Exhibit

The biggest challenge we faced in the quarter, which could last for some time, was 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 will closely monitor developments and seek to re-deploy our trucking assets and endeavors to areas not operating under such distorted conditions. We also took an approximate $0.6 million charge to exit certain third-party tanks that we no longer need to support our recently right-sized historical heavy fuel oil business. Crude-by-rail volumes almost doubled relative to second quarter of 2015, as we are ramping up operations in our infrastructure supporting the ExxonMobil refinery complex in Baton Rouge, the fourth largest refinery in North America.

Our onshore pipelines segment experienced increased throughputs in the aggregate, both sequentially and over the year earlier period. Financial results for the quarter were negatively impacted by an approximately $0.8 million charge due to an as yet unresolved measurement imbalance as well as an almost $1.2 million decrease in pipeline loss allowance revenues attributable primarily to the drop in crude oil prices from the year earlier period.

Our marine group continues to perform well. As we have previously disclosed, our fleet of inland barges, all but four of which employ internal heaters, is among the largest and youngest fleets of that particular type of tank barge on the inland waterways and works, almost exclusively, directly for refiners moving hot, intermediate refined products from one refinery location to another. Our American Phoenix tanker transitioned to a five year contract with Phillips 66 at the end of the quarter. Our ocean g

oing barge fleet continues to maintain a high utilization rate. We expect, however, to experience a drag of perhaps as much as $2 million on margin in the fourth quarter because two units will undergo scheduled regulatory dry dockings, and perhaps as much as $3 million on margin in the first quarter of 2016 because three other units will undergo scheduled regulatory dry dockings during that quarter. After this relatively bunched schedule, we are working to smooth the required out of service times for our fleet of nine units prospectively.

This quarter also reflected the first contribution of our newly acquired offshore pipelines and services assets. Their financial performance met or exceeded our expectations, and we remain confident in the resiliency of the deepwater Gulf of Mexico as a world class basin for the economic and efficient exploitation of known, and to be discovered, hydrocarbons.

We are also pleased to announce we have executed long-term agreements with ExxonMobil supporting the construction of new crude oil infrastructure in the greater Houston area to support ExxonMobil's refinery complex in Baytown, Texas, the second largest refinery in North America. Additionally, we have entered into agreements with a large investment grade operator in Wyoming to support the construction of additional infrastructure upstream of our existing, first-mover facilities in Converse and Campbell Counties in Wyoming, as well as the construction of a pipeline down to Guernsey, Wyoming to provide the maximum flexibility for our contracted party and those operators with whom we continue to pursue long-term agreements. Both of these projects are expected to be completed in mid-2016 and to contribute late next year and accelerate into 2017 and beyond.

The total cost of these new endeavors is approximately $350 million, some of which was already expended at quarter end. We have more than sufficient committed liquidity under our recently upsized revolver to fully execute these projects. The excess coverage currently being generated by our existing operations, even in this interesting environment, represents the equity, so to speak, in these new projects. In other words, we would not expect the need to go to the equity, quasi-equity or debt capital markets to fully fund our continuing growth. While our calculated leverage ratio will creep above 5X over the next 3 or 4 quarters, we would expect growth in cash available for distributions (i.e. Available Cash before Reserves) to exceed growth in distributions, the difference in which will be used to pay down debt, de-lever our capital structure and approach our goal of a long-term leverage ratio of plus or minus 3.75 turns.

Our business strategies that we have previously outlined, coupled with our complementary acquisitions and growth projects that will be ramping up throughout the end of this year and into 2017, should position us well to continue to achieve our goals of delivering low double-digit growth in distributions, an increasing coverage ratio and an investment grade leverage ratio, all without ever losing our cultural focus on providing safe, responsible and reliable services."

Available Cash before Reserves was $96.3 million in the third quarter of 2015 (or "2015 Quarter"). The primary components impacting Available Cash before Reserves are Segment Margin, corporate general and administrative expenses (excluding certain non-cash charges), interest expense and maintenance capital utilized.



	Three Months Ended September 30,
	2015		2014
	(in thousands)
Onshore pipeline transportation	$	14,984	$	15,354
Offshore pipeline transportation	70,943		21,666
Refinery services	20,692		21,855
Marine transportation	26,583		22,077
Supply and logistics	7,508		13,838
Total Segment Margin⁽¹⁾	$	140,710	$	94,790

(1) We define Segment Margin, which is a "non-GAAP" measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S. (GAAP) as revenues less product costs, operating expenses (excluding non-cash gains and charges, such as depreciation and amortization), and segment general and administrative expenses (excluding corporate 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 stock appreciation rights plan and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Our Segment Margin definition includes the non-income portion of payments received under direct financing leases. A reconciliation of Segment Margin to net income is presented for periods presented in the table at the end of this release.

Onshore pipeline transportation Segment Margin decreased $0.4 million, or 2%, between the third quarter periods. That decrease was primarily the result of a $1.2 million decrease in revenue generated from the sale of pipeline loss allowance volumes, principally related to the decrease in the market price of crude oil between the respective periods. These results also include a $0.8 million charge due to an as yet unresolved measurement imbalance. These items were partially offset by an increase in tariff revenues mainly on our Texas and Louisiana pipeline systems.

Offshore pipeline transportation Segment Margin increased $49.3 million, or 227%, between the third quarter periods. 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.

Refinery services Segment Margin decreased $1.2 million, or 5%, between the third quarter periods. 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.

Marine transportation Segment Margin increased $4.5 million or 20%, between the third quarter periods. This increase 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.

Supply and logistics Segment Margin decreased by $6.3 million, or 46%, between the third quarter periods, 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.

Interest costs for the 2015 Quarter increased by $9.2 million from the 2014 Quarter primarily due to an increase in our average outstanding indebtedness from recently acquired and constructed assets (principally from additional debt outstanding as a result of financing the Enterprise acquisition). Interest costs, on an ongoing basis, are net of capitalized interest costs attributable to our growth capital expenditures.



	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 gain (loss) on derivative transactions excluding fair value hedges, net of changes in inventory value	(192		)	(3,460		)
Maintenance capital utilized ⁽¹⁾	(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

In addition to the factors impacting Available Cash before Reserves, we recorded a $335.3 million non-cash gain 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. We also incurred $13 million in acquisition related costs in the 2015 Quarter relating to the Enterprise acquisition. Depreciation and amortization expense increased $16.0 million between the quarterly periods primarily as a result of the effect of placing recently acquired and constructed assets in service during calendar 2014 and the early part of 2015. Our derivative positions (excluding the effects of changes in inventory values) resulted in a $1.2 million non-cash unrealized gain in the 2015 Quarter compared to a $3.5 million non-cash unrealized gain in the 2014 Quarter.

We have increased our quarterly distribution rate for the forty-first consecutive quarter. Thirty-six of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. Over the last four quarters, we have increased the distribution rate on our common units by a total of $0.06 per unit, or 10.3%. Distributions attributable to each quarter of 2015 and 2014, are as follows:



Distribution For	Date Paid	Per Unit Amount
2015
3rd Quarter	November 13, 2015	$	0.6400
2nd Quarter	August 14, 2015	$	0.6250
1st Quarter	May 15, 2015	$	0.6100
2014
4th Quarter	February 13, 2015	$	0.5950
3rd Quarter	November 14, 2014	$	0.5800
2nd Quarter	August 14, 2014	$	0.5650
1st Quarter	May 15, 2014	$	0.5500

We will broadcast our Earnings Conference Call on Tuesday, November 3, 2015, at 9:00 a.m. Central time (10:00 a.m. Eastern time). This call can be accessed at www.genesisenergy.com. Choose the Investor Relations button. For those unable to attend the live broadcast, a replay will be available beginning approximately one hour after the event and remain available on our website for 30 days. There is no charge to access the event.

Genesis Energy, L.P. is a diversified midstream energy master limited partnership headquartered in Houston, Texas. Genesis’ operations include onshore and offshore pipeline transportation, refinery services, marine transportation and supply and logistics. Genesis’ operations are primarily located in Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and the Gulf of Mexico.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES	$	572,334		$	964,114		$	1,755,518		$	2,998,882

COSTS AND EXPENSES:
Costs of sales	459,567			889,933			1,505,169			2,791,565
General and administrative expenses	26,799			13,765			54,852			40,471
Depreciation and amortization	41,170			25,148			96,500			64,919
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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Onshore Pipeline Transportation Segment
Crude oil pipelines (barrels/day):
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 (Mcf/day)
Free State	145,947		144,588		167,805		171,388

Offshore Pipeline Transportation Segment
Crude oil pipelines (barrels/day unless otherwise noted):
CHOPS⁽³⁾	176,479		186,470		171,774		182,371
Poseidon ⁽³⁾	264,862		213,855		256,277		208,696
Odyssey ⁽³⁾	90,419		51,314		63,536		45,626
SEKCO ⁽³⁾	78,008		—		56,962		—
GOPL	17,049		7,610		14,028		6,419
Offshore crude oil pipelines total	626,817		459,249		562,577		443,112

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

Refinery Services Segment
NaHS (dry short tons sold)	30,721		36,431		95,654		114,940
NaOH (caustic soda dry short tons sold)	23,907		23,368		67,223		71,467

Marine Transportation Segment
Inland Fleet Utilization Percentage ⁽⁴⁾	97.6	%	97.4	%	97.7	%	97.8	%
Offshore Fleet Utilization Percentage ⁽⁴⁾	99.9	%	99.6	%	99.8	%	99.8	%

Supply and Logistics Segment
Crude oil and petroleum products sales (barrels/day)	89,516		96,521		94,571		97,626
Rail load/unload volumes (barrels/day) ⁽⁵⁾	37,767		39,555		24,043		31,555



	September 30, 2015			December 31, 2014
ASSETS
Cash and cash equivalents	$	15,568		$	9,462
Accounts receivable - trade, net	243,372			271,529
Inventories	49,069			46,829
Other current assets	37,387			27,546
Total current assets	345,396			355,366
Fixed assets, net	3,826,822			1,631,001
Investment in direct financing leases, net	141,343			145,959
Equity investees	493,190			628,780
Intangible assets, net	229,457			82,931
Goodwill	325,046			325,046
Other assets, net	87,991			61,291
Total assets	$	5,449,245		$	3,230,374
LIABILITIES AND PARTNERS’ CAPITAL
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
Partners' capital:
Common unitholders	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

Units Data:
Total common units outstanding	109,979,218			95,029,218



	Three Months Ended September 30,
	2015			2014
Segment Margin ⁽¹⁾	$	140,710		$	94,790
Corporate general and administrative expenses	(25,940		)	(12,865		)
Non-cash items included in general and administrative costs	(585		)	(701		)
Cash expenditures not included in Adjusted EBITDA	12,766			688
Cash expenditures not included in net income	(50		)	(129		)
Adjusted EBITDA	126,901			81,783
Depreciation and amortization	(41,170		)	(25,148		)
Interest expense, net	(29,617		)	(20,441		)
Cash expenditures not included in Adjusted EBITDA or net income	(12,716		)	(559		)
Adjustment to exclude distributable cash generated by equity investees not included in income and include equity in investees net income	(7,962		)	(6,741		)
Non-cash legacy stock appreciation rights plan expense	553			608
Gain on step up of historical basis in CHOPS and SEKCO	335,260			—
Other non-cash items	(6,743		)	342
Income tax expense	(1,292		)	(731		)
Net income attributable to Genesis Energy, L.P.	$	363,214		$	29,113

(1) Our reconciliation of Segment Margin to net income reflects that Segment Margin (as defined above) excludes corporate general and administrative expenses, 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 generated by equity investees in excess of equity in earnings (or losses) and cash payments from direct financing leases in excess of earnings.



	September 30, 2015
Senior secured credit facility	$	1,014,100
Senior unsecured notes	1,839,933
Less: Outstanding inventory financing sublimit borrowings	(34,500		)
Less: Cash and cash equivalents	(15,568		)
Adjusted Debt ⁽¹⁾	$	2,803,965

	Pro Forma LTM
	September 30, 2015
LTM Adjusted EBITDA (as reported)⁽²⁾	$	379,079
Acquisitions and material projects EBITDA adjustment ⁽³⁾	181,180
Pro Forma EBITDA	$	560,259

Adjusted Debt-to-Pro Forma EBITDA	5.00		x

(2) Last twelve months ("LTM") Adjusted EBITDA. The most comparable GAAP measure to Adjusted EBITDA, net income, was $26.2 million for the fourth quarter of 2014, $20.2 million for the first quarter of 2015, $11.7 million for the second quarter of 2015 and $363.4 million for the third quarter of 2015. Reconciliations of Adjusted EBITDA to net income for all periods presented are available on our website at www.genesisenergy.com.

(3) This amount reflects the adjustment we are permitted to make under our credit agreement for purposes of calculating compliance with our leverage ratio. It includes a pro rata portion of projected future annual EBITDA from material projects (i.e. organic growth) and includes Adjusted EBITDA (using historical amounts and other permitted amounts) since the beginning of the calculation period attributable to each acquisition completed during such calculation period, regardless of the date on which such acquisition was actually completed. This adjustment may not be indicative of future results.

This press release includes forward-looking statements as defined under federal law. Although we believe that our expectations are based upon reasonable assumptions, we can give no assurance that our goals will be achieved. Actual results may vary materially. All statements, other than statements of historical facts, included in this release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements, and historical performance is not necessarily indicative of future performance. Those forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside our control, that could cause results to differ materially from those expected by management. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for products, the timing and success of business development efforts and other uncertainties. Those and other applicable uncertainties, factors and risks that may affect those forward-looking statements are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2014 filed with the Securities and Exchange Commission and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q. We undertake no obligation to publicly update or revise any forward-looking statement.

This press release and the accompanying schedules include non-generally accepted accounting principle (non-GAAP) financial measures of available cash and Adjusted EBITDA. 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 schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States of America (GAAP). Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and Adjusted EBITDA measures are just two of the relevant data points considered from time to time.

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team has access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow; and expectations for us, and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user.

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:

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.

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 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. An example of a non-discretionary (or mandatory) maintenance capital expenditure would

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.

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.

We define Adjusted EBITDA (“Adjusted EBITDA”) as net income or loss plus net interest expense, income taxes, non-cash gains and charges, depreciation and amortization plus other specific items, the most significant of which are the addition of cash received from direct financing leases not included in income, non-cash equity-based compensation expense, expenses


•	On November 13, 2015, we will pay a total quarterly distribution of $70.4 million based on our quarterly declared distribution of $0.64 per unit attributable to our financial and operational results for the third quarter of 2015. Our Available Cash before Reserves provided 1.37 times coverage for this quarterly distribution.


•	We increased our distribution to all unitholders for the forty-first consecutive quarter, thirty-six of which have been 10% or greater over the prior year’s quarter and none less than 8.7%.


(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.


(1)	the financial performance of our assets without regard to financing methods, capital structures or historical cost basis;


(2)	our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure;