GENESIS ENERGY LP - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)



Delaware	76-0513049
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

919 Milam, Suite 2100, Houston, TX	77002
(Address of principal executive offices)	(Zip code)
Registrant’s telephone number, including area code: (713) 860-2500

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. There were 109,939,221 Class A Common Units and 39,997 Class B Common Units outstanding as of November 5, 2015.

Table of Contents

GENESIS ENERGY, L.P.

TABLE OF CONTENTS



		Page
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	4
	Unaudited Condensed Consolidated Statements of Partners’ Capital	5
	Unaudited Condensed Consolidated Statements of Cash Flows	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
	1. Organization and Basis of Presentation and Consolidation	7
	2. Recent Accounting Developments	8
	3. Acquisition and Divestiture	8
	4. Inventories	11
	5. Fixed Assets	11
	6. Equity Investees	12
	7. Intangible Assets	14
	8. Debt	14
	9. Partners' Capital and Distributions	15
	10. Business Segment Information	16
	11. Transactions with Related Parties	18
	12. Supplemental Cash Flow Information	19
	13. Derivatives	20
	14. Fair-Value Measurements	23
	15. Contingencies	24
	16. Condensed Consolidating Financial Information	24
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	55
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
SIGNATURES		58

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except units)



	September 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	15,568		$	9,462
Accounts receivable - trade, net	243,372			271,529
Inventories	49,069			46,829
Other	37,387			27,546
Total current assets	345,396			355,366
FIXED ASSETS, at cost	4,163,909			1,899,058
Less: Accumulated depreciation	(337,087		)	(268,057		)
Net fixed assets	3,826,822			1,631,001
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income	141,343			145,959
EQUITY INVESTEES	493,190			628,780
INTANGIBLE ASSETS, net of amortization	229,457			82,931
GOODWILL	325,046			325,046
OTHER ASSETS, net of amortization	87,991			61,291
TOTAL ASSETS	$	5,449,245		$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable - trade	$	168,118		$	245,405
Accrued liabilities	157,988			117,740
Total current liabilities	326,106			363,145
SENIOR SECURED CREDIT FACILITY	1,014,100			550,400
SENIOR UNSECURED NOTES	1,839,933			1,050,639
DEFERRED TAX LIABILITIES	20,997			18,754
OTHER LONG-TERM LIABILITIES	182,915			18,233
COMMITMENTS AND CONTINGENCIES (Note 15)
PARTNERS’ CAPITAL:
Common unitholders, 109,979,218 and 95,029,218 units issued and outstanding at September 30, 2015 and December 31, 2014, respectively	2,072,030			1,229,203
Noncontrolling interests	(6,836		)	—
Total partners' capital	2,065,194			1,229,203
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	5,449,245		$	3,230,374

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES:
Onshore pipeline transportation services	19,909			20,349			57,910			62,992
Offshore pipeline transportation services	61,388			974			63,436			2,443
Refinery services	43,332			51,208			135,780			158,202
Marine transportation	60,536			57,000			180,501			169,241
Supply and logistics	387,169			834,583			1,317,891			2,606,004
Total revenues	572,334			964,114			1,755,518			2,998,882
COSTS AND EXPENSES:
Supply and logistics product costs	354,331			791,411			1,217,374			2,485,068
Supply and logistics operating costs	24,585			27,434			73,606			82,526
Marine transportation operating costs	33,869			34,864			100,749			107,543
Refinery services operating costs	22,363			29,031			75,225			93,374
Onshore pipeline transportation operating costs	6,721			6,917			19,874			22,113
Offshore pipeline transportation operating costs	17,698			276			18,341			941
General and administrative	26,799			13,765			54,852			40,471
Depreciation and amortization	41,170			25,148			96,500			64,919
Total costs and expenses	527,536			928,846			1,656,521			2,896,955
OPERATING INCOME	44,798			35,268			98,997			101,927
Equity in earnings of equity investees	14,260			15,017			48,440			27,757
Interest expense	(29,617		)	(20,441		)	(66,737		)	(47,314		)
Gain on basis step up on historical interest	335,260			—			335,260			—
Other income/(expense), net	—			—			(17,529		)	—
Income before income taxes	364,701			29,844			398,431			82,370
Income tax expense	(1,292		)	(731		)	(3,142		)	(2,334		)
NET INCOME	363,409			29,113			395,289			80,036
Net income attributable to noncontrolling interests	(195		)	—			(195		)	—
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.	$	363,214		$	29,113		$	395,094		$	80,036
NET INCOME PER COMMON UNIT:
Basic and Diluted	$	3.38		$	0.33		$	3.93		$	0.90
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted	107,617			88,941			100,653			88,775

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)



	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Total
Partners’ capital, January 1, 2015	95,029	$	1,229,203		$	—		$	1,229,203
Net income	—	395,094			195			395,289
Noncontrolling interest from acquisition	—	—			(6,471		)	(6,471		)
Cash distributions to partners, net	—	(186,026		)	—			(186,026		)
Cash distributions to noncontrolling interests	—	—			(560		)	(560		)
Issuance of common units for cash, net	14,950	633,759			—			633,759
Partners' capital, September 30, 2015	109,979	$	2,072,030		$	(6,836	)	$	2,065,194
	Number of Common Units	Partners’ Capital			Noncontrolling Interest			Total
Partners’ capital, January 1, 2014	88,691	$	1,097,737		$	—		$	1,097,737
Net income	—	80,036			—			80,036
Cash distributions to partners, net	—	(146,350		)	—			(146,350		)
Cash distributions to noncontrolling interests	—	—			—			—
Issuance of common units for cash, net	4,600	225,610			—			225,610
Partners' capital, September 30, 2014	93,291	$	1,257,033		$	—		$	1,257,033

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

Table of Contents

GENESIS ENERGY, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	395,289		$	80,036
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization	96,500			64,919
Gain on basis step up on historical interest	(335,260		)	—
Amortization of debt issuance costs and premium	8,467			3,541
Amortization of unearned income and initial direct costs on direct financing leases	(11,286		)	(11,833		)
Payments received under direct financing leases	15,501			15,946
Equity in earnings of investments in equity investees	(48,440		)	(27,757		)
Cash distributions of earnings of equity investees	54,463			38,031
Non-cash effect of equity-based compensation plans	6,387			7,624
Deferred and other tax liabilities	2,242			1,234
Unrealized loss (gain) on derivative transactions	68			(5,680		)
Other, net	816			3,008
Net changes in components of operating assets and liabilities (Note 12)	7,381			39,050
Net cash provided by operating activities	192,128			208,119
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	(359,504		)	(336,061		)
Cash distributions received from equity investees - return of investment	19,360			11,352
Investments in equity investees	(2,900		)	(40,426		)
Acquisitions	(1,517,428		)	—
Proceeds from asset sales	2,571			178
Other, net	(2,137		)	(4,706		)
Net cash used in investing activities	(1,860,038		)	(369,663		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,168,850			1,420,900
Repayments on senior secured credit facility	(705,150		)	(1,668,700		)
Proceeds from issuance of senior unsecured notes	1,139,718			350,000
Repayment of senior unsecured notes	(350,000		)	—
Debt issuance costs	(28,361		)	(11,857		)
Issuance of common units for cash, net	633,759			225,610
Distributions to noncontrolling interests	(560		)	—
Distributions to common unitholders	(186,026		)	(146,350		)
Other, net	1,786			—
Net cash provided by financing activities	1,674,016			169,603
Net increase in cash and cash equivalents	6,106			8,059
Cash and cash equivalents at beginning of period	9,462			8,866
Cash and cash equivalents at end of period	$	15,568		$	16,925

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation and Consolidation

Organization

We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. We are owned 100% by our limited partners. Our general partner, Genesis Energy, LLC, is a wholly-owned subsidiary. Our general partner has sole responsibility for conducting our business and managing our operations. We conduct our operations and own our operating assets through our subsidiaries and joint ventures. We manage our businesses through the following five divisions that constitute our reportable segments:


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


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


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


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


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

On July 24, 2015, we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its affiliates for approximately $1.5 billion, subject to certain adjustments. That business includes interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms that serve some of the most active drilling and development regions in the United States, including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. At the closing of that transaction, we entered into transition service agreements to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. That acquisition complements and substantially expands our existing offshore pipelines segment.

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, 2014, as amended and superseded in part in Genesis' Current Report on Form 8-K filed on July 2, 2015.

Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Table of Contents

2. Recent Accounting Developments

Recently Issued

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

In May 2014, the FASB issued revised guidance on revenue from contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard provides a five-step analysis for transactions to determine when and how revenue is recognized. The guidance permits the use of either a full retrospective or a modified retrospective approach. In July 2015, the FASB approved a one year deferral of the effective date of this standard to December 15, 2017 for annual reporting periods beginning after that date. The FASB also approved early adoption of the standard, but not before the original effective date of December 15, 2016. We are evaluating the transition methods and the impact of the amended guidance on our financial position, results of operations and related disclosures.

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

3. Acquisition and Divestiture

Acquisition

Enterprise Offshore

On July 24, 2015, we completed the Enterprise acquisition for $1.5 billion, subject to certain adjustments. That business includes interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms, including a 36% interest in the Poseidon Oil Pipeline System, a 50% interest in the Southeast Keathley Canyon Oil Pipeline System, and a 50% interest in the Cameron Highway Oil Pipeline System. To finance that transaction, in July, we issued 10,350,000 common units in a public offering that generated proceeds of $437.2 million net of underwriter discounts and $750 million aggregate principal amount of 6.75% senior unsecured notes due 2022 that generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The remainder of that transaction was financed with borrowings under our senior secured credit facility.

We have reflected the financial results of the acquired business in our offshore pipeline transportation segment from the date of acquisition. The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Those preliminary fair values were developed by management with the assistance of a third-party valuation firm and are subject to change pending a final valuation report and final determination of working capital acquired and other purchase price adjustments. We expect to finalize the purchase price allocation for this transaction during the fourth quarter of 2015. We do not expect any material adjustments to these preliminary purchase price allocations as a result of the final valuation.

Table of Contents

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



Cash	$	1,087
Accounts receivable	28,783
Inventories	600
Other current assets	3,504
Fixed assets	1,229,807
Intangible assets	79,416
Equity investees	353,841
Accounts payable	(6,464		)
Accrued liabilities	(15,017		)
Other long-term liabilities	(163,513		)
Noncontrolling interest	6,471
Total purchase price	$	1,518,515

Fixed assets identified in connection with our valuation and preliminary purchase price allocation include crude oil pipelines, natural gas pipelines and related assets. We will depreciate these assets on a straight line basis over estimated useful lives ranging from 2 to 35 years depending on the nature of each asset.

Intangible assets identified in connection with our valuation and preliminary purchase price allocation relate to customer contracts surrounding certain transportation agreements with producers in the Lucius production area in Southeast Keathley Canyon, which support our SEKCO pipeline. We will amortize these intangible assets on a straight line basis over an estimated useful life of 19 years.

In connection with our valuation and preliminary purchase price allocation, we have identified asset retirement obligations ("AROs") relating to the crude oil pipelines, natural gas pipelines and related assets with a preliminary fair value of $158.1 million. Of these AROs, $7.7 million of retirement costs are estimated to be incurred within the next year and thus are included in accrued liabilities in the table above, as well as on our Unaudited Condensed Consolidated Balance Sheet. The remainder of the AROs recorded as a result of the Enterprise acquisition are included within "Other long-term liabilities" in the table above, as well as on our Unaudited Condensed Consolidated Balance Sheet. See further discussion of AROs assumed as a result of the Enterprise acquisition in Note 5.

Noncontrolling interest as shown in the able above relates to the preliminary fair value assigned to the 20% ownership interest of our joint venture partner in Independence Hub, LLC, a consolidated subsidiary acquired as a result of the Enterprise acquisition in which we have an 80% ownership interest.

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



	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Revenues	$	44,713	$	44,713
Net income	$	24,471	$	24,471

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

Table of Contents



	Three Months Ended September 30,				Nine Months Ended September 30,
Pro forma consolidated financial operating results:	2015		2014		2015		2014
Revenues	$	590,994	$	1,049,349	$	1,930,978	$	3,205,331
Net Income Attributable to Genesis Energy L.P.	$	372,548	$	38,573	$	392,988	$	91,466
Basic and diluted earnings per unit:
As reported net income per unit	$	3.38	$	0.33	3.93		$	0.90
Pro forma net income per unit	$	3.39	$	0.39	$	3.63	$	0.92

As relating to the Enterprise acquisition, we have incurred approximately $13 million in acquisition related costs through September 30, 2015. Such costs are included as "General and Administrative costs" on our Unaudited Condensed Consolidated Statement of Operations.

M/T American Phoenix

On November 13, 2014, we acquired the M/T American Phoenix from Mid Ocean Tanker Company for $157 million. The M/T American Phoenix is a modern double-hulled, Jones Act qualified tanker with 330,000 barrels of cargo capacity that was placed into service during 2012.

The purchase price of $157 million was paid to Mid Ocean Tanker Company in cash, as funded with proceeds from available and committed liquidity under our $1.5 billion revolving credit facility. We have reflected the financial results of the acquired business in our marine transportation segment from the date of acquisition. We have recorded the assets acquired in the Consolidated Financial Statements at their fair values. Those fair values were developed by management.

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



Property and equipment	$	125,000
Intangible assets	32,000
Total purchase price	$	157,000

Our Consolidated Financial Statements include the results of our acquired offshore marine transportation business since November 13, 2014, the effective closing date of the acquisition. The following table presents selected financial information included in our Consolidated Financial Statements for the periods presented:



	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Revenues	$	5,637	$	16,859
Net income	$	1,381	$	4,052

The table below presents selected unaudited pro forma financial information incorporating the historical results of our M/T American Phoenix. The pro forma financial information below has been prepared as if the acquisition had been completed on January 1, 2014 and is based upon assumptions deemed appropriate by us and may not be indicative of actual results. Depreciation expense for the fixed assets acquired is calculated on a straight-line basis over an estimated useful life of approximately 30 years.



	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Pro forma consolidated financial operating results:
Revenues	$	969,127	$	3,013,597
Net Income	$	30,471	$	84,022

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4. Inventories

The major components of inventories were as follows:



	September 30, 2015		December 31, 2014
Petroleum products	$	14,500	$	30,108
Crude oil	28,352		7,266
Caustic soda	3,265		2,850
NaHS	2,952		6,603
Other	—		2
Total	$	49,069	$	46,829

Inventories are valued at the lower of cost or market. The market value of inventories was below recorded costs by approximately $1.1 million and $6.6 million at September 30, 2015 and December 31, 2014, respectively; therefore we reduced the value of inventory in our Condensed Consolidated Financial Statements for this difference.

5. Fixed Assets

Fixed Assets

Fixed assets consisted of the following:



	September 30, 2015			December 31, 2014
Crude oil pipelines and natural gas pipelines and related assets	$	2,481,871		$	466,613
Machinery and equipment	406,512			376,672
Transportation equipment	19,459			18,479
Marine vessels	770,362			731,016
Land, buildings and improvements	41,304			38,037
Office equipment, furniture and fixtures	7,481			6,696
Construction in progress	390,464			222,233
Other	46,456			39,312
Fixed assets, at cost	4,163,909			1,899,058
Less: Accumulated depreciation	(337,087		)	(268,057		)
Net fixed assets	$	3,826,822		$	1,631,001

Our depreciation expense for the periods presented was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Depreciation expense	$	33,716	$	20,736	$	78,265	$	52,422

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. As a result of the Enterprise acquisition of the offshore pipeline and services business of Enterprise Products Partners, L.P. on July 24, 2015, we recorded AROs based on the fair value measurement assigned during the preliminary purchase price allocation.

The following table presents information regarding our AROs since December 31, 2014:



ARO liability balance, December 31, 2014	$	14,790
AROs arising from the Enterprise acquisition	158,133
AROs from the consolidation of historical interests in CHOPS and SEKCO	1,988
Accretion Expense	2,781
Settlements	(384		)
ARO liability balance, September 30, 2015	$	177,308

Of the ARO balances disclosed above, $7.7 million is included as current in "Accrued liabilities" on our Unaudited Condensed Consolidated Balance Sheet, as of September 30, 2015. The remainder of the ARO liability as of September 30, 2015, as well as ARO liability as of December 31, 2014, are 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	2015	$	3,420
	2016	$	8,997
	2017	$	9,611
	2018	$	10,291
	2019	$	11,488

Certain of our unconsolidated affiliates have AROs recorded at September 30, 2015 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Financial Statements.

6. Equity Investees

We account for our ownership in our joint ventures under the equity method of accounting. The price we pay to acquire an ownership interest in a company may exceed the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our equity investees. At September 30, 2015 and December 31, 2014, the unamortized excess cost amounts totaled $419.6 million and $215.4 million, respectively. We amortize the excess cost as a reduction in equity earnings in a manner similar to depreciation.

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

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Genesis’ share of operating earnings	$	17,944		$	17,600		$	57,607		$	35,506
Amortization of excess purchase price	(3,684		)	(2,583		)	(9,167		)	(7,749		)
Net equity in earnings	$	14,260		$	15,017		$	48,440		$	27,757
Distributions received	$	23,522		$	21,758		$	73,823		$	49,383

The following tables present the combined unaudited balance sheet and income statement information (on a 100% basis) of our equity investees:



	September 30, 2015		December 31, 2014
BALANCE SHEET DATA:
Assets
Current assets	$	34,168	$	42,135
Fixed assets, net	546,311		1,015,305
Other assets	2,776		4,369
Total assets	$	583,255	$	1,061,809
Liabilities and equity
Current liabilities	$	10,718	$	25,369
Other liabilities	222,729		202,613
Equity	349,808		833,827
Total liabilities and equity	$	583,255	$	1,061,809



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
INCOME STATEMENT DATA:
Revenues	$	73,281	$	74,801	$	227,924	$	171,065
Operating income	$	45,496	$	46,096	$	150,017	$	99,199
Net income	$	34,195	$	44,881	$	136,342	$	96,402

Poseidon's revolving credit facility

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

7. Intangible Assets

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



	September 30, 2015						December 31, 2014
	Gross Carrying Amount		Accumulated Amortization		Carrying Value		Gross Carrying Amount		Accumulated Amortization		Carrying Value
Refinery Services:
Customer relationships	$	94,654	$	85,184	$	9,470	$	94,654	$	81,880	$	12,774
Licensing agreements	38,678		31,016		7,662		38,678		28,983		9,695
Segment total	133,332		116,200		17,132		133,332		110,863		22,469
Supply & Logistics:
Customer relationships	35,430		31,563		3,867		35,430		30,228		5,202
Intangibles associated with lease	13,260		3,868		9,392		13,260		3,512		9,748
Segment total	48,690		35,431		13,259		48,690		33,740		14,950
Marine contract intangibles	32,000		4,583		27,417		32,000		833		31,167
Offshore pipeline contract intangibles	158,831		1,393		157,438		—		—		—
Other	21,798		7,587		14,211		22,797		8,452		14,345
Total	$	394,651	$	165,194	$	229,457	$	236,819	$	153,888	$	82,931

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Amortization of intangible assets	$	5,554	$	3,148	$	13,745	$	9,440

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



Remainder of	2015	$	6,785
	2016	$	24,014
	2017	$	22,850
	2018	$	20,735
	2019	$	16,422

8. Debt

Our obligations under debt arrangements consisted of the following:



	September 30, 2015		December 31, 2014
Senior secured credit facility	$	1,014,100	$	550,400
7.875% senior unsecured notes (including unamortized premium of $639 in 2014)	—		350,639
6.000% senior unsecured notes	400,000		—
5.750% senior unsecured notes	350,000		350,000
5.625% senior unsecured notes	350,000		350,000
6.750% senior unsecured notes (including unamortized discount of $10,067 in 2015)	739,933		—
Total long-term debt	$	2,854,033	$	1,601,039

As of September 30, 2015, we were in compliance with the financial covenants contained in our credit agreement and senior unsecured notes indentures.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Senior Secured Credit Facility

The Enterprise acquisition meaningfully expanded our size and is expected to improve our credit metrics over the longer-term, which we believe should help accelerate an increase in our credit ratings in the future. In connection with our expanded size and improved credit outlook, we amended our senior secured credit facility (which matures on July 28, 2019) in the third quarter of 2015 to, among other things, (i) increase our committed amount to $1.5 billion, (ii) provide that, if and when we achieve specified investment grade ratings, certain restrictive covenants will cease to apply and the applicable margin for both alternate base rate and Eurodollar loans and the commitment fee on the unused committed amount will be reduced by specified amounts, (iii) immediately provide us more operational flexibility by relaxing certain covenants, including by increasing certain applicable limits and baskets, and (iv) increase the inventory financing sublimit amount, which is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate, from $150 million to $200 million.

The key terms for rates under our $1.5 billion senior secured credit facility, which are dependent on our leverage ratio (as defined in the credit agreement), are as follows:

•The applicable margin varies from 1.50% to 2.50% on Eurodollar borrowings and from 0.50% to 1.50% on alternate base rate borrowings.

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

•The commitment fee on the unused committed amount will range from 0.250% to 0.375%.

•The accordion feature is $500 million, giving us the ability to expand the size of the facility up to $2.0 billion for acquisitions or growth projects, subject to lender consent.

At September 30, 2015, we had $1.0 billion borrowed under our $1.5 billion credit facility, with $34.5 million of the borrowed amount designated as a loan under the inventory sublimit. Our credit agreement allows up to $100 million of the capacity to be used for letters of credit, of which $16.6 million was outstanding at September 30, 2015. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date. The total amount available for borrowings under our credit facility at September 30, 2015 was $469.3 million.

On September 17, 2015, we amended our $1.5 billion credit agreement which provides that, if and when we achieve specified investment grade ratings, certain restrictive covenants will cease to apply and the applicable margin for both alternate base rate and Eurodollar loans and the commitment fee on the unused committed amount will be reduced by specified amounts. The amendment also increases the inventory financing sublimit amount from $150 million to $200 million.

Senior Unsecured Note Issuance and Repayment

On July 23, 2015, we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due 2022. Interest payments are due on February 1 and August 1 of each year with the initial interest payment due February 1, 2016. Those notes mature on August 1, 2022. That issuance generated net proceeds of $728.6 million net of issuance discount and underwriting fees. The net proceeds were used to fund a portion of the purchase price for our Enterprise acquisition.

On May 21, 2015, we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes due 2023. Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Those notes mature on May 15, 2023. We used a portion of the proceeds from those notes to effectively redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018, using a combination of public tender offer and our redemption rights relating to those notes. The aggregate principal amount of the 7.875% notes totaling $300.1 million were tendered and the remaining $49.9 million were redeemed in full. A total loss of approximately $19.2 million for the tender and redemption of notes is recorded to "Other income/(expense), net" in our Consolidated Statements of Operations.

9. Partners’ Capital and Distributions

At September 30, 2015, our outstanding common units consisted of 109,939,221 Class A units and 39,997 Class B units.

On July 22, 2015, we issued 10,350,000 Class A common units in a public offering at a price of $43.77 per unit, which included the exercise by the underwriters of an option to purchase up to 1,350,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $437.2 million from that offering. We used the net proceeds to fund a portion of the purchase price for our Enterprise acquisition.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On April 10, 2015, we issued 4,600,000 Class A common units in a public offering at a price of $44.42 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $198 million from that offering. We intend to use the net proceeds for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility.

Distributions

We paid or will pay the following distributions in 2014 and 2015:



Distribution For	Date Paid		Per Unit Amount		Total Amount
2014
1^st Quarter	May 15, 2014		$	0.5500	$	48,783
2^nd Quarter	August 14, 2014		$	0.5650	$	50,114
3^rd Quarter	November 14, 2014		$	0.5800	$	54,112
4^th Quarter	February 13, 2015		$	0.5950	$	56,542
2015
1^st Quarter	May 15, 2015		$	0.6100	$	60,774
2^nd Quarter	August 14, 2015		$	0.6250	$	68,737
3^rdQuarter	November 13, 2015	⁽¹⁾	$	0.6400	$	70,387

(1) This distribution will be paid to unitholders of record as of October 30, 2015.

10. Business Segment Information

In the fourth quarter of 2014, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates resources. The results of our marine transportation activities, formerly reported in the Supply and Logistics Segment, are now reported in our Marine Transportation Segment. In addition, the results of our offshore and onshore pipeline transportation activities, formerly reported in the Pipeline Transportation Segment, are now reported separately in our Onshore Pipeline Transportation Segment and Offshore Pipeline Transportation Segment. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

As a result of the above changes, we currently manage our businesses through five divisions that constitute our reportable segments:


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


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


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


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


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

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

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases.

Our 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.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Segment information for the periods presented below was as follows:



	Onshore Pipeline Transportation		Offshore Pipeline Transportation		Refinery Services			Marine Transportation		Supply & Logistics			Total
Three Months Ended September 30, 2015
Segment margin (a)	$	14,984	$	70,943	$	20,692		$	26,583	$	7,508		$	140,710
Capital expenditures (b)	$	45,933	$	1,520,268	$	118		$	12,489	$	43,942		$	1,622,750
Revenues:
External customers	$	16,735	$	61,388	$	45,738		$	58,490	$	389,983		$	572,334
Intersegment (c)	3,174		—		(2,406		)	2,046		(2,814		)	—
Total revenues of reportable segments	$	19,909	$	61,388	$	43,332		$	60,536	$	387,169		$	572,334
Three Months Ended September 30, 2014
Segment margin (a)	$	15,354	$	21,666	$	21,855		$	22,077	$	13,838		$	94,790
Capital expenditures (b)	$	11,340	$	23,949	$	1,254		$	14,987	$	88,347		$	139,877
Revenues:
External customers	$	15,715	$	974	$	53,930		$	53,901	$	839,594		$	964,114
Intersegment (c)	4,634		—		(2,722		)	3,099		(5,011		)	—
Total revenues of reportable segments	$	20,349	$	974	$	51,208		$	57,000	$	834,583		$	964,114
Nine Months Ended September 30, 2015
Segment Margin (a)	$	43,670	$	121,241	$	60,073		$	79,501	$	28,913		$	333,398
Capital expenditures (b)	$	155,417	$	1,522,407	$	1,568		$	40,151	$	136,568		$	1,856,111
Revenues:
External customers	$	48,422	$	63,436	$	142,959		$	173,733	$	1,326,968		$	1,755,518
Intersegment (c)	9,488		—		(7,179		)	6,768		(9,077		)	—
Total revenues of reportable segments	$	57,910	$	63,436	$	135,780		$	180,501	$	1,317,891		$	1,755,518
Nine Months Ended September 30, 2014
Segment Margin (a)	$	46,574	$	46,504	$	64,354		$	61,512	$	35,878		$	254,822
Capital expenditures (b)	$	39,081	$	37,525	$	2,153		$	63,023	$	240,997		$	382,779
Revenues:
External customers	$	50,454	$	2,443	$	166,589		$	156,883	$	2,622,513		$	2,998,882
Intersegment (c)	12,538		—		(8,387		)	12,358		(16,509		)	—
Total revenues of reportable segments	$	62,992	$	2,443	$	158,202		$	169,241	$	2,606,004		$	2,998,882

Total assets by reportable segment were as follows:



	September 30, 2015		December 31, 2014
Onshore pipeline transportation	$	552,920	$	460,012
Offshore pipeline transportation	2,661,783		645,668
Refinery services	395,291		403,703
Marine transportation	752,116		745,128
Supply and logistics	995,589		907,189
Other assets	91,546		68,674
Total consolidated assets	5,449,245		3,230,374


(a)	A reconciliation of Segment Margin to net income 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. In addition to construction of growth projects, capital spending in our

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

pipeline transportation segment included $0.7 million and $2.5 million during the three and nine months ended September 30, 2015 and $23.4 million and $36.1 million during the three and nine months ended September 30, 2014 representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline.


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

Reconciliation of Segment Margin to net income:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Segment Margin	$	140,710		$	94,790		$	333,398		$	254,822
Corporate general and administrative expenses	(25,940		)	(12,865		)	(52,192		)	(37,715		)
Depreciation and amortization	(41,170		)	(25,148		)	(96,500		)	(64,919		)
Interest expense	(29,617		)	(20,441		)	(66,737		)	(47,314		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ⁽¹⁾	(7,962		)	(6,741		)	(25,383		)	(20,326		)
Non-cash items not included in Segment Margin	1,316			1,653			473			1,935
Cash payments from direct financing leases in excess of earnings	(1,448		)	(1,404		)	(4,215		)	(4,113		)
Gain on step up of historical basis in CHOPS and SEKCO	335,260			—			335,260			—
Loss on extinguishment of debt	—			—			(19,225		)	—
Other, net	(6,643		)	—			(6,643		)	—
Income tax expense	(1,292		)	(731		)	(3,142		)	(2,334		)
Net income attributable to Genesis Energy, L.P.	$	363,214		$	29,113		$	395,094		$	80,036


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

11. Transactions with Related Parties

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Revenues:
Sales of CO₂ to Sandhill Group, LLC ⁽¹⁾	$	913	$	867	$	2,418	$	2,235
Sales to Poseidon Oil Pipeline Company, LLC ⁽²⁾	1,980		—		1,980		—
Sales to Deepwater Gateway, LLC ⁽³⁾	33		—		33		—
Costs and expenses:
Amounts paid to our CEO in connection with the use of his aircraft	$	165	$	150	$	525	$	450
Expenses from Poseidon Oil Pipeline Company, LLC ⁽²⁾	241		—		241		—
Expenses from Deepwater Gateway, LLC ⁽³⁾	—		—		—		—


(1)	We own a 50% interest in Sandhill Group, LLC.


(2)	We own 64% interest in Poseidon Oil Pipeline Company, LLC.


(3)	We own a 50% interest in Deepwater Gateway, LLC.

Amount due from Related Party

At September 30, 2015 and December 31, 2014 Sandhill Group, LLC owed us $0.3 million, respectively, for purchases of CO₂.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Transactions with Unconsolidated Affiliates

Poseidon

As part of our Enterprise acquisition, we became the operator of Poseidon in the third quarter of 2015. We provide management, administrative and pipeline operator services to Poseidon under an Operation and Management Agreement . Currently, that agreement renews automatically annually unless terminated by either party (as defined in the agreement). Our revenues for the three and nine months ended September 30, 2015 reflect $2 million, respectively, of fees we earned through the provision of services under that agreement.

Deepwater Gateway

As part of our Enterprise acquisition, we became the operator of Deepwater Gateway in the third quarter of 2015. We provide technical and administrative services to Deepwater Gateway under a Management Services Agreement. That agreement continues indefinitely until either party decides to exercise their termination rights (as defined in the agreement). Our revenues for the three and nine months ended September 30, 2015 reflect less than $0.1 million, respectively, of fees we earned through the provision of services under that agreement.

12. Supplemental Cash Flow Information

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



	Nine Months Ended September 30,
	2015			2014
(Increase) decrease in:
Accounts receivable	$	72,372		$	43,591
Inventories	(1,481		)	(14,060		)
Deferred charges	(7,256		)	—
Other current assets	(7,014		)	48,582
Increase (decrease) in:
Accounts payable	(70,980		)	(8,576		)
Accrued liabilities	21,740			(30,487		)
Net changes in components of operating assets and liabilities	7,381			39,050

Payments of interest and commitment fees, net of amounts capitalized, were $56.8 million and $46.3 million for the nine months ended September 30, 2015 and September 30, 2014, respectively. We capitalized interest of $11.9 million and $11.5 million during the nine months ended September 30, 2015 and September 30, 2014.

At September 30, 2015 and September 30, 2014, we had incurred liabilities for fixed and intangible asset additions totaling $50.2 million and $61.2 million, respectively, that had not been paid at the end of the third quarter, and, therefore, were not included in the caption “Payments to acquire fixed and intangible assets” under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

At September 30, 2015 we had incurred liabilities for other asset additions totaling $0.1 million, that had not been paid at the end of the third quarter and, therefore, were not included in the caption "Other, net" under Cash Flows from Investing Activities in the Unaudited Condensed Consolidated Statements of Cash Flows.

During the three months ended September 30, 2015, as a result of the Enterprise acquisition, we acquired the 50% ownership interest in each of CHOPS and SEKCO as previously held by Enterprise, resulting in 100% ownership interest by us in each of these subsidiaries. As a result, we recorded a one time $335 million non-cash gain from the step up in basis in our historical 50% ownership interest in each of CHOPS and SEKCO to fair value (resulting from the fair value assigned to the 50% ownership interest in each of CHOPS and SEKCO that we acquired from Enterprise, as derived from the preliminary purchase price allocation). This also results in the consolidation of CHOPS and SEKCO by us, resulting in the inclusion of the operating assets and liabilities on our Unaudited Condensed Consolidated Balance Sheet. As 50% of the operating assets and liabilities of CHOPS and SEKCO were based on our historical interest with no cash impact, these amounts relating to our historical interest were not included in net changes in components of operating assets and liabilities in the Unaudited Condensed Consolidated Statements of Cash Flows.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

13. Derivatives

Commodity Derivatives

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

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

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

At September 30, 2015, we had the following outstanding derivative commodity contracts that were entered into to economically hedge inventory or fixed price purchase commitments.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



	Sell (Short) Contracts		Buy (Long) Contracts
Designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	47		—
Weighted average contract price per bbl	$	46.81	$	—

Not qualifying or not designated as hedges under accounting rules:
Crude oil futures:
Contract volumes (1,000 bbls)	730		292
Weighted average contract price per bbl	$	44.88	$	46.77
Crude oil swaps:
Contract volumes (1,000 bbls)	280		—
Weighted average contract price per bbl	$	2.38	$	—
Diesel futures:
Contract volumes (1,000 bbls)	58		12
Weighted average contract price per gal	$	1.58	$	1.56
#6 Fuel oil futures:
Contract volumes (1,000 bbls)	465		105
Weighted average contract price per bbl	$	36.36	$	34.76
Crude oil options:
Contract volumes (1,000 bbls)	175		30
Weighted average premium received	$	1.68	$	0.21

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.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following tables reflect the estimated fair value gain (loss) position of our derivatives at September 30, 2015 and December 31, 2014:

Fair Value of Derivative Assets and Liabilities



	Unaudited Condensed Consolidated Balance Sheets Location	Fair Value
	Unaudited Condensed Consolidated Balance Sheets Location	September 30, 2015			December 31, 2014
Asset Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized assets	Current Assets - Other	$	1,515		$	16,383
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	(1,277		)	(2,310		)
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	238		$	14,073
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized assets	Current Assets - Other	$	—		$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other	—			—
Net amount of assets presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Liability Derivatives:
Commodity derivatives - futures and call options (undesignated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(1,277	)	$	(2,310	)
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	1,277			2,310
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—
Commodity derivatives - futures and call options (designated hedges):
Gross amount of recognized liabilities	Current Assets - Other ⁽¹⁾	$	(37	)	$	—
Gross amount offset in the Unaudited Condensed Consolidated Balance Sheets	Current Assets - Other ⁽¹⁾	37			—
Net amount of liabilities presented in the Unaudited Condensed Consolidated Balance Sheets		$	—		$	—


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

Our accounting policy is to offset derivative assets and liabilities executed with the same counterparty when a master netting arrangement exists. Accordingly, we also offset derivative assets and liabilities with amounts associated with cash margin. Our exchange-traded derivatives are transacted through brokerage accounts and are subject to margin requirements as established by the respective exchange. On a daily basis, our account equity (consisting of the sum of our cash balance and the fair value of our open derivatives) is compared to our initial margin requirement resulting in the payment or return of variation margin. As of September 30, 2015, we had a net broker receivable of approximately $4.9 million (consisting of initial margin of $4.9 million and unaffected by variation margin). As of December 31, 2014, we had a net broker receivable of approximately $2.8 million (consisting of initial margin of $2.4 million increased by $0.3 million of variation margin). At September 30, 2015 and December 31, 2014, 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.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Effect on Operating Results



		Amount of Gain (Loss) Recognized in Income
	Unaudited Condensed Consolidated Statements of Operations Location	Three Months Ended September 30,					Nine Months Ended September 30,
		2015		2014			2015			2014
Commodity derivatives - futures and call options:
Contracts designated as hedges under accounting guidance	Supply and logistics product costs	$	621	$	—		$	(1,214	)	$	—
Contracts not considered hedges under accounting guidance	Supply and logistics product costs	11,559		(8,738		)	6,545			(5,242		)
Total commodity derivatives		$	12,180	$	(8,738	)	$	5,331		$	(5,242	)

14. Fair-Value Measurements

We classify financial assets and liabilities into the following three levels based on the inputs used to measure fair value:


(1)	Level 1 fair values are based on observable inputs such as quoted prices in active markets for identical assets and liabilities;


(2)	Level 2 fair values are based on pricing inputs other than quoted prices in active markets for identical assets and liabilities and are either directly or indirectly observable as of the measurement date; and


(3)	Level 3 fair values are based on unobservable inputs in which little or no market data exists.

As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014.



	Fair Value at							Fair Value at
	September 30, 2015							December 31, 2014
Recurring Fair Value Measures	Level 1			Level 2		Level 3		Level 1			Level 2		Level 3
Commodity derivatives:
Assets	$	1,515		$	—	$	—	$	16,383		$	—	$	—
Liabilities	$	(1,314	)	$	—	$	—	$	(2,310	)	$	—	$	—

Our commodity derivatives include exchange-traded futures and exchange-traded options contracts. The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.

See Note 13 for additional information on our derivative instruments.

Other Fair Value Measurements

We believe the debt outstanding under our credit facility approximates fair value as the stated rate of interest approximates current market rates of interest for similar instruments with comparable maturities. At September 30, 2015 our senior unsecured notes had a carrying value of $1.8 billion and a fair value of $1.7 billion, compared to $1.1 billion and $1.0 billion, respectively, at December 31, 2014. The fair value of the senior unsecured notes is determined based on trade information in the financial markets of our public debt and is considered a Level 2 fair value measurement.

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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

15. Contingencies

We are subject to various environmental laws and regulations. Policies and procedures are in place to aid in monitoring compliance and detecting and addressing releases of crude oil from our pipelines or other facilities; however, no assurance can be made that such environmental releases may not substantially affect our business.

We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material effect on our financial position, results of operations, or cash flows.

16. Condensed Consolidating Financial Information

Our $1.9 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries, except Genesis Free State Pipeline, LLC, Genesis NEJD Pipeline, LLC and certain other minor subsidiaries. Genesis NEJD Pipeline, LLC is 100% owned by Genesis Energy, L.P., the parent company. The remaining non-guarantor subsidiaries are owned by Genesis Crude Oil, L.P., a guarantor subsidiary. Genesis Energy Finance Corporation has no independent assets or operations. See Note 8 for additional information regarding our consolidated debt obligations.

During the second quarter of 2015, the Company took action related to certain non-guarantor subsidiaries that resulted in these subsidiaries previously categorized as non-guarantor subsidiaries becoming wholly owned guarantor subsidiaries. The changes made to guarantor subsidiaries did not impact the Company's previously reported consolidated net operating results, financial position, or cash flows. The condensed consolidating balance sheet as of December 31, 2014 and the condensed consolidating statements of operations for the three and nine months ended September 30, 2014 as well as the condensed consolidating statements of cash flows for the nine months ended September 30, 2014 have been retrospectively adjusted to reflect these updates to our guarantor subsidiaries as though the subsidiaries had been guarantors in all periods presented.

During the third quarter of 2015, the Company determined the need to revise its disclosures and presentation with respect to the Condensed Consolidating Financial Information included in this footnote. These revisions relate solely to transactions between Genesis Energy, L.P. and its subsidiaries and only impact the information that is presented in the Condensed Consolidating Financial Information presented herein and does not affect the Consolidated Financial Statements in any way. The Company determined that adjustments to the presentation relating to advances to and from affiliates was necessary and were made. As such, the condensed consolidating balance sheet as of December 31, 2014 was adjusted to present advances to and from subsidiaries as non-current assets and liabilities. This resulted in the reclassification of such advances from current assets and liabilities to long term assets and liabilities. The condensed consolidated statement of cash flows for the nine months ended September 30, 2014 has also been adjusted to reflect these changes. There is also a schedule below that reflects all these adjustments and reconciles from what has been disclosed in previous filings to what we represent in the financial statements below.

The following is condensed consolidating financial information for Genesis Energy, L.P., the guarantor subsidiaries and the non-guarantor subsidiaries.

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

September 30, 2015



	Genesis Energy, L.P. (Parent and Co-Issuer)		Genesis Energy Finance Corporation (Co-Issuer)		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Genesis Energy, L.P. Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	6	$	—	$	13,044		$	2,518		$	—		$	15,568
Other current assets	75		—		317,334			12,428			(9		)	329,828
Total current assets	81		—		330,378			14,946			(9		)	345,396
Fixed assets, at cost	—		—		4,086,318			77,591			—			4,163,909
Less: Accumulated depreciation	—		—		(318,312		)	(18,775		)	—			(337,087		)
Net fixed assets	—		—		3,768,006			58,816			—			3,826,822
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	47,919		—		418,936			142,038			(150,102		)	458,791
Advances to affiliates	2,543,341		—		—			38,941			(2,582,282		)	—
Equity investees	—		—		493,190			—			—			493,190
Investments in subsidiaries	2,362,919		—		95,587			—			(2,458,506		)	—
Total assets	$	4,954,260	$	—	$	5,431,143		$	254,741		$	(5,190,899	)	$	5,449,245
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	28,197	$	—	$	318,185		$	7,749		$	(28,025	)	$	326,106
Senior secured credit facility	1,014,100		—		—			—			—			1,014,100
Senior unsecured notes	1,839,933		—		—			—			—			1,839,933
Deferred tax liabilities	—		—		20,997			—			—			20,997
Advances from affiliates	—		—		2,582,282			—			(2,582,282		)	—
Other liabilities	—		—		152,191			152,802			(122,078		)	182,915
Total liabilities	2,882,230		—		3,073,655			160,551			(2,732,385		)	3,384,051
Partners’ capital, common units	2,072,030		—		2,357,488			101,026			(2,458,514		)	2,072,030
Noncontrolling interests	—		—		—			(6,836		)	—			(6,836		)
Total liabilities and partners’ capital	$	4,954,260	$	—	$	5,431,143		$	254,741		$	(5,190,899	)	$	5,449,245

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Balance Sheet

December 31, 2014



	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	$	9	$	—	$	8,310		$	1,143		$	—		$	9,462
Other current assets	53		—		333,385			12,474			(8		)	345,904
Total current assets	62		—		341,695			13,617			(8		)	355,366
Fixed assets, at cost	—		—		1,823,556			75,502			—			1,899,058
Less: Accumulated depreciation	—		—		(251,171		)	(16,886		)	—			(268,057		)
Net fixed assets	—		—		1,572,385			58,616			—			1,631,001
Goodwill	—		—		325,046			—			—			325,046
Other assets, net	28,421		—		269,252			146,700			(154,192		)	290,181
Advances to affiliates	1,378,520		—		—			—			(1,378,520		)	—
Equity investees	—		—		628,780			—			—			628,780
Investments in subsidiaries	1,434,255		—		97,195			—			(1,531,450		)	—
Total assets	$	2,841,258	$	—	$	3,234,353		$	218,933		$	(3,064,170	)	$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	11,016	$	—	$	395,159		$	499		$	(43,529	)	$	363,145
Senior secured credit facility	550,400		—		—			—			—			550,400
Senior unsecured notes	1,050,639		—		—			—			—			1,050,639
Deferred tax liabilities	—		—		18,754			—			—			18,754
Advances from affiliates	—		—		1,366,697			11,823			(1,378,520		)	—
Other liabilities	—		—		18,233			110,663			(110,663		)	18,233
Total liabilities	1,612,055		—		1,798,843			122,985			(1,532,712		)	2,001,171
Partners’ capital	1,229,203		—		1,435,510			95,948			(1,531,458		)	1,229,203
Total liabilities and partners’ capital	$	2,841,258	$	—	$	3,234,353		$	218,933		$	(3,064,170	)	$	3,230,374

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2015



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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2014



	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:
Onshore pipeline transportation services	$	—		$	—	$	14,451		$	5,898		$	—		$	20,349
Offshore pipeline transportation services	—			—		974			—			—			974
Refinery services	—			—		52,047			2,192			(3,031		)	51,208
Marine transportation	—			—		57,000			—			—			57,000
Supply and logistics	—			—		834,583			—			—			834,583
Total revenues	—			—		959,055			8,090			(3,031		)	964,114
COSTS AND EXPENSES:
Supply and logistics costs	—			—		818,845			—			—			818,845
Marine transportation costs	—			—		34,864			—			—			34,864
Refinery services operating costs	—			—		29,331			2,167			(2,467		)	29,031
Onshore pipeline transportation operating costs	—			—		6,917			—			—			6,917
Offshore pipeline transportation operating costs	—			—		76			200			—			276
General and administrative	—			—		13,765			—			—			13,765
Depreciation and amortization	—			—		24,508			640			—			25,148
Total costs and expenses	—			—		928,306			3,007			(2,467		)	928,846
OPERATING INCOME	—			—		30,749			5,083			(564		)	35,268
Equity in earnings of subsidiaries	49,550			—		1,479			—			(51,029		)	—
Equity in earnings of equity investees	—			—		15,017			—			—			15,017
Interest (expense) income, net	(20,437		)	—		3,900			(3,904		)	—			(20,441		)
Income before income taxes	29,113			—		51,145			1,179			(51,593		)	29,844
Income tax expense	—			—		(985		)	254			—			(731		)
NET INCOME	$	29,113		$	—	$	50,160		$	1,433		$	(51,593	)	$	29,113

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2015



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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2014



	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:
Onshore pipeline transportation services	$	—		$	—	$	44,459		$	18,533		$	—		$	62,992
Offshore pipeline transportation services	—			—		2,443			—			—			2,443
Refinery services	—			—		155,470			12,838			(10,106		)	158,202
Marine transportation	—			—		169,241			—			—			169,241
Supply and logistics	—			—		2,606,004			—			—			2,606,004
Total revenues	—			—		2,977,617			31,371			(10,106		)	2,998,882
COSTS AND EXPENSES:
Supply and logistics costs	—			—		2,567,594			—			—			2,567,594
Marine transportation costs	—			—		107,543			—			—			107,543
Refinery services operating costs	—			—		91,322			12,225			(10,173		)	93,374
Onshore pipeline transportation operating costs	—			—		21,461			652			—			22,113
Offshore pipeline transportation operating costs	—			—		941			—			—			941
General and administrative	—			—		40,471			—			—			40,471
Depreciation and amortization	—			—		63,019			1,900			—			64,919
Total costs and expenses	—			—		2,892,351			14,777			(10,173		)	2,896,955
OPERATING INCOME	—			—		85,266			16,594			67			101,927
Equity in earnings of subsidiaries	127,343			—		5,051			—			(132,394		)	—
Equity in earnings of equity investees	—			—		27,757			—			—			27,757
Interest (expense) income, net	(47,307		)	—		11,798			(11,805		)	—			(47,314		)
Income before income taxes	80,036			—		129,872			4,789			(132,327		)	82,370
Income tax benefit (expense)	—			—		(2,462		)	128			—			(2,334		)
NET INCOME	$	80,036		$	—	$	127,410		$	4,917		$	(132,327	)	$	80,036

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2015



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

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2014



	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 (used in) provided by operating activities	$	73,525		$	—	$	216,907		$	25,769		$	(108,082	)	$	208,119
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed and intangible assets	—			—		(336,061		)	—			—			(336,061		)
Cash distributions received from equity investees - return of investment	38,236			—		11,352			—			(38,236		)	11,352
Investments in equity investees	(225,610		)	—		(40,426		)	—			225,610			(40,426		)
Intercompany transfers	(55,765		)	—		—			—			55,765			—
Repayments on loan to non-guarantor subsidiary	—			—		3,697			—			(3,697		)	—
Proceeds from asset sales	—			—		178			—			—			178
Other, net	—			—		(4,706		)	—			—			(4,706		)
Net cash used in investing activities	(243,139		)	—		(365,966		)	—			239,442			(369,663		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on senior secured credit facility	1,420,900			—		—			—			—			1,420,900
Repayments on senior secured credit facility	(1,668,700		)	—		—			—			—			(1,668,700		)
Proceeds from issuance of senior unsecured notes	350,000			—		—			—			—			350,000
Debt issuance costs	(11,857		)	—		—			—			—			(11,857		)
Intercompany transfers	—			—		78,031			(22,266		)	(55,765		)	—
Issuance of common units for cash, net	225,610			—		225,610			—			(225,610		)	225,610
Distributions to partners/owners	(146,350		)	—		(146,350		)	—			146,350			(146,350		)
Other, net	—			—		—			(3,665		)	3,665			—
Net cash provided by (used in) financing activities	169,603			—		157,291			(25,931		)	(131,360		)	169,603
Net (decrease) increase in cash and cash equivalents	(11		)	—		8,232			(162		)	—			8,059
Cash and cash equivalents at beginning of period	20			—		8,050			796			—			8,866
Cash and cash equivalents at end of period	$	9		$	—	$	16,282		$	634		$	—		$	16,925

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

See below for revisions to previously presented Condensed Consolidating Financial Information.



Balance Sheet Restatements	As Previously Reported		Adjustment		As Revised
December 31, 2014
Parent Column
Other current assets	1,378,573		(1,378,520	)	53
Total current assets	1,378,582		(1,378,520	)	62
Advances to affiliates	—		1,378,520		1,378,520
Guarantor Column
Current liabilities	1,761,856		(1,366,697	)	395,159
Advances from affiliates	—		1,366,697		1,366,697
Non Guarantor Column
Other current assets	46,215		(33,741	)	12,474
Total current assets	47,358		(33,741	)	13,617
Total assets	252,674		(33,741	)	218,933
Current liabilities	2,705		(2,206	)	499
Advances from affiliates	—		11,823		11,823
Other liabilities	154,021		(43,358	)	110,663
Total liabilities	156,726		(33,741	)	122,985
Total liabilities and partners' capital	252,674		(33,741	)	218,933
Eliminations Column
Other current assets	(1,412,269	)	1,412,261		(8	)
Total current assets	(1,412,269	)	1,412,261		(8	)
Advances to affiliates	—		(1,378,520	)	(1,378,520	)
Total assets	(3,097,911	)	33,741		(3,064,170	)
Current liabilities	(1,412,432	)	1,368,903		(43,529	)
Advances from affiliates	—		(1,378,520	)	(1,378,520	)
Other liabilities	(154,021	)	43,358		(110,663	)
Total liabilities	(1,566,453	)	33,741		(1,532,712	)
Total liabilities and partners' capital	(3,097,911	)	33,741		(3,064,170	)

Table of Contents

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Cash Flow Restatements	As Previously Reported		Adjustment		As Revised
September 30, 2014
Parent Column
Net cash provided by operating activities	17,760		55,765		73,525
Intercompany transfers (investing)	—		(55,765	)	(55,765	)
Net cash used in investing activities	(187,374	)	(55,765	)	(243,139	)
Guarantor Column
Net cash provided by operating activities	294,938		(78,031	)	216,907
Intercompany transfers (financing)	—		78,031		78,031
Net cash provided by (used in) financing activities	79,260		78,031		157,291
Non Guarantor Column
Net cash provided by operating activities	3,503		22,266		25,769
Intercompany transfers (financing)	—		(22,266	)	(22,266	)
Net cash provided by (used in) financing activities	(3,665	)	(22,266	)	(25,931	)
Eliminations Column
Intercompany transfers (investing)	—		55,765		55,765
Net cash used in investing activities	183,677		55,765		239,442
Intercompany transfers (financing)	—		(55,765	)	(55,765	)
Net cash provided by (used in) financing activities	(75,595	)	(55,765	)	(131,360	)

Table of Contents

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, 2014, as amended and superseded in part in Genesis' Current Report on Form 8-K filed on July 2, 2015.

Included in Management’s Discussion and Analysis are the following sections:


•	Overview


•	Segment Reporting Change


•	Financial Measures


•	Results of Operations


•	Liquidity and Capital Resources


•	Commitments and Off-Balance Sheet Arrangements


•	Forward Looking Statements

Overview

We reported Net Income Attributable to Genesis Energy, L.P. of $363.2 million, or $3.38 per common unit, during the three months ended September 30, 2015 (“2015 Quarter”) compared to net income of $29.1 million or $0.33 per common unit, during the three months ended September 30, 2014 (“2014 Quarter”). The large increase in our net income was principally due to the $335.3 million non-cash gain we recognized during the 2015 quarter resulting from a step up in basis to fair value of our historical interests in certain of our equity investees (CHOPS and SEKCO) as a result of our acquiring the remaining interest in those equity investees when we completed our Enterprise acquisition on July 24, 2015. A more detailed discussion of that acquisition is included below and a more detailed discussion of our related non-cash gain is included in the "Other Costs" section.

Available Cash before Reserves was $96.3 million for the 2015 Quarter, an increase of $35.5 million, or 58%, from the 2014 Quarter. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin (as described below in “Financial Measures”) was $140.7 million for the 2015 Quarter, an increase of $45.9 million, or 48%, from the 2014 Quarter.

The increase in our Segment Margin resulted primarily from increases attributable to our offshore pipeline transportation segment of $49.3 million. This increase is primarily related to assets recently acquired as part of our Enterprise acquisition. Those acquisitions similarly benefited Available Cash before Reserves and net income.

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

Distribution Increase

In October 2015, we declared our forty-first consecutive increase in our quarterly distribution to our common unitholders. Thirty-six of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In November 2015, we will pay a distribution of $0.64 per unit representing a 10.3% increase from our distribution of $0.58 per unit related to the third quarter of 2014.

Acquisition of Offshore Pipelines and Services Business of Enterprise Products Partners, L.P.

Table of Contents

To finance that transaction, in July, we issued 10,350,000 common units in a public offering that generated proceeds of $437.2 million net of underwriter discounts and $750 million aggregate principal amount of 6.75% senior unsecured notes due 2022 that generated proceeds of $728.6 million net of issuance discount and underwriting fees. The remainder of that transaction was financed with borrowings under our senior secured credit facility.

Segment Reporting Change

As a result of the above changes, we currently manage our businesses through five divisions that constitute our reportable segments - Onshore Pipeline Transportation, Offshore Pipeline Transportation, Refinery Services, Marine Transportation and Supply and Logistics. Our disclosures related to prior periods have been recast to reflect our reorganized segments.

Financial Measure Reconciliation

For definitions and discussion of the financial measures refer to the "Financial Measures" as later discussed and defined.

Available Cash before Reserves for the periods presented below was as follows:



	Three Months Ended September 30,
	2015			2014
	(in thousands)
Net income attributable to Genesis Energy, L.P.	$	363,214		$	29,113
Depreciation and amortization	41,170			25,148
Cash received from direct financing leases not included in income	1,448			1,404
Cash effects of sales of certain assets	343			45
Effects of distributable cash generated by equity method investees not included in income	7,962			6,741
Cash effects of legacy stock appreciation rights plan	(50		)	(129		)
Non-cash legacy stock appreciation rights plan expense	(553		)	(608		)
Expenses related to acquiring or constructing growth capital assets	12,766			688
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value	(192		)	(3,460		)
Maintenance capital utilized	(1,044		)	(242		)
Non-cash tax expense	992			381
Gain on step up of historical basis	(335,260		)	—
Other items, net	5,512			1,717
Available Cash before Reserves	96,308			60,798

Results of Operations

Revenues and Costs and Expenses

Our revenues for the 2015 Quarter decreased $391.8 million, or 41%, from the 2014 Quarter. Additionally, our costs and expenses decreased $401.3 million, or 43%, between the two periods.

The substantial majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products. The significant decrease in our revenues and costs between the two third quarter periods is primarily attributable to a decrease in market prices for crude oil and petroleum products as described below.

The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") decreased 52% to $46.43 per barrel in the third quarter of 2015, as compared to $97.17 per barrel in the third quarter of 2014.

Table of Contents

In general, we do not expect fluctuations in prices for oil and gas to affect our Segment Margin to the same extent they affect our revenues and costs. We have limited our direct commodity price exposure through the broad use of fee based service contracts, back-to-back purchase and sale arrangements, and hedges. As a result, changes in the price of oil would similarly impact both our revenues and our costs with a disproportionate smaller net impact on our Segment Margin.

Our indirect exposure to the impacts of changes in the price of crude oil are mitigated by our strategy of focusing on customers whose operations tend to be less adversely affected by decreases in the price of crude oil. These customers are refiners and other onshore customers who operate further down the energy value chain (as opposed to producers). Our crude oil pipelines in the Gulf of Mexico represent the single largest departure from our “refinery-centric” customer strategy. The shippers on those pipelines are mostly integrated and large independent energy companies who have developed, and continue to explore for, numerous large-reservoir, long-lived crude oil properties whose production is ideally suited for the vast majority of refineries along the Gulf Coast, unlike the lighter crude oil and condensates produced from numerous onshore shale plays. Those large-reservoir properties and the related pipelines and other infrastructure needed to develop them are capital intensive and yet, we believe, economically viable, in most cases, even in this lower commodity price environment.

Segment Margin

The contribution of each of our segments to total Segment Margin in the three and nine months ended September 30, 2015 and September 30, 2014 was as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
Onshore pipeline transportation	$	14,984	$	15,354	$	43,670	$	46,574
Offshore pipeline transportation	70,943		21,666		121,241		46,504
Refinery services	20,692		21,855		60,073		64,354
Marine transportation	26,583		22,077		79,501		61,512
Supply and logistics	7,508		13,838		28,913		35,878
Total Segment Margin	$	140,710	$	94,790	$	333,398	$	254,822

A reconciliation of Segment Margin to Net Income for the periods presented is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Segment Margin	$	140,710		$	94,790		$	333,398		$	254,822
Corporate general and administrative expenses	(25,940		)	(12,865		)	(52,192		)	(37,715		)
Depreciation and amortization	(41,170		)	(25,148		)	(96,500		)	(64,919		)
Interest expense	(29,617		)	(20,441		)	(66,737		)	(47,314		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income ₍₁₎	(7,962		)	(6,741		)	(25,383		)	(20,326		)
Non-cash items not included in Segment Margin	1,316			1,653			473			1,935
Cash payments from direct financing leases in excess of earnings	(1,448		)	(1,404		)	(4,215		)	(4,113		)
Gain on step up of historical basis	335,260			—			335,260			—
Loss on debt extinguishment	—			—			(19,225		)	—
Other, net	(6,643		)	—			(6,643		)	—
Income tax expense	(1,292		)	(731		)	(3,142		)	(2,334		)
Net income attributable to Genesis Energy, L.P.	$	363,214		$	29,113		$	395,094		$	80,036

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

Table of Contents

Our reconciliation of Segment Margin to net income reflects that Segment Margin (as defined above) excludes corporate general and administrative expenses, non-cash gains and charges, depreciation and amortization, interest expense, certain non-cash items, the most significant of which are the non-cash gain on step-up of historical basis in existing assets for which additional interest have been acquired, the non-cash effects of our stock appreciation rights plan and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Items in Segment Margin not included in net income are distributable cash from equity investees in excess of equity in earnings (or losses) and cash payments from direct financing leases in excess of earnings.

Onshore Pipeline Transportation Segment

Operating results and volumetric data for our onshore pipeline transportation segment are presented below:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	11,926		$	10,754		$	32,464		$	31,642
CO2 tariffs and revenues from direct financing leases of CO2 pipelines	5,882			6,014			18,358			18,888
Sales of onshore crude oil pipeline loss allowance volumes	1,172			2,378			3,775			7,233
Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(5,667		)	(5,433		)	(15,872		)	(16,080		)
Payments received under direct financing leases not included in income	1,448			1,404			4,215			4,113
Other	223			237			730			778
Segment Margin	$	14,984		$	15,354		$	43,670		$	46,574

Volumetric Data (average barrels/day unless otherwise noted):
Onshore crude oil pipelines:
Texas	68,675			61,907			70,815			57,175
Jay	17,547			22,759			17,041			24,965
Mississippi	16,963			14,460			16,246			14,918
Louisiana ⁽¹⁾	38,738			18,331			28,042			15,177
Wyoming ⁽²⁾	7,702			—			7,702			—
Onshore crude oil pipelines total	149,625			117,457			139,846			112,235

CO₂ pipeline (average Mcf/day):
Free State	145,947			144,588			167,805			171,388

(1) Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.

(2) Represents volumes per day from the period the pipeline began operations in August of 2015.

Table of Contents

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Onshore Pipeline Transportation Segment Margin for the 2015 Quarter decreased $0.4 million, or 2%. Certain significant components and details of this change were as follows:


•	Onshore crude oil pipeline loss allowance volumes, collected and sold, resulted in a decrease in segment margin quarter over quarter of $1.2 million. This decrease is primarily due to the change in the market price of crude oil between the respective periods. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on that system.

•

With respect to our onshore crude oil pipelines, tariff revenues increased by $1.2 million quarter to quarter, primarily due to a net increase in throughput volumes of 32,168 barrels per day or 27%. This was primarily the result of increased volumes on our Texas and Louisiana pipeline systems. These increases were partially offset by volume variances on our other onshore pipeline systems. Due to a mix of tariff rates on our onshore pipelines, the impact on onshore crude oil tariffs and revenues from these volume variances was an increase of 11%. As our Baton Rouge growth projects become completed and operational, we anticipate a continued ramp up in volumes on our Louisiana pipeline system in future periods.


•	This increase in pipeline tariff revenues was partially offset by an increase in operating costs, which include the effects of a $0.8 million charge due to an as yet unresolved measurement imbalance.

•

Although volumes on our Free State CO₂ pipeline system increased 1,359 Mcf per day, or 1%, in the 2015 Quarter as compared to the 2014 Quarter, that increase did not materially affect contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a base level on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Onshore Pipeline Transportation Segment Margin for the first nine months of 2015 decreased $2.9 million, or 6%. Certain significant components and details of this change were as follows:


•	Onshore crude oil pipeline loss allowance volumes, collected and sold, resulted in a decrease in segment margin quarter over quarter of $3.5 million. This decrease is primarily due to the change in the market price of crude oil between the respective periods. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on that system.

•

With respect to our onshore crude oil pipelines, tariff revenues increased by $0.8 million period to period, due to an overall net increase in throughput volumes of 27,611 barrels per day, which was primarily the result of increased volumes on our Texas and Louisiana pipeline systems. These increases were partially offset by a decrease in volumes on our Jay pipeline system, which is primarily attributable to a decrease in volumes entering the pipeline through our Walnut Hill rail facility. Due to a mix of tariff rates on our onshore pipelines, the impact on onshore crude oil tariffs and revenues from these volume variances largely offset each other.

•

Although volumes on our Free State CO₂ pipeline system decreased 3,583 Mcf per day, or 2%, in the first nine months of 2015 as compared to the first nine months of 2014, that decrease did not materially affect contributions to Segment Margin by that pipeline. We provide transportation services on our Free State CO₂pipeline system through an “incentive” tariff which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a base level on our Free State CO₂ pipeline system have a limited impact on Segment Margin.

Table of Contents

Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Offshore crude oil pipeline revenue	$	47,431		$	974		$	49,479		$	2,444
Offshore natural gas pipeline revenue	13,957			—			13,957			—
Offshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(17,698		)	(276		)	(18,341		)	(941		)
Distributions from equity investments	21,791			21,420			71,541			46,295
Other	5,462			(452		)	4,605			(1,294		)
Offshore Pipeline Transportation Segment Margin ⁽¹⁾	$	70,943		$	21,666		$	121,241		$	46,504

Volumetric Data 100% basis:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	176,479			186,470			171,774			182,371
Poseidon	264,862			213,855			256,277			208,696
Odyssey	90,419			51,314			63,536			45,626
SEKCO ⁽²⁾	78,008			—			56,962			—
GOPL	17,049			7,610			14,028			6,419
Total crude oil offshore pipelines	626,817			459,249			562,577			443,112

Natural gas transportation volumes (MMBtus/d) (3)	727,295			—			727,295			—

Volumetric Data net to our ownership interest as of September 30, 2015 and September 30, 2014:
Crude oil pipelines (average barrels/day unless otherwise noted):
CHOPS	176,479			186,470			171,774			182,371
Poseidon	169,512			136,867			164,017			133,565
Odyssey	26,222			14,881			18,425			13,232
SEKCO ⁽²⁾	78,008			—			56,962			—
GOPL	17,049			7,610			14,028			6,419
Total crude oil offshore pipelines	467,270			345,828			425,206			335,587

Natural gas transportation volumes (MMBtus/d) ⁽³⁾	448,043			—			448,043			—

(1)

Offshore Pipeline Transportation segment margin includes approximately $22 million and $72 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting for the three months and nine months ended September 30, 2015, respectively. Segment Margin for the three months and nine months ended September 30, 2014 include $21 million and $46 million in similar distributions from our offshore pipeline joint ventures, respectively.


(2)	Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO’s transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude until January 2015. Volumes reported for the nine months ended September 30, 2015 for SEKCO reflect the gradual commencement of throughput beginning in January of 2015.


(3)	Represents volumes per day from the period the pipelines and related assets were acquired in July 2015.

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Table of Contents

Offshore Pipeline Transportation Segment Margin for the 2015 Quarter increased $49.3 million, or 227%, from the 2014 Quarter. This increase is primarily due to the Enterprise acquisition, which closed in July 2015. As a result of the Enterprise acquisition we obtained approximately 2,350 miles of additional offshore natural gas and crude oil pipelines, including increasing our ownership interest in each of the Poseidon, SEKCO, and CHOPS pipelines, and six offshore hub platforms.

In addition, a portion of the increase in our Segment Margin is attributable to the SEKCO pipeline being completed and earning certain minimum fees and commencing throughput of crude in January 2015. For a portion of the 2015 Quarter, SEKCO pipeline's throughput exceeded its shippers' minimum volume commitments. Also, as a result of the Enterprise acquisition, our ownership interest in the SEKCO pipeline increased from 50% to 100% in the 2015 Quarter. Our SEKCO pipeline is connected to our Poseidon pipeline (of which we now own a 64% interest in as a result of our Enterprise acquisition, an increase from our historical 28% interest), so increases in throughput on our SEKCO pipeline also increases throughput on our Poseidon pipeline.

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Offshore Pipeline Transportation Segment Margin for the first nine months of 2015 increased $74.7 million, or 161%, from the first nine months of 2014. This increase is primarily due to the Enterprise acquisition, which closed in July 2015. As a result of the Enterprise acquisition we obtained approximately 2,350 miles of additional offshore natural gas and crude oil pipelines, including increasing our ownership interest in each of the Poseidon, SEKCO, and CHOPS pipelines, and six offshore hub platforms.

Table of Contents

Refinery Services Segment

Operating results for our refinery services segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Volumes sold (in Dry short tons "DST"):
NaHS volumes	30,721			36,431			95,654			114,940
NaOH (caustic soda) volumes	23,907			23,368			67,223			71,467
Total	54,628			59,799			162,877			186,407

Revenues (in thousands):
NaHS revenues	$	32,618		$	39,409		$	104,153		$	123,679
NaOH (caustic soda) revenues	11,329			12,312			33,217			37,099
Other revenues	1,791			2,209			5,589			5,811
Total external segment revenues	$	45,738		$	53,930		$	142,959		$	166,589

Segment Margin (in thousands)	$	20,692		$	21,855		$	60,073		$	64,354

Average index price for NaOH per DST ⁽¹⁾	$	563		$	588		$	576		$	588
Raw material and processing costs as % of segment revenues	38		%	42		%	41		%	42		%

(1) Source: IHS Chemical

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Refinery services Segment Margin for the 2015 Quarter decreased $1.2 million, or 5%. Certain significant components and details of this change were as follows:

•

NaHS revenues decreased 17% due primarily to a decrease in volumes. That decrease primarily resulted from lower total volumes than the 2014 Quarter attributable to the bankruptcy of one mining customer and reduced sales to a major customer as they work through an atypical ore seam as a result of a landslide, coupled with increased prior year volumes generated from heavy turn around schedules at certain customers.


•	We were able to realize benefits from our favorable management of the purchasing (including economies of scale) and utilization of caustic soda in our (and our customers') operations and our logistics management capabilities, which somewhat offset the effects on Segment Margin of decreased NaHS sales volumes.


•	Caustic soda revenues decreased 8% primarily due to a decrease in our sales price for caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities.

•

Average index prices for caustic soda decreased to $563 per DST in the 2015 Quarter compared to $588 per DST during the 2014 Quarter. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Refinery services Segment Margin for the first nine months of 2015 decreased $4.3 million, or 7%. Certain significant components and details of this change were as follows:

•

NaHS revenues decreased 16% primarily due to a decrease in volumes. That decrease primarily resulted from lower total volumes than the 2014 Quarter attributable to the bankruptcy of one mining customer and reduced sales to a major customer as they work through an atypical ore seam as a result of a landslide, coupled with increased prior year volumes generated from heavy turn around schedules at certain customers. Additionally,

Table of Contents

timing of certain bulk deliveries to our South American customers was a factor in decreased volumes for the nine months ended between September 30, 2015 and September 30, 2014.


•	We were able to realize benefits from our favorable management of the purchasing (including economies of scale) and utilization of caustic soda in our (and our customers') operations and our logistics management capabilities, which somewhat offset the effects on Segment Margin of decreased NaHS sales volumes.


•	Caustic soda revenues decreased 10% due to a reduction in our sales volumes, as well as a decrease in our sales price for caustic soda. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities.

•

Average index prices for caustic soda decreased to $576 per DST in the first nine months of 2015 compared to $588 per DST during the first nine months of 2014. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic soda on our operating costs.

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 71 barges (62 inland and 9 offshore) with a combined transportation capacity of 2.6 million barrels, 38 push/tow boats (29 inland and 9 offshore), and a 330,000 barrel ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Revenues (in thousands):
Inland freight revenues	$	23,970		$	24,340		$	71,967		$	68,637
Offshore freight revenues	26,630			20,091			76,908			58,852
Other rebill revenues ⁽¹⁾	9,936			12,569			31,626			41,752
Total segment revenues	$	60,536		$	57,000		$	180,501		$	169,241

Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	$	33,953		$	34,923		$	101,000		$	107,729

Segment Margin (in thousands)	$	26,583		$	22,077		$	79,501		$	61,512

Fleet Utilization: ⁽²⁾
Inland Barge Utilization	97.6		%	97.4		%	97.7		%	97.8		%
Offshore Barge Utilization	99.9		%	99.6		%	99.8		%	99.8		%

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

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

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Marine Transportation Segment Margin for the 2015 Quarter increased $4.5 million, or 20%, from the 2014 Quarter. This increase in Segment Margin in 2015 is primarily due to a full quarter of operating results from the M/T American Phoenix (included as part of our offshore marine fleet), which we acquired in November 2014, and higher realized contract rates on several of our oceangoing barges.

Utilization rates on both our inland and offshore barge fleets did not change significantly between the respective quarters. The decrease in operating costs, a large portion of which relate to fuel and other rebillable charges, was largely offset by the decrease in other rebill revenues.

Table of Contents

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Marine Transportation Segment Margin for the first nine months of 2015 increased $18.0 million, or 29%, from the first nine months of 2014. This increase in Segment Margin in 2015 is primarily due to three full quarters of operating results from the M/T American Phoenix (included as part of our offshore marine fleet), which we acquired in November 2014, and higher realized contract rates on several of our oceangoing barges.

Supply and Logistics Segment

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


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


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


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


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


•	purchasing products from refiners, transporting those products to one of our terminals and blending the products to a quality that meets the requirements of our customers and selling those products;


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


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

We also use our terminal facilities to take advantage of contango market conditions, to gather and market crude oil, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

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

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

We utilize our fleet of trucks, trailers, railcars, and leased and owned storage capacity to service our crude oil and refining customers and to store and blend the intermediate and finished refined products.

Table of Contents

Operating results from our supply and logistics segment were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Supply and logistics revenue	$	387,169		$	834,583		$	1,317,891		$	2,606,004
Crude oil and petroleum products costs, excluding unrealized gains and losses from derivative transactions	(354,551		)	(792,586		)	(1,215,242		)	(2,487,175		)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses	(24,772		)	(27,658		)	(73,607		)	(82,252		)
Other	(338		)	(501		)	(129		)	(699		)
Segment Margin	$	7,508		$	13,838		$	28,913		$	35,878

Volumetric Data (average barrels per day):
Crude oil and petroleum products sales:
Total crude oil and petroleum products sales	89,516			96,521			94,571			97,626
Rail load/unload volumes ⁽¹⁾	37,767			39,555			24,043			31,555

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

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014

Segment Margin for our supply and logistics segment decreased by $6.3 million, or 46%, between the two three month periods.

In the 2015 Quarter, the decrease in our Segment Margin is primarily due to lower demand, especially in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. We find it difficult to compete with certain persons in the market who are willing to lose money on such local gathering because they are attempting to minimize their losses from minimum volume or take-or-pay commitments they previously made in anticipation of new production that has not yet come online. We also incurred a $0.6 million charge to exit certain third-party tanks that we no longer needed to support our recently right-sized heavy fuel oil business. These decreases were somewhat offset by an increase in rail volumes at our Scenic Station rail terminal.

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

Segment Margin for our supply and logistics segment decreased by $7.0 million, or 19%, between the first nine months of 2015 and the first nine months of 2014.

In the nine months ended September 30, 2015, the decrease in our Segment Margin is primarily due to lower demand, especially in our historical back-to-back, or buy/sell, crude oil marketing business associated with aggregating and trucking crude oil from producers' leases to local or regional re-sale points. We find it difficult to compete with certain persons in the market who are willing to lose money on such local gathering because they are attempting to minimize their losses from minimum volume or take-or-pay commitments they previously made in anticipation of new production that has not yet come online. We also incurred a $0.6 million charge to exit certain third-party tanks that we no longer needed to support our recently right-sized heavy fuel oil business. These decreases were somewhat offset by an increase in rail volumes at our Scenic Station rail terminal.

Table of Contents

Other Costs, Interest, and Income Taxes

General and administrative expenses



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
General and administrative expenses not separately identified below:
Corporate	$	11,742	$	10,909	$	32,056	$	29,806
Segment	860		896		2,639		2,718
Equity-based compensation plan expense	1,431		1,272		4,982		6,057
Third party costs related to business development activities and growth projects	12,766		688		15,175		1,890
Total general and administrative expenses	$	26,799	$	13,765	$	54,852	$	40,471

Total general and administrative expenses increased $13.0 million and $14.4 million between the three and nine month periods primarily due to higher third party costs, primarily financing, legal and accounting, related to business development and growth activities (primarily related to third party costs incurred for business development activities surrounding the Enterprise acquisition as previously discussed).

Depreciation and amortization expense



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(in thousands)				(in thousands)
Depreciation expense	$	33,716	$	20,736	$	78,265	$	52,422
Amortization of intangible assets	5,554		3,148		13,745		9,440
Amortization of CO2 volumetric production payments	1,900		1,264		4,490		3,057
Total depreciation and amortization expense	$	41,170	$	25,148	$	96,500	$	64,919

Total depreciation and amortization expense increased $16.0 million and $31.6 million between the three and nine month periods primarily as a result of placing recently acquired and constructed assets' in service during calendar 2014 and the first nine months of 2015 (including the offshore pipelines and services assets acquired as a result of the Enterprise acquisition).

Interest expense, net



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)						(in thousands)
Interest expense, credit facility (including commitment fees)	$	6,888		$	3,898		$	15,054		$	12,070
Interest expense, senior unsecured notes	25,155			16,844			58,717			43,203
Amortization of debt issuance costs and premium	2,303			1,221			4,853			3,541
Capitalized interest	(4,729		)	(1,522		)	(11,887		)	(11,500		)
Net interest expense	$	29,617		$	20,441		$	66,737		$	47,314

Net interest expense increased $9.2 million and $19.4 million between the three and nine month periods primarily due to an increase in our average outstanding indebtedness from recently acquired and constructed assets, primarily related to additional debt outstanding as a result of financing our Enterprise acquisition. In May 2014, we issued an additional $350 million of aggregate principal amount of 5.625% senior unsecured notes to repay borrowings under our senior secured credit facility. In July 2015, we issued an additional $750 million of aggregate principal amount of 6.75% senior unsecured notes to fund a portion of the purchase price for our Enterprise acquisition. Capitalized interest costs increased $3.2 million and $0.4 million over the three and nine month periods due to our growth capital expenditures for projects still under construction when compared to prior year period.

Table of Contents

Income tax expense

A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

Other

Net income for the 2015 Quarter included an unrealized gain on derivative positions, excluding fair value hedges, of $1.2 million. Net income for the 2014 Quarter included an unrealized gain on derivative positions of $3.5 million. Net income for the nine months ended September 30, 2015 included an unrealized loss on derivative positions of $0.1 million. Net income for the same period in 2014 included an unrealized gain on derivative positions of $4.7 million. Those amounts are included in supply and logistics product costs in the Unaudited Condensed Consolidated Statements of Operations and are not a component of Segment Margin.

As a result of acquiring the remaining 50% interest in CHOPS and SEKCO in the Enterprise acquisition, we recognized a $335.3 million gain during the 2015 Quarter relating to the effects of the re-measurement of our pre-acquisition historical interest (prior to the acquisition, Genesis owned 50% of each of CHOPS and SEKCO) at fair value based on accounting guidance involving step acquisitions as discussed in ASC 805-10-25. A more detailed discussion of our Enterprise acquisition is included below.

The nine months ended September 30, 2015 also includes a loss of approximately $19.2 million that was recognized in relation to the early retirement of our $350 million, 7.875% senior unsecured notes.

Liquidity and Capital Resources

General

As of September 30, 2015, we had $469.3 million of borrowing capacity available under our $1.5 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.

Our primary cash requirements consist of:


•	working capital, primarily inventories and trade receivables and payables;


•	routine operating expenses;


•	capital growth and maintenance projects;


•	acquisitions of assets or businesses;


•	payments related to servicing outstanding debt; and


•	quarterly cash distributions to our unitholders.

Acquisition of Enterprise Offshore Pipelines and Services Business

On July 24, 2015, we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its affiliates for approximately $1.5 billion, subject to certain adjustments. That business includes interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms that serve some of the most active drilling and development regions in the United States, including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. At the closing of that transaction, we entered into a transition service agreement with affiliates of Enterprise to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. That acquisition complements and substantially expands our existing offshore pipelines segment and has been immediately accretive to Segment Margin and Available Cash before Reserves in the 2015 Quarter.

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

Table of Contents

other financing transactions—and to implement our growth strategy successfully. No assurance can be made that we will be able to raise additional capital on satisfactory terms or implement our growth strategy successfully.

On April 10, 2015, we issued 4,600,000 Class A common units in a public offering at a price of $44.42 per unit, which included the exercise by the underwriters of an option to purchase up to 600,000 additional common units from us. We received proceeds, net of underwriting discounts and offering costs, of approximately $198 million from that offering. We used the net proceeds for general partnership purposes, including funding acquisitions (including organic growth projects) or repaying a portion of the borrowings outstanding under our revolving credit facility.

On July 23, 2015, we issued $750 million in aggregate principal amount of 6.75% senior unsecured notes due 2022. The net proceeds were used to fund a portion of the purchase price for our Enterprise acquisition. Those notes were issued at a discount which generated net proceeds of $728.6 million net of issuance discount and underwriting fees. Interest payments are due on February 1 and August 1 of each year with the initial interest payment due on February 1, 2016. Those notes mature on August 1, 2022.

On May 21, 2015, we issued $400 million in aggregate principal amount of 6.0% senior unsecured notes at face value. Interest payments are due on May 15 and November 15 of each year with the initial interest payment due November 15, 2015. Those notes mature on May 15, 2023. We used a portion of the proceeds from those notes to effectively redeem all of our outstanding $350 million, 7.875% senior unsecured notes due 2018, using a combination of a public tender offer and our redemption rights relating to those notes. We recognized a loss of approximately $19.2 million in conjunction therewith.

At September 30, 2015, long-term debt totaled $2.9 billion, consisting of $1,014.1 million outstanding under our credit facility (including $34.5 million borrowed under the inventory sublimit tranche), a $350 million carrying amount of senior unsecured notes due on February 15, 2021, a $400 million carrying amount of senior unsecured notes due on May 15, 2023, a $350 million carrying amount of senior unsecured notes due on June 15, 2024, and a $750 million carrying amount of senior unsecured notes due August 1, 2022.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our credit facility and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem, as we make payments and receive payments for the purchase and sale of crude oil.

In our petroleum products activities, we buy products, and typically either move the products to one of our storage facilities for further blending or we sell the products within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.

The storage of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the 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 prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.

See Note 12 in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities for the nine months ended September 30, 2015 and September 30, 2014.

Table of Contents

The decrease in operating cash flow for the nine months ended September 30, 2015 compared to the same period in 2014 was primarily due to increases in working capital needs. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our working capital and, therefore, our operating cash flows between periods as the cost to acquire a barrel of oil or petroleum products will require more or less cash. Net cash flows provided by our operating activities for the nine months ended September 30, 2015 were $192.1 million compared to $208.1 million for the nine months ended September 30, 2014.

Capital Expenditures and Distributions Paid to our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, organic growth projects and distributions we pay to our unitholders. We finance maintenance capital expenditures and smaller organic growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and organic growth projects) with borrowings under our credit facility, equity issuances and/or the issuance of senior unsecured notes.

Capital Expenditures and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, business and other asset acquisitions for the nine months ended September 30, 2015 and September 30, 2014 is as follows:



	Nine Months Ended September 30,
	2015		2014
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Onshore pipeline transportation assets	$	4,958	$	3,302
Offshore pipeline transportation assets	615		1,429
Refinery services assets	1,528		1,709
Marine transportation assets	24,719		3,741
Supply and logistics assets	6,807		383
Information technology systems	322		444
Total maintenance capital expenditures	38,949		11,008
Growth capital expenditures:
Onshore pipeline transportation assets	150,459		35,779
Offshore pipeline transportation assets	377		20
Refinery services assets	40		444
Marine transportation assets	15,432		59,282
Supply and logistics assets	129,761		240,614
Information technology systems	1,115		514
Total growth capital expenditures	297,184		336,653
Total capital expenditures for fixed and intangible assets	336,133		347,661
Capital expenditures for business combinations, net of liabilities assumed:
Acquisition of offshore pipelines ⁽¹⁾	1,518,515		—
Total business combinations capital expenditures	1,518,515		—
Capital expenditures related to equity investees ⁽²⁾	2,900		36,076
Total capital expenditures	$	1,857,548	$	383,737

(1) Amounts represent our purchase price (subject to adjustments) for our Enterprise acquisition.

(2) Amounts represent our investment in our SEKCO pipeline equity investee prior to our Enterprise acquisition.

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.

Table of Contents

Growth Capital Expenditures

Total capital expenditures on projects under construction are estimated to be approximately $900 million in 2015 and in future periods, inclusive of expenditures incurred through September 30, 2015. We anticipate that approximately $440 million of that total will be spent in 2015, inclusive of expenditures incurred through September 30, 2015. The most significant of these projects currently under construction are described below.

Houston Area Crude Oil Pipeline and Terminal Infrastructure

We are constructing new, and expanding existing, crude oil pipeline and terminal facilities in Webster, Texas and Texas City, Texas as a result of expanding our crude oil pipeline and terminal infrastructure in the Houston area. We will construct a new crude oil pipeline that will deliver crude oil received from upstream crude oil pipelines (including CHOPS, which delivers crude oil originating in the deepwater Gulf of Mexico to the Texas City area) to our new Texas City Terminal, which will ultimately connect to our existing 18-inch Webster to Texas City crude oil pipeline. Our new Texas City Terminal will include initially approximately 750,000 barrels of crude oil tankage. We will also expand storage capacity at our Webster, Texas Terminal to allow for up to an additional 750,000 barrels of crude oil tankage at Webster. Our Webster Terminal is connected to other crude oil pipelines servicing other Houston area refineries. As a part of this project, we are also making the necessary upgrades on our existing 18-inch Webster to Texas City crude oil pipeline to allow for bi-directional flow. The result of this expanded crude oil infrastructure will allow additional optionality to Houston and Baytown area refineries, including the Exxon-Mobil Baytown refinery, its largest refinery in the U.S.A., and provide additional delivery outlets for other crude oil pipelines. We expect these assets to become operational in the second half of 2016.

Wyoming Crude Oil Pipeline

In the third quarter of 2015, we completed construction of a new 60 mile crude oil pipeline to transport crude oil from new receipt point stations in Campbell County and Converse County, Wyoming to our existing Pronghorn Rail Facility. This new crude oil pipeline has an initial capacity of approximately 30,000 barrels per day and is supplied by truck volumes and third party gathering infrastructure in the Powder River Basin.

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

Baton Rouge Terminal

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

Raceland Rail Facility

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

Inland Marine Barge Transportation Expansion

We ordered 20 new-build barges and 14 new-build push boats for our inland marine barge transportation fleet. We have accepted delivery of 8 of those barges and 2 of those push boats through December 31, 2014. We accepted delivery of 8 additional push boats in the first three quarters of 2015. We expect to take delivery of those remaining vessels periodically into 2016.

Acquisition of Enterprise Offshore Pipelines and Services Business

In July 2015, we acquired the offshore pipeline and services business of Enterprise Products Partners, L.P. and its affiliates for approximately $1.5 billion, subject to certain adjustments. That business includes interests in approximately 2,350 miles of offshore crude oil and natural gas pipelines and six offshore hub platforms that serve some of the most active drilling

Table of Contents

and development regions in the United States, including deepwater production fields in the Gulf of Mexico offshore Texas, Louisiana, Mississippi and Alabama. At the closing of that transaction, we entered into a transition service agreement with affiliates of Enterprise to facilitate a smooth transition of operations and uninterrupted services for both employees and customers. That acquisition complements and substantially expands our existing offshore pipelines segment and has been immediately accretive to Segment Margin and Available Cash before Reserves in the 2015 Quarter.

Maintenance Capital Expenditures

Our increase in maintenance capital expenditures for the nine months ended September 30, 2015 primarily relates to construction of new marine push boats to replace older boats. For the nine months ended September 30, 2015 we spent approximately $10 million on the construction of those replacement push boats. As we place more assets into service, particularly our marine transportation assets, our maintenance capital expenditures may continue to increase in future years. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before reserves.

Distributions to Unitholders

On November 13, 2015, we will pay a distribution of $0.64 per common unit totaling $70.4 million with respect to the third quarter of 2015 to common unitholders of record on October 30, 2015 inclusive of the holders of units issued on April 10, 2015, as well as those issued on July 22, 2015. This is the forty-first consecutive quarter in which we have increased our quarterly distribution. Information on our recent distribution history is included in Note 9 to our Unaudited Condensed Consolidated Financial Statements.

Non- GAAP Financial Measures

General

To evaluate our business, we use certain financial measures ("non-GAAP" measures) that are not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP. 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. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

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 accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure - income from continuing operations. 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 measures is just one 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.

Table of Contents

Segment Margin

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distibutable 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.

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

Available Cash before Reserves

Purposes, Uses and Definition

Available Cash before Reserves, also referred to as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:


(1)	the financial performance of our assets;


(2)	our operating performance;


(3)	the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;


(4)	the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and


(5)	our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

We define Available Cash before Reserves as net income as adjusted for specific items, the most significant of which are the addition of certain non-cash gains or charges (including depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees (includes distributions attributable to the quarter and received during or promptly following such quarter), the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows and the subtraction of maintenance capital utilized, which is described in detail below.

Recent Change in Circumstances and Disclosure Format

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

Maintenance Capital Requirements

MAINTENANCE CAPITAL EXPENDITURES

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

Historically, substantially all of our maintenance capital expenditures have been (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible.

Table of Contents

An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

Prospectively, we believe a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those future expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

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

MAINTENANCE CAPITAL UTILIZED

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

Because we have not historically used our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013. Further, we do not have the actual comparable calculations for our prior periods, and we may not have the information necessary to make such calculations for such periods. And, even if we could locate and/or re-create the information necessary to make such calculations, we believe it would be unduly burdensome to do so in comparison to the benefits derived.

Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Commercial Commitments

There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2014.

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, 2014, nor do we have any debt or equity triggers based upon our unit or commodity prices.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,”

Table of Contents

“intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:


•	demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;


•	throughput levels and rates;


•	changes in, or challenges to, our tariff rates;


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


•	service interruptions in our pipeline transportation systems and processing operations;


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


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


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


•	the effects of production declines and the effects of future laws and government regulation;


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


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


•	loss of key personnel;


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


•	an increase in the competition that our operations encounter;


•	cost and availability of insurance;


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


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


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


•	natural disasters, accidents or terrorism;


•	changes in the financial condition of customers or counterparties;


•	adverse rulings, judgments, or settlements in litigation or other legal or tax matters;


•	the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and


•	the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014. These risks may also be specifically described in our Quarterly Reports on Form 10-Q,

Table of Contents

Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2014. There have been no material changes that would affect the quantitative and qualitative disclosures provided therein. Also, see Note 13 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this Quarterly Report on Form 10-Q is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

There were no changes during the third quarter of 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

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, 2014. There have been no material developments in legal proceedings since the filing of such Form 10-K.

Item 1A. Risk Factors

There has been no material change in our risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, except as supplemented by our Quarterly Reports on Form 10-Q and Periodic Reports on Form 8-K and Form 8-K/A, including those contained in our Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015. For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014, as well as any risk factors contained in other filings with the SEC, including Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Table of Contents

Item 6. Exhibits.

(a) Exhibits



	2.1	Purchase and Sale Agreement, dated July 16, 2015, by and between Genesis Energy, L.P. and Enterprise Products Operating, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K/A dated July 16, 2015, File No. 001-12295).
	3.1	Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Registration Statement on Form S-1, File No. 333-11545).
	3.2	Amendment to the Certificate of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.2 to Form 10-Q for the quarterly period ended June 30, 2011, File No. 011-12295).
	3.3	Fifth Amended and Restated Agreement of Limited Partnership of Genesis Energy, L.P. (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 3, 2011, File No. 001-12295).
	3.4	Certificate of Conversion of Genesis Energy, Inc. a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.5	Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009, File No. 001-12295).
	3.6	Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, File No. 001-12295).
	4.1	Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007, File No. 001-12295).
*	4.2	Fifth Supplemental Indenture for 6.000% Senior Notes due 2023 and 6.750% Senior Notes due 2022, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.3	Ninth Supplemental Indenture for 5.625% Senior Notes due 2024, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
*	4.4	Tenth Supplemental Indenture for 5.75% Senior Notes due 2021, dated as of September 22, 2015, among Genesis Energy, L.P., Genesis Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as trustee.
	10.1	Third Amendment to Fourth Amended and Restated Credit Agreement dates as of September 17, 2015 among Genesis Energy, L.P., as the borrower, Wells Fargo Bank, National Association, as administrative agent and issuing bank, Bank of America, N.A. and Bank of Montreal, as co-syndication agents, U.S. Bank National Association, as documentation agent, and the lenders party thereto incorporated by reference to Exhibit 10.1 to Form 8-K dated September 23, 2015, File number 1-12294).
*	31.1	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	31.2	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934.
*	32	Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934.
*	101.INS	XBRL Instance Document
*	101.SCH	XBRL Schema Document
*	101.CAL	XBRL Calculation Linkbase Document
*	101.LAB	XBRL Label Linkbase Document
*	101.PRE	XBRL Presentation Linkbase Document
*	101.DEF	XBRL Definition Linkbase Document



*	Filed herewith

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		GENESIS ENERGY, L.P. (A Delaware Limited Partnership)

	By:	GENESIS ENERGY, LLC, as General Partner



Date:	November 6, 2015	By:	/s/ ROBERT V. DEERE
			Robert V. Deere
			Chief Financial Officer