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Genesis Energy, L.P. Reports Fourth Quarter 2018 Results

HOUSTON--(BUSINESS WIRE)--

Genesis Energy, L.P. (GEL) today announced its fourth quarter results.

We generated the following financial results for the fourth quarter of 2018:

  • Net Loss Attributable to Genesis Energy, L.P. of $24.8 million for the fourth quarter of 2018 compared to Net Income Attributable to Genesis Energy, L.P. of $15.5 million for the same period in 2017.
  • Cash Flows from Operating Activities of $82.5 million for the fourth quarter of 2018 compared to $117.2 million for the same period in 2017, a decrease of $34.8 million, principally due to an increase in working capital.
  • Total Segment Margin in the fourth quarter of 2018 of $185.5 million.
  • Available Cash before Reserves of $150.8 million for the fourth quarter of 2018, inclusive of a one-time gain on sale of assets of $38.9 million. Excluding the gain on sale of assets, Available Cash before Reserves provided 1.66X coverage for the quarterly distribution of $0.55 per common unit attributable to the fourth quarter. We paid distributions on our preferred units in the form of 534,576 additional convertible preferred units.
  • Adjusted EBITDA of $213.2 million for the fourth quarter of 2018, inclusive of a one-time gain on sale of assets of $38.9 million. Excluding the gain on sale of assets, Adjusted EBITDA would have been $174.3 million.

Grant Sims, CEO of Genesis Energy, said, “We are pleased to announce Total Segment Margin of $185.5 million in the quarter which is a testament to the strength of our underlying diverse business segments. This was primarily driven by continued over performance in our soda ash business and continued ramping up of volumes on our Louisiana infrastructure.

As we have previously alluded, we have identified and are currently evaluating several organic growth opportunities that are complementary to our existing core businesses with apparent multiples to Adjusted EBITDA of plus or minus 5 times. In conjunction with our desire to internally fund these potential investments and possibly other future opportunities and to further strengthen our balance sheet and maintain our financial flexibility, our Board of Directors has made the decision to hold our quarterly distribution rate flat at $0.55 per common unit beginning with the distribution attributable to the quarter ending March 31, 2019. We intend to use our capital for the highest and best use for all of our stakeholders. We will revisit our distribution policy quarterly, but we currently expect for our quarterly distribution rate to remain at $0.55 per common unit for the foreseeable future.

Turning to our quarterly financial results, our business continued to perform well, generating consistent financial results that provided 1.66X coverage for our increased quarterly distribution. Our distribution coverage ratio should be slightly lower in future periods, everything else the same, as we move out of the paid-in-kind period on our preferred equity units beginning on March 1, 2019 and start paying the 8.75% preferred payment in cash on a go forward basis.

In our offshore business, we continue to be encouraged by the current activity in and around our substantial footprint in the Gulf of Mexico. We are currently seeing increasing demand for our assets from production that is currently dedicated to pipelines of our competitors that, in our estimation, appear to be oversubscribed. Given our excess capacity and connectivity on certain of our systems, we expect to benefit from this takeaway capacity constraint for the next twelve to twenty-four months.

In addition, we have several new dedicated tie-backs scheduled to come on-line in the second half of 2019 representing up to an additional 40-50 thousand barrels per day, or kbd, of throughput exiting 2019. In fact, we have either executed or are in the process of finalizing agreements adding incremental, dedicated volumes approaching 80 kbd in 2020 (including Atlantis Phase 3), 70 kbd in 2021 and 150 kbd in 2022 (including Mad Dog 2) none of which requires any capital expenditures by us. We are in early but active discussions regarding an incremental 300 kbd that could quite possibly come on in the 2022-2025 time-frame, a portion of which represents one of the strategic capital opportunities mentioned earlier. However, unless and until the parties enter into definitive agreements, there is no guarantee that we will be successful in capturing some or any of these volumes.

Our soda ash operations continue to exceed our original acquisition date expectations. In 2018, we beat our previously raised target range of $165-$175 million in segment margin contribution driven by strong export pricing supported by higher than expected international demand growth and lower than expected international supply growth. We currently expect this tight international supply/demand balance to stay in place in 2019 and, in all likelihood, to strengthen into 2020 and 2021. During the 2019 domestic contract season, we gained some domestic market share to bring our portfolio back in line with the domestic-international mix of the average U.S. producer, after incurring some domestic losses over the last couple years. Our intent is to maintain this balanced portfolio moving forward.

Our refinery services business continues to perform at or above our expectations and to be a remarkably steady contributor.

Margin in our marine segment actually increased slightly for the fourth quarter in a row. We are reasonably hopeful we’ve put in a bottom for the quarterly segment margin from our entire fleet of assets and have seen some strength in near term day rates and utilization rates. It will be interesting to see how IMO 2020 plays out, as we would otherwise expect an increased demand for our type of inland barge that can get the right intermediate refined barrel to the right refinery location under the more stringent requirements for finished products. Also, there has been a recent firming in Jones Act tanker rates, possibly indicating that more and more shale crude oil volumes delivered to the Gulf Coast are further transported to the East and West coasts of the US on Jones Act vessels, in addition to international exports.

In the quarter, even after reflecting the sale of our Powder River Basin midstream assets at the beginning of the fourth quarter, our segment margin contribution from our onshore facilities and transportation segment increased from the third quarter. That increase was primarily driven by increasing crude by rail volumes flowing through our infrastructure in the Baton Rouge corridor in Louisiana. Those increased volumes were primarily attributable to Imperial Oil shipping a portion of its equity Canadian production via rail to ExxonMobil’s Baton Rouge refinery for consumption and export through our capital Aframax capable facilities at the Port of Baton Rouge.

As many have read, on December 2, 2018 the government of Alberta took an unprecedented action of intervention in a free market by imposing mandatory upstream production curtailments on Canadian producers. We believe that artificially impacted the short to near term spread between WCS and WTI and resulted in making rail movements out of Canada uneconomical. We believe that, over the long term, the market takeaway capacity supply and demand dynamics are in place to ultimately return to fourth quarter volumes, but we expect to see a reduction in volume in the first half of 2019. The government of Alberta has already eased its curtailment and will continue to revisit its policy from time to time.

Touching on the outlook for 2019, we are excited about the overall current operating environment for our business segments, notwithstanding the loss of segment margin expected in onshore facilities and transportation in the first half of 2019 relating to the Alberta production curtailment, as mentioned above. We expect 2019 Adjusted EBITDA to be in a range of $685 to $715 million, which assumes an Adjusted EBITDA reduction of approximately $15 million due to the Alberta situation described above. We expect our fourth quarter Adjusted EBITDA to be in a range of $180 to $190 million, driven by a reasonable recovery of crude by rail volumes and expected growth from our offshore segment attributable to the startup of several new dedicated tie-backs in the second half of the year, discussed in more detail above. 1

We continue to enjoy a strong distribution coverage ratio and remain on our path to naturally de-lever our balance sheet. We are encouraged by our view of the operating environment for 2019 for our businesses, especially after the Alberta oil production curtailment ends. As always, we intend to be prudent and diligent in maintaining our financial flexibility to allow the partnership to opportunistically build long term value for all stakeholders without ever losing our commitment to safe, reliable and responsible operations.”

1 We are unable to provide a reconciliation of the forward-looking Adjusted EBITDA, a non-GAAP financial measure, to the most directly comparable GAAP financial measure without unreasonable efforts. The probable significance is that such comparable GAAP financial measure may be materially different.

Financial Results

Segment Margin

Variances between the fourth quarter of 2018 (the “2018 Quarter”) and the fourth quarter of 2017 (the “2017 Quarter”) in these components are explained below.

Segment margin results for the 2018 Quarter and 2017 Quarter were as follows:

   
Three Months Ended
December 31,
2018   2017
(in thousands)
Offshore pipeline transportation $ 69,276 $ 74,012
Sodium minerals and sulfur services 67,613 66,469
Onshore facilities and transportation 36,296 24,377
Marine transportation 12,272   10,526
Total Segment Margin $ 185,457   $ 175,384
 

Offshore pipeline transportation Segment Margin for the 2018 Quarter decreased $4.7 million, or 6%, from the 2017 Quarter. The decrease is primarily attributable to lower cash distributions received from our equity investees, specifically Poseidon, during the 2018 Quarter. Poseidon has pipeline capacity reservation agreements with certain producers in the Gulf of Mexico that require them to make minimum bill payments to us in excess of the standard throughput fee charged per barrel. These minimum bill payments ended prior to the 2018 Quarter. This decrease was partially offset by higher overall volumes and throughput fees on the Poseidon system, and higher volumes on our CHOPS pipeline system and its associated laterals.

Sodium minerals and sulfur services Segment Margin for the 2018 Quarter increased $1.1 million, or 2%. The contributions thus far from our Alkali Business have exceeded our expectations, and we expect continued strong performance into 2019. Although soda ash volumes were slightly down during the 2018 Quarter, we were able to take advantage of favorable export pricing supported by higher than expected international demand growth and lower than expected international supply growth. Additionally, our refinery services business continues to perform as expected. NaHS volumes were slightly lower during the 2018 Quarter due to the timing of certain of our sales to our international customers.

Onshore facilities and transportation Segment Margin for the 2018 Quarter increased $11.9 million, or 49%. Even after reflecting the sale of our Powder River Basin midstream assets and realizing no margin from the associated assets during the 2018 Quarter, our margin contribution from the segment increased sequentially from the third quarter and from the 2017 Quarter. This increase in the 2018 Quarter is primarily attributable to increased volumes flowing through our infrastructure in the Baton Rouge corridor in Louisiana. These increased volumes are the realization of the expected growth in this business that we have discussed over the last few quarters. This comes from actually moving increased volumes of crude oil rather than marketing or merchant fees which, for context, contributed less than $1 million for the fourth quarter.

Marine transportation Segment Margin for the 2018 Quarter increased $1.7 million, or 17%, from the 2017 Quarter. This increase in Segment Margin is primarily attributable to an increase in utilization during the 2018 Quarter on our inland barge operation. This was partially offset by our offshore barge fleet entering into more short-term spot price contracts, which can lead to a less favorable rebill structure and higher operating costs, as our last legacy long term contract rolled off during the first quarter of 2018. Additionally, we had an increase in operating costs during the 2018 Quarter relative to the 2017 Quarter due to an increase in dry-docking costs. We have continued to enter into short term contracts (less than a year) in both the inland and offshore markets because we believe the day rates currently being offered by the market are at, or approaching, cyclical lows. We are reasonably hopeful that we've put in a bottom for the quarterly segment margin from our entire fleet of assets and have seen some strength in near term day rates and utilization, but we have no expectation of the fundamentals for marine transportation showing significant improvement through at least the next several years.

Other Components of Net Income

In the 2018 Quarter, we recorded Net Loss Attributable to Genesis Energy, L.P. of $24.8 million compared to Net Income Attributable to Genesis Energy, L.P. of $15.5 million in the 2017 Quarter. The 2018 Quarter was negatively impacted by impairment expense of $120.2 million associated with: (i) an impairment of $23.1 million on the goodwill associated with our supply and logistics reporting unit, which primarily consists of our legacy crude oil and refined products marketing and trucking businesses; (ii) an impairment of certain of our non-core offshore gas pipeline and platform assets of approximately $75.9 million for which the abandonment timing has accelerated; and (iii) an impairment of approximately $21.2 million related to our remaining non-core assets in the Powder River Basin.

This decrease was offset by an increase in the 2018 Quarter on gains on asset sales, primarily due to the closing of our Powder River Basin asset sale. Additionally, we reported an increase in segment margin during the 2018 Quarter of $10.1 million, a decrease in general and administrative expenses of $10.2 million principally due lower corporate and transaction costs, and other income (expense) effects of approximately $23.0 million primarily driven by the valuation of the embedded derivative associated with our Class A Convertible Preferred Units and a loss on debt extinguishment, which was recognized during the 2017 Quarter.

Earnings Conference Call

We will broadcast our Earnings Conference Call on Wednesday, February 20, 2019, at 8:30 a.m. Central time (9:30 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 offshore pipeline transportation, sodium minerals and sulfur services, marine transportation and onshore facilities and transportation. Genesis’ operations are primarily located in Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and the Gulf of Mexico.

 

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - UNAUDITED

(in thousands, except per unit amounts)

 
  Three Months Ended
December 31,
  Year Ended
December 31,
2018   2017 2018   2017
REVENUES $ 689,296 $ 720,049 $ 2,912,770 $ 2,028,377
 
COSTS AND EXPENSES:
Costs of sales and operating expenses 511,931 566,544 2,278,416 1,529,236
General and administrative expenses 17,486 27,698 66,898 66,421
Depreciation, depletion and amortization 74,401 76,027 313,190 252,480
Impairment expense 120,260 126,282
Gain on sale of assets (38,901 ) (13,627 ) (42,264 ) (40,311 )
OPERATING INCOME 4,119 63,407 170,248 220,551
Equity in earnings of equity investees 15,238 16,241 43,626 51,046
Interest expense (56,327 ) (54,645 ) (229,191 ) (176,762 )
Other income (expense) 8,627   (14,439 ) 5,023   (16,715 )
INCOME BEFORE INCOME TAXES (28,343 ) 10,564 (10,294 ) 78,120
Income tax benefit (expense) (584 ) 4,837   (1,498 ) 3,959  
NET INCOME (LOSS) (28,927 ) 15,401 (11,792 ) 82,079
Net loss attributable to noncontrolling interests 4,144   111   5,717   568  
NET INCOME (LOSS) ATTRIBUTABLE TO GENESIS ENERGY, L.P. $ (24,783 ) $ 15,512   $ (6,075 ) $ 82,647  
Less: Accumulated distributions attributable to Class A Convertible Preferred Units (18,021 ) (16,526 ) (69,801 ) (21,995 )
NET INCOME(LOSS) AVAILABLE TO COMMON UNITHOLDERS $ (42,804 ) $ (1,014 ) $ (75,876 ) $ 60,652  
NET INCOME(LOSS) PER COMMON UNIT:        
Basic and Diluted $ (0.35 ) $ (0.01 ) $ (0.62 ) $ 0.50  
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
Basic and Diluted 122,579 122,579 122,579 121,546
 
 

GENESIS ENERGY, L.P.

OPERATING DATA - UNAUDITED

 
  Three Months Ended
December 31,
  Year Ended
December 31,
2018   2017 2018   2017
Offshore Pipeline Transportation Segment
Crude oil pipelines (barrels/day unless otherwise noted):
CHOPS 202,008 193,210 202,121 213,527
Poseidon (1) 251,512 240,241 234,960 253,547
Odyssey (1) 131,088 98,529 115,239 116,408
GOPL 8,485   8,243   10,147   8,185  
Offshore crude oil pipelines total 593,093   540,223   562,467   591,667  
 
Natural gas transportation volumes (MMbtus/d) (1) 421,104 434,591 432,261 496,302
 
Sodium Minerals and Sulfur Services Segment
NaHS (dry short tons sold) 36,125 37,829 150,671 133,404
Soda Ash volumes (short tons sold) 929,953 965,031 3,669,206 1,274,421
NaOH (caustic soda) volumes (dry short tons sold) (2) 22,917 28,854 110,107 84,816
 
Onshore Facilities and Transportation Segment
Crude oil pipelines (barrels/day):
Texas 48,877 45,343 33,303 32,684
Jay 12,733 13,189 14,036 14,155
Mississippi 5,879 7,732 6,359 8,290
Louisiana (3) 165,426 152,954 159,754 135,310
Wyoming (4)   29,789   33,957   22,329  
Onshore crude oil pipelines total 232,915   249,007   247,409   212,768  
 
Free State- CO2 Pipeline (Mcf/day) 125,213 92,397 107,674 77,921
 
Crude oil and petroleum products sales (barrels/day) 37,617 59,237 45,845 51,771
 
Rail load/unload volumes (barrels/day) (5) 165,902 46,544 89,082 52,877
 
Marine Transportation Segment
Inland Fleet Utilization Percentage (6) 97.0 % 90.0 % 95.2 % 90.4 %
Offshore Fleet Utilization Percentage (6) 96.5 % 97.5 % 93.5 % 98.2 %
 
(1)   Volumes for our equity method investees are presented on a 100% basis. We own 64% of Poseidon and 29% of Odyssey, as well as equity interests in various other entities.
(2) Caustic soda sales volumes also include volumes sold from our Alkali business.
(3) Total daily volume for the three and twelve months ended December 31, 2018 includes 49,802 and 55,202 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines. Total daily volume for the three and twelve months ended December 31, 2017 includes 62,012 and 56,748 barrels per day, respectively, of intermediate refined products associated with our Port of Baton Rouge Terminal pipelines.
(4) Volumes on our Wyoming system during 2018 represent actual throughput as of September 30, 2018 as the relevant assets were divested at the beginning of the 2018 Quarter.
(5) Indicates total barrels for which fees were charged for either loading or unloading at all rail facilities.
(6) Utilization rates are based on a 365 day year, as adjusted for planned downtime and dry-docking.
 
 

GENESIS ENERGY, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS - UNAUDITED

(in thousands, except number of units)

 
  December 31,
2018
  December 31,
2017
ASSETS
Cash and cash equivalents $ 10,300 $ 9,041
Accounts receivable - trade, net 323,462 495,449
Inventories 73,531 88,653
Other current assets 35,986   42,890  
Total current assets 443,279 636,033
Fixed assets and mineral leaseholds, net 4,977,514 5,430,535
Investment in direct financing leases, net 116,925 125,283
Equity investees 355,085 381,550
Intangible assets, net 162,602 182,406
Goodwill 301,959 325,046
Other assets, net 121,707   56,628  
Total assets $ 6,479,071   $ 7,137,481  
LIABILITIES AND CAPITAL
Accounts payable - trade $ 127,327 $ 270,855
Accrued liabilities 205,507   185,409  
Total current liabilities 332,834 456,264
Senior secured credit facility 970,100 1,099,200
Senior unsecured notes, net of debt issuance costs 2,462,363 2,598,918
Deferred tax liabilities 12,576 11,913
Other long-term liabilities 259,198   256,571  
Total liabilities 4,037,071   4,422,866  
Mezzanine capital:
Class A convertible preferred units 761,466 697,151
Partners' capital:
Common unitholders 1,690,799 2,026,147
Accumulated other comprehensive income (loss) 939 (604 )
Noncontrolling interests (11,204 ) (8,079 )
Total partners' capital 1,680,534   2,017,464  
Total liabilities, mezzanine capital and partners' capital $ 6,479,071   $ 7,137,481  
 
Common Units Data:
Total common units outstanding 122,579,218   122,579,218  
 
 

GENESIS ENERGY, L.P.

RECONCILIATION OF NET INCOME TO SEGMENT MARGIN - UNAUDITED

(in thousands)

 
  Three Months Ended
December 31,
2018   2017
Net income (loss) attributable to Genesis Energy, L.P. $ (24,783 ) $ 15,512
Corporate general and administrative expenses 16,997 26,335
Depreciation, depletion, amortization and accretion 70,816 77,808
Impairment expense 120,260
Interest expense, net 56,327 54,645
Income tax expense (benefit) 584 (4,837 )
Gain on sale of assets (38,901 ) (13,627 )
Equity compensation adjustments (126 ) (283 )
Provision for leased items no longer in use (434 )
Other 2,987
Plus (minus) Select Items, net (15,283 ) 16,844  
Segment Margin (1) $ 185,457   $ 175,384  
(1)   See definition of Segment Margin later in this press release.
 
 

GENESIS ENERGY, L.P.

RECONCILIATIONS OF NET INCOME TO ADJUSTED EBITDA AND AVAILABLE CASH BEFORE RESERVES- UNAUDITED

(in thousands)

 
  Three Months Ended
December 31,
2018   2017
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P. $ (24,783 ) $ 15,512
Interest expense, net 56,327 54,645
Income tax expense (benefit) 584 (4,837 )
Depreciation, depletion, amortization, and accretion 70,816 77,808
Impairment expense 120,260    
EBITDA 223,204 143,128
Plus (minus) Select Items, net (10,024 ) 21,652  
Adjusted EBITDA, net(1) 213,180 164,780
Maintenance capital utilized(2) (5,755 ) (3,750 )
Interest expense, net (56,327 ) (54,645 )
Cash tax expense (benefit) (301 ) 270
Other   53  
Available Cash before Reserves(1) $ 150,797   $ 106,708  
(1)   Includes a gain on sale of assets of $38.9 million related to the sale of our Powder River Basin midstream assets.
(2) Maintenance capital expenditures in the 2018 Quarter and 2017 Quarter were $27.3 million and $35.7 million, respectively. These expenditures are primarily related to our Alkali business.
 
 

GENESIS ENERGY, L.P.

RECONCILIATION OF NET CASH FLOWS FROM OPERATING ACTIVITIES TO ADJUSTED EBITDA - UNAUDITED

(in thousands)

 
  Three Months Ended
December 31,
2018   2017
Cash Flows from Operating Activities (1) $ 82,475 $ 117,166
Adjustments to reconcile net cash flow provided by operating activities to Adjusted EBITDA:
Interest Expense, net 56,327 54,645
Amortization of debt issuance costs and discount (2,676 ) (4,949 )
Effects of available cash from equity method investees not included in operating cash flows (1) 2,937 9,665
Net effect of changes in components of operating assets and liabilities 29,482 (36,418 )
Non-cash effect of long-term incentive compensation expense (832 ) (121 )
Expenses related to acquiring or constructing growth capital assets 2,970 5,324
Differences in timing of cash receipts for certain contractual arrangements (2) (1,358 ) (5,846 )
Loss on debt extinguishment 6,242
Other items, net 4,954 5,445
Gain on sale of assets 38,901   13,627  
Adjusted EBITDA $ 213,180   $ 164,780  
(1)   Amounts for the 2017 periods have been re-cast in accordance with our retrospective adoption of the FASB's update to ASC 230.
(2) Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.
 
 

GENESIS ENERGY, L.P.

ADJUSTED DEBT-TO-ADJUSTED CONSOLIDATED EBITDA RATIO - UNAUDITED

(in thousands)

 
  December 31, 2018
Senior secured credit facility $ 970,100
Senior unsecured notes 2,462,363
Less: Outstanding inventory financing sublimit borrowings (17,800 )
Less: Cash and cash equivalents (10,300 )
Adjusted Debt (2) $ 3,404,363  
 
Pro Forma LTM
December 31, 2018
Consolidated EBITDA (per our senior secured credit facility)(3) $ 670,957
Acquisitions, material projects and other Consolidated EBITDA adjustments(4) (7,351 )
Adjusted Consolidated EBITDA (per our senior secured credit facility)(5) $ 663,606  
 
Adjusted Debt-to-Adjusted Consolidated EBITDA 5.13X
 
(1)   Our credit facility allows for pro forma credit for asset sales completed subsequent to the reporting period but prior to the date our compliance certificate is due for such period.
 
(2) We define Adjusted Debt as the amounts outstanding under our senior secured credit facility and senior unsecured notes (including any unamortized premiums or discounts) less the amount outstanding under our inventory financing sublimit, less cash and cash equivalents on hand at the end of the period.
 
(3) Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.
 
(4) This amount reflects the adjustment we are permitted to make under our senior secured credit facility 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.
 
(5) Adjusted Consolidated EBITDA for the four-quarter period ending with the most recent quarter, as calculated under our senior secured credit facility.
 

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 press 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, 2017 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.

NON-GAAP MEASURES

This press release and the accompanying schedules include non-generally accepted accounting principle (non-GAAP) financial measures of Adjusted EBITDA and total Available Cash before Reserves. In this press release, we also present total Segment Margin as if it were a non-GAAP measure. Our Non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The 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, Adjusted EBITDA and total Segment Margin measures are just three 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 have 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.

In the fourth quarter of 2017, we revised portions of the format and definitions relating to our presentation of non-GAAP financial measures. Amounts attributable to prior periods have been recast.

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 ("Available Cash before Reserves") as Adjusted EBITDA as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, net cash interest expense and cash tax expense.

Disclosure Format Relating to Maintenance Capital

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

Maintenance Capital Requirements

Maintenance Capital Expenditures

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

Initially, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

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

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

Maintenance Capital Utilized

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

Because we did not initially use our maintenance capital utilized measure, our future maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

ADJUSTED EBITDA

Purposes, Uses and Definition

Adjusted EBITDA 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 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;

(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 Adjusted EBITDA (“Adjusted EBITDA”) as earnings before interest, taxes, depreciation and amortization (including impairment, write-offs, accretion and similar items, often referred to as EBITDA) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, "Select Items"). Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.

The table below includes the Select Items discussed above as applicable to the reconciliation of Adjusted EBITDA and Available Cash before Reserves to net income:

   
Three Months Ended
December 31,
2018   2017
I. Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements(1) $ (1,358 ) $ (5,846 )
Adjustment regarding direct financing leases(2) 1,979 1,794
Certain non-cash items:
Unrealized loss (gain) on derivative transactions excluding fair value hedges, net of changes in inventory value (11,288 ) 8,253
Adjustment regarding equity investees(3) 1,442 6,286
Other (6,058 ) 115  
Sub-total Select Items, net(4) (15,283 ) 16,844
II. Applicable only to Adjusted EBITDA and Available Cash before Reserves
Certain transaction costs(5) 2,970 5,324
Equity compensation adjustments (151 ) (373 )
Other 2,440   (143 )
Total Select Items, net(6) $ (10,024 ) $ 21,652  
(1)   Includes the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our Non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.
(2) Represents the net effect of adding cash receipts from direct financing leases and deducting expenses relating to direct financing leases.
(3) Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(4) Represents all Select Items applicable to Segment Margin, Adjusted EBITDA and Available Cash before Reserves.
(5) Represents transaction costs relating to certain merger, acquisition, transition, and financing transactions incurred in acquisition activities.
(6) Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
 

SEGMENT MARGIN

Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment. We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses, after eliminating gain or loss on sale of assets, plus or minus applicable Select Items. Although, we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results.

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