshore pipeline contract intangibles
158,101

 
22,190

 
135,911

 
158,101

 
20,109

 
137,992

Other
30,684

 
14,213

 
16,471

 
28,900

 
13,483

 
15,417

Total
$
398,607

 
$
219,852

 
$
178,755

 
$
396,823

 
$
214,417

 
$
182,406

Our amortization of intangible assets for the periods presented was as follows:
 
Three Months Ended
March 31,
 
2018
 
2017
Amortization of intangible assets
$
5,433

 
$
5,872

We estimate that our amortization expense for the next five years will be as follows:
Remainder of
2018
$
16,475

 
2019
$
16,914

 
2020
$
16,661

 
2021
$
11,080

 
2022
$
10,695


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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:
 
March 31, 2018
 
December 31, 2017
 
Principal
 
Unamortized Discount and Debt Issuance Costs (1)
 
Net Value
 
Principal
 
Unamortized Discount and Debt Issuance Costs (1)
 
Net Value
Senior secured credit facility
$
1,279,000

 
$
—

 
$
1,279,000

 
$
1,099,200

 
$
—

 
$
1,099,200

5.750% senior unsecured notes due February 2021
—

 
—

 
—

 
145,170

 
1,303

 
143,867

6.750% senior unsecured notes due August 2022
750,000

 
15,257

 
734,743

 
750,000

 
16,077

 
733,923

6.000% senior unsecured notes due May 2023
400,000

 
5,424

 
394,576

 
400,000

 
5,691

 
394,309

5.625% senior unsecured notes due June 2024
350,000

 
5,493

 
344,507

 
350,000

 
5,717

 
344,283

6.500% senior unsecured notes due October 2025
550,000

 
9,157

 
540,843

 
550,000

 
9,462

 
540,538

6.250% senior unsecured notes due May 2026
450,000

 
7,920

 
442,080

 
450,000

 
8,002

 
441,998

Total long-term debt
$
3,779,000

 
$
43,251

 
$
3,735,749

 
$
3,744,370

 
$
46,252

 
$
3,698,118

(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 $13.1 million and $14.1 million as of March 31, 2018 and December 31, 2017, respectively.
As of March 31, 2018, 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 applicable margin varies from 1.50% to 3.00% on Eurodollar borrowings and from 0.50% to 2.00% on alternate base rate borrowings.
•Letter of credit fees range from 1.50% to 3.00%
•The commitment fee on the unused committed amount will range from 0.25% to 0.50%.
•The accordion feature is $300.0 million, giving us the ability to expand the size of the facility to up to $2.0 billion for acquisitions or growth projects, subject to lender consent.
At March 31, 2018, we had $1.3 billion borrowed under our $1.7 billion credit facility, with $40.5 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 $1.2 million was outstanding at March 31, 2018. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our credit facility at March 31, 2018 was $419.8 million.
Senior Unsecured Note Issuances, Redemption, and Extinguishment
On December 11, 2017, we issued $450 million in aggregate principal amount of 6.25% senior unsecured notes due May 15, 2026 (the "2026 Notes"). Interest payments are due May 15 and November 15 of each year with the initial interest payment due May 15, 2018. Our 2026 Notes mature on May 15, 2026. That issuance generated proceeds of $441.8 million, net of issuance costs incurred. We used $204.8 million of the net proceeds to redeem the portion of the 5.75% senior unsecured notes due February 15, 2021 (the "2021 Notes") that were validly tendered and the remaining net proceeds to repay a portion of the borrowings outstanding under our revolving credit facility. 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. We incurred a total loss of approximately $3.3 million relating to the extinguishment of those notes (including the writeoff of the related unamortized debt issuance costs), which loss is recorded as "Other income/(expense), net" in our Consolidated Statements of Operations.

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


10. Partners’ Capital, Mezzanine Capital and Distributions
At March 31, 2018, our outstanding common units consisted of 122,539,221 Class A units and 39,997 Class B units.
Distributions
We paid or will pay the following distributions to our common unitholders in 2017 and 2018:
Distribution For
 
Date Paid
 
Per Unit
Amount
 
Total
Amount
 
2017
 
 
 
 
 
 
 
1st Quarter
 
May 15, 2017
 
$
0.7200

 
$
88,257

 
2nd Quarter
 
August 14, 2017
 
$
0.7225

 
$
88,563

 
3rd Quarter
 
November 14, 2017
 
$
0.5000

 
$
61,290

 
4th Quarter
 
February 14, 2018
 
$
0.5100

 
$
62,515

 
2018
 
 
 
 
 
 
 
1st Quarter
 
May 15, 2018
(1) 
$
0.5200

 
$
63,741

 
(1) This distribution will be paid to unitholders of record as of May 1, 2018.
Class A Convertible Preferred Units
On September 1, 2017, we sold $750 million of our 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. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our preferred units. Our preferred units are a new class of security that ranks senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our preferred units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those preferred units.    
Accounting for the Class A Convertible Preferred Units
Our 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 Consolidated Balance Sheet. We recorded our preferred units at their issuance date fair value, net of issuance costs. Because our 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 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 .
Initial and Subsequent Measurement
We initially recognized our 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 units until it becomes probable that they would become redeemable. Once redemption becomes probable, we would adjust the carrying amount of our 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.
Preferred unit distributions are recognized on the date in which they are declared. In January 2018, we declared a $16.5 million distribution on our preferred units owned as of January 31, 2018. This distribution was paid in kind ("PIK") through the issuance of 490,252 additional preferred units. The following table shows the change in our preferred units from December 31, 2017 to March 31, 2018:

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

 
 
As of March 31,
Mezzanine Capital Balance
 
2018
Balance as of December 31, 2017
 
697,151

Distribution paid-in-kind
 
16,527

Allocation of Distribution paid in-kind to Preferred Distribution Rate Reset Election (Note 16)
 
(991
)
Balance as of March 31, 2018
 
712,687


 
 
Three months ended
March 31,
Number of Class A Convertible Preferred Units
 
2018
Balance as of December 31, 2017
 
22,411,728

Distribution paid-in-kind
 
490,252

Balance as of March 31, 2018
 
22,901,980


Net income attributable to common unitholders is reduced by preferred unit distributions that accumulated during the period. During 2018, net income attributable to common unitholders was reduced by $16.9 million as a result of distributions that accumulated during the period. With respect to our preferred units to be issued relating to the first quarter of 2018, we elected to make a PIK payment for the quarterly distribution, which will result in the issuance of an additional 500,976 preferred units. This PIK amount equates to a distribution of $0.7374 per preferred unit for the first quarter of 2018, or $2.9496 annualized. These distributions will be paid on May 15, 2018 to unitholders holders of record at the close of business May 1, 2018.

11. Net Income 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 units is calculated using the if-converted method. Under the if-converted method, our preferred 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 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 months ended March 31, 2018, the effect of the assumed conversion of the 22,901,980 preferred units was anti-dilutive and was not included in the computation of diluted earnings per unit.

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

The following table reconciles net income and weighted average units used in computing basic and diluted net income per common unit (in thousands, except per unit amounts):
 
Three Months Ended
March 31,
 
2018
 
2017
Net Income Attributable to Genesis Energy L.P.
$
8,034

 
$
27,090

Less: Accumulated distributions attributable to Class A Convertible Preferred Units
(16,888
)
 
—

Net Income (loss) Available to Common Unitholders
$
(8,854
)
 
$
27,090

 
 
 
 
Weighted Average Outstanding Units
122,579

 
118,388

 
 
 
 
Basic and Diluted Net Income (loss) per Common Unit
$
(0.07
)
 
$
0.23

 
 
 
 


12. Business Segment Information
We currently manage our businesses through four 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
•
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 legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases.
Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, where relevant, and capital investment. 

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

Segment information for the periods presented below was as follows:
 
Offshore Pipeline Transportation
 
Sodium Minerals & Sulfur Services
 
Onshore Facilities & Transportation
 
Marine Transportation
 
Total
Three Months Ended March 31, 2018
 
 
 
 
 
 
 
 
 
Segment Margin (a)
$
73,173

 
$
64,391

 
$
21,689

 
$
10,987

 
$
170,240

Capital expenditures (b)
$
654

 
$
9,699

 
$
23,289

 
$
10,865

 
44,507

Revenues:
 
 
 
 
 
 
 
 
 
External customers
$
73,260

 
$
287,403

 
$
320,215

 
$
44,930

 
725,808

Intersegment (c)
—

 
(1,493
)
 
(2,506
)
 
3,999

 
—

Total revenues of reportable segments
$
73,260

 
$
285,910

 
$
317,709

 
$
48,929

 
$
725,808

Three Months Ended March 31, 2017
 
 
 
 
 
 
 
 
 
Segment Margin (a)
$
87,089

 
$
17,496

 
$
21,097

 
$
12,963

 
$
138,645

Capital expenditures (b)
$
2,239

 
$
513

 
$
46,702

 
$
9,533

 
58,987

Revenues:
 
 
 
 
 
 
 
 
 
External customers
$
85,405

 
$
47,271

 
$
234,611

 
$
48,204

 
415,491

Intersegment (c)
(277
)
 
(2,225
)
 
404

 
2,098

 
—

Total revenues of reportable segments
$
85,128

 
$
45,046

 
$
235,015

 
$
50,302

 
$
415,491

Total assets by reportable segment were as follows:
 
March 31,
2018
 
December 31,
2017
Offshore pipeline transportation
$
2,472,742

 
$
2,486,803

Sodium minerals and sulfur services
1,842,607

 
1,848,188

Onshore facilities and transportation
1,916,102

 
1,927,976

Marine transportation
819,057

 
824,777

Other assets
59,328

 
49,737

Total consolidated assets
7,109,836

 
7,137,481

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

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

Reconciliation of total Segment Margin to net income:
 
Three Months Ended
March 31,
 
2018
 
2017
Total Segment Margin
$
170,240

 
$
138,645

Corporate general and administrative expenses
(10,460
)
 
(8,327
)
Depreciation, depletion, amortization and accretion
(78,008
)
 
(58,395
)
Interest expense
(56,136
)
 
(36,739
)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income (1)
(9,057
)
 
(9,290
)
Non-cash items not included in Segment Margin
(6,137
)
 
437

Cash payments from direct financing leases in excess of earnings
(1,839
)
 
(1,667
)
Loss on extinguishment of debt
(3,339
)
 
—

Differences in timing of cash receipts for certain contractual arrangements (2)
3,331

 
2,681

Non-cash provision for leased items no longer in use
(186
)
 
—

Income tax expense
(375
)
 
(255
)
Net income attributable to Genesis Energy, L.P.
$
8,034

 
$
27,090

(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.
13. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:
 
Three Months Ended
March 31,
 
2018
 
2017
Revenues:
 
 
 
Sales of CO2 to Sandhill Group, LLC (1)
$
543

 
$
677

Revenues from services and fees to Poseidon Oil Pipeline Company, LLC (2)
3,200

 
3,022

Revenues from product sales to ANSAC
90,796

 
—

Costs and expenses:
 
 
 
Amounts paid to our CEO in connection with the use of his aircraft
$
165

 
$
165

Charges for services from Poseidon Oil Pipeline Company, LLC (2)
249

 
241

Charges for services from ANSAC
1,778

 
—

 
(1)
We own a 50% interest in Sandhill Group, LLC.
(2)
We own 64% interest in Poseidon Oil Pipeline Company, LLC.

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 March 31, 2018 and December 31, 2017 Poseidon Oil Pipeline Company, LLC owed us $1.8 million and $2.2 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 months ended March 31, 2018 reflect $2.2 million 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 $90.8 million during the period ended March 31, 2018. The costs charged to us by ANSAC, included in operating costs, were $1.8 million during the period ended March 31, 2018.
Receivables from ANSAC as of March 31, 2018 and December 31, 2017 are as follows:
 
March 31,
 
December 31,
 
2018
 
2017
Receivables:
 
 
 
ANSAC
$
71,276

 
$
74,490

Payables:
 
 
 
ANSAC
$
1,970

 
$
1,223

 
 
 
 

ANSAC is considered a variable interest entity (VIE) because we experience certain risks and rewards from our relationship with it. Because we do not exercise control over ANSAC and are not considered its primary beneficiary, we do not consolidate ANSAC.         

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

14. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
 
Three Months Ended
March 31,
 
2018
 
2017
(Increase) decrease in:
 
 
 
Accounts receivable
$
27,368

 
$
9,169

Inventories
(4,469
)
 
6,009

Deferred charges
(4,161
)
 
(348
)
Other current assets
(7,694
)
 
(4,605
)
Increase (decrease) in:
 
 
 
Accounts payable
94

 
(17,305
)
Accrued liabilities
(14,920
)
 
(21,988
)
Net changes in components of operating assets and liabilities
(3,782
)
 
(29,068
)
Payments of interest and commitment fees were $43.0 million and $46.7 million for the three months ended March 31, 2018 and March 31, 2017, respectively. We capitalized interest of $1.4 million and $6.0 million during the three months ended March 31, 2018 and March 31, 2017.
At March 31, 2018 and March 31, 2017, we had incurred liabilities for fixed and intangible asset additions totaling $20.6 million and $31.6 million, respectively, that had not been paid at the end of the quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

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

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

Additionally, in 2018 we have entered into swap arrangements. Our Alkali Business relies on natural gas to generate heat and electricity for operations. We use a combination of commodity price swap contracts and future purchase contracts to manage our exposure to fluctuations in natural gas prices. The swap contracts fix the basis differential between NYMEX Henry Hub and NW Rocky Mountain posted prices. We do not designate these contracts as hedges for accounting purposes. We recognize any changes in fair value of the derivative contracts as increases or decreases in our cost of sales.
At March 31, 2018, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments.
 
 
Sell (Short)
Contracts
 
Buy (Long)
Contracts
Designated as hedges under accounting rules:
 
 
 
 
Crude oil futures:
 
 
 
 
Contract volumes (1,000 bbls)
 
243

 
—

Weighted average contract price per bbl
 
$
62.41

 
$
—

 
 
 
 
 
Not qualifying or not designated as hedges under accounting rules:
 
 
 
 
Crude oil futures:
 
 
 
 
Contract volumes (1,000 bbls)
 
283

 
145

Weighted average contract price per bbl
 
$
63.92

 
$
64.68

Natural gas swaps:
 
 
 
 
Contract volumes (10,000 MMBTU)
 
275

 
—

Weighted average price differential per MMBTU
 
$
0.61

 
$
—

Natural gas futures:
 
 
 
 
Contract volumes (10,000 MMBTU)
 
35

 
275

Weighted average contract price per MMBTU
 
$
2.74

 
$
2.83

Diesel futures:
 
 
 
 
Contract volumes (1,000 bbls)
 
6

 
—

Weighted average contract price per bbl
 
$
1.94

 
$
—

NYM RBOB Gas futures:
 
 
 
 
Contract volumes (42,000 gallons)
 
24

 
16

Weighted average contract price per gallon
 
$
1.97

 
$
1.94

Fuel oil futures:
 
 
 
 
Contract volumes (1,000 bbls)
 
397

 
40

Weighted average contract price per bbl
 
$
54.55

 
$
54.03

Crude oil options:
 
 
 
 
Contract volumes (1,000 bbls)
 
70

 
20

Weighted average premium received
 
$
1.16

 
$
0.29

Financial Statement Impacts
Unrealized gains are subtracted from net income and unrealized losses are added to net income in determining cash flows from operating activities. To the extent that we have fair value hedges outstanding, the offsetting change recorded in the fair value of inventory is also eliminated from net income in determining cash flows from operating activities. Changes in margin deposits necessary to fund unrealized losses also affect cash flows from operating activities.

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

The following tables reflect the estimated fair value gain (loss) position of our derivatives at March 31, 2018 and December 31, 2017:
Fair Value of Derivative Assets and Liabilities
 
 
Unaudited Condensed Consolidated Balance Sheets Location
 
Fair Value
 
March 31,
2018
 
December 31,
2017
Asset Derivatives:
 
 
 
 
 
Commodity derivatives - futures and call options (undesignated hedges):
 
 
 
 
 
Gross amount of recognized assets
Current Assets - Other
 
$
394

 
$
505

Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other
 
(394
)
 
(505
)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives
 
 
$
—

 
$
—

Commodity derivatives - futures and call options (designated hedges):
 
 
 
 
 
Gross amount of recognized assets
Current Assets - Other
 
$
34

 
$
54

Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other
 
(34
)
 
(54
)
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
 
(48,106
)
 
(45,209
)
Natural Gas Swap (undesignated hedge)
Current Liabilities - Accrued Liabilities
 
(358
)
 
—

Commodity derivatives - futures and call options (undesignated hedges):
 
 
 
 
 
Gross amount of recognized liabilities
Current Assets - Other (1)
 
$
(1,001
)
 
$
(1,203
)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 
1,001

 
1,203

Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives
 
 
$
—

 
$
—

Commodity derivatives - futures and call options (designated hedges):
 
 
 
 
 
Gross amount of recognized liabilities
Current Assets - Other (1)
 
$
(646
)
 
$
(863
)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets
Current Assets - Other (1)
 
646

 
338

Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets related to commodity derivatives
 
 
$
—

 
$
(525
)
 (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 established by the respective exchange.  On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation

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

margin.  As of March 31, 2018, we had a net broker receivable of approximately $1.9 million consisting of our initial margin balance of $1.9 million.  As of December 31, 2017, we had a net broker receivable of approximately $1.0 million (consisting of initial margin of $1.3 million decreased by $0.3 million of variation margin).  At March 31, 2018 and December 31, 2017, none of our outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to us upon any change in our credit ratings. 
Preferred Distribution Rate Reset Election    
A derivative feature embedded in a contract that does not meet the definition of a derivative in its entirety must be bifurcated and accounted for separately if the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract. For a period of 30 days following (i) September 1, 2022 and (ii) each subsequent anniversary thereof, the holders of our preferred units may make a one-time election to reset the quarterly distribution amount (a "Rate Reset Election") to a cash amount per preferred unit equal to the amount that would be payable per quarter if a preferred unit accrued interest on the Issue Price at an annualized rate equal to three-month LIBOR plus 750 basis points; provided, however, that such reset rate shall be equal to 10.75% if (i) such alternative rate is higher than the LIBOR-based rate and (ii) the then market price for our common units is then less than 110% of the Issue Price. The Rate Reset Election of our preferred units represents an embedded derivative that must be bifurcated from the related host contract and recorded at fair value on our Unaudited Condensed Consolidated Balance Sheet. Corresponding changes in fair value are recognized in Other Expense in our Unaudited Condensed Consolidated Statement of Operations. At March 31, 2018, the fair value of this embedded derivative was a liability of $48.1 million. See Note 10 for additional information regarding our preferred units and the Rate Reset Election.
Effect on Operating Results 
 
 
 
Amount of Gain (Loss) Recognized in Income
 
Unaudited Condensed Consolidated Statements of Operations Location
 
Three Months Ended
March 31,
 
 
2018
 
2017
Commodity derivatives - futures and call options:
 
 
 
 
 
Contracts designated as hedges under accounting guidance
Onshore facilities and transportation product costs
 
$
(1,366
)
 
$
6,286

Contracts not considered hedges under accounting guidance
Onshore facilities and transportation product costs, sodium minerals and sulfur services operating costs
 
(332
)
 
1,093

Total commodity derivatives
 
 
$
(1,698
)
 
$
7,379

 
 
 
 
 
 
Natural Gas Swap Liability
Sodium minerals and sulfur services operating costs
 
$
(275
)
 
$
—

 
 
 
 
 
 
Preferred Distribution Rate Reset Election
Other expense
 
$
(1,906
)
 
$
—

16. Fair-Value Measurements
We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value:
(1)
Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;
(2)
Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and
(3)
Level 3 fair values are based on unobservable inputs in which little or no market data exists.

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

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 March 31, 2018 and December 31, 2017. 
 
 
Fair Value at
 
Fair Value at
 
 
March 31, 2018
 
December 31, 2017
Recurring Fair Value Measures
 
Level 1
 
Level 2
 
Level 3
 
Level 1
 
Level 2
 
Level 3
Commodity derivatives:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
$
428

 
$
—

 
$
—

 
$
559

 
$
—

 
$
—

Liabilities
 
$
(1,647
)
 
$
(358
)
 
$
—

 
$
(2,066
)
 
$
—

 
$
—

Preferred Distribution Rate Reset Election
 
$
—

 
$
—

 
$
(48,106
)
 
$
—

 
$
—

 
$
(45,209
)

Rollforward of Level 3 Fair Value Measurements

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

 
Three months ended March 31,
 
2018
Balance as of December 31, 2017
(45,209)
Net Loss for the period included in earnings
(1,906)
Allocation of Distribution Paid-in-kind
(991)
Balance as of March 31, 2018
(48,106)


Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy. The fair value of the swaps contracts was determined using market price quotations and a pricing model. The swap contracts were considered a level 2 input in the fair value hierarchy at March 31, 2018.
The fair value of the embedded derivative feature is based on a valuation model that estimates the fair value of our preferred units with and without a Rate Reset Election. This model contains inputs, including our common unit price, a ten year history of the dividend yield, default probabilities and timing estimates which involve management judgment. A significant increase or decrease in the value of these inputs could result in a material change in fair value to this embedded derivative feature. We report unrealized gains and losses associated with this embedded derivative in our Unaudited Condensed Consolidated Statements of Operations as Other income (expense), net.
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 March 31, 2018 our senior unsecured notes had a carrying value and fair value of $2.5 billion compared to $2.6 billion and $2.7 billion, respectively, at December 31, 2017. 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.
    
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

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

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.
In the second quarter of 2017, we recorded a non-cash provision of $12.6 million (included within Onshore facilities and transportation operating costs in our Unaudited Condensed Consolidated Statements of Operations during that period) relating to certain leased railcars no longer in use. As of March 31, 2018, our remaining provision is $9.3 million, of which $3.9 million is recorded as current and included in accrued liabilities in our Unaudited Condensed Consolidated Balance Sheet, with the remainder included in other long-term liabilities.

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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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