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GEL > SEC Filings for GEL > Form 10-Q on 6-Aug-2014All Recent SEC Filings

Show all filings for GENESIS ENERGY LP

Form 10-Q for GENESIS ENERGY LP


6-Aug-2014

Quarterly Report


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, 2013. Included in Management's Discussion and Analysis are the following sections:
Overview

Financial Measures

Results of Operations

Liquidity and Capital Resources

Commitments and Off-Balance Sheet Arrangements

Forward Looking Statements

Overview
We reported net income of $21.1 million, or $0.24 per common unit during the three months ended June 30, 2014 ("2014 Quarter") compared to net income of $26.9 million or $0.33 per common unit during the three months ended June 30, 2013 ("2013 Quarter").
Available Cash before Reserves increased $9.8 million, or 21%, in the 2014 Quarter (as compared to the 2013 Quarter) to $55.5 million. See "Financial Measures" below for additional information on Available Cash before Reserves. Segment Margin (as described below in "Financial Measures") increased by $12.2 million, or 17%, in the 2014 Quarter, as compared to the 2013 Quarter. The significant factor benefiting net income, Available Cash before Reserves and Segment Margin was improved operating results from each of our segments. The increase in our Segment Margin resulted primarily from increases attributable to our pipeline transportation, refinery services and supply and logistics segments of 6%, 16% and 31%, respectively.
More than offsetting the above factors benefiting net income were increases in depreciation and amortization expenses as a result of the effect of newly acquired and constructed assets in the 2014 Quarter as compared to the 2013 Quarter as well as the change in unrealized losses on derivative transactions in the 2014 Quarter as compared to unrealized gains on derivative transactions during the 2013 Quarter.
A more detailed discussion of our segment results and other costs is included below in "Results of Operations".

Distribution Increase
In July 2014, we declared our thirty-sixth consecutive increase in our quarterly distribution to our common unitholders. Thirty-one of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In August 2014, we will pay a distribution of $0.565 per unit representing a 10.8% increase from our distribution of $0.51 per unit related to the second quarter of 2013.
Financial Measures
Segment Margin
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., also referred to as GAAP, as revenues less product costs, operating expenses (excluding non-cash 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. A reconciliation of Segment Margin to income from continuing operations is included in our segment disclosures in Note 10 to our Unaudited Condensed Consolidated Financial Statements. Our non-GAAP financial measure 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.


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Available Cash before Reserves
This Quarterly Report on Form 10-Q includes the financial measure of Available Cash before Reserves, which is a "non-GAAP" measure because it is not contemplated by or referenced in GAAP. 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 measure 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. Available Cash before Reserves, also referred to as distributable cash flow, 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 assess: (1) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure and (4) the viability of projects and the overall rates of return on alternative investment opportunities.
Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies. Available Cash before Reserves, including applicable pro forma presentations, is a performance measure used by our management to compare cash flows generated by us to the cash distribution paid to our common unitholders. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investments. Among other things, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
Available Cash before Reserves is income from continuing operations as adjusted for specific items, the most significant of which are the addition of certain non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, 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. Maintenance capital is 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. Our quarterly maintenance capital utilized is intended to represent the amount of cash reserves we believe is prudent to establish each quarter attributable to maintenance capital requirements in connection with determining the amount of distributable or discretionary cash flow attributable to that quarter, which cash flow we refer to as Available Cash before Reserves. We believe the most useful quarterly maintenance capital utilized amount is that portion of the amount of previously incurred maintenance capital expenditures that we realize and/or 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 maintenance capital utilized, our future maintenance capital utilized calculations will reflect the realization and/or utilization of solely those maintenance capital expenditures incurred since December 31, 2013.


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

                                                                Three Months Ended
                                                                     June 30,
                                                               2014            2013
                                                                  (in thousands)
Income from continuing operations                          $    21,148     $   26,612
Depreciation and amortization                                   20,491         15,665
Cash received from direct financing leases not included in
income                                                           1,371          1,263
Cash effects of sales of certain assets                             61            294
Effects of distributable cash generated by equity method
investees not included in income                                 7,808          4,891
Cash effects of legacy stock appreciation rights plan             (127 )       (1,896 )
Non-cash legacy stock appreciation rights plan expense             322            705
Expenses related to acquiring or constructing growth
capital assets                                                     418            667
Unrealized loss (gain) on derivative transactions
excluding fair value hedges                                      2,724         (1,971 )
Maintenance capital utilized                                      (178 )       (1,015 )
Non-cash tax expense (benefit)                                     512           (213 )
Other items, net                                                   942            707
Available Cash before Reserves                             $    55,492     $   45,709


Results of Operations
Revenues and Costs and Expenses

Our revenues for the 2014 Quarter decreased $53.6 million, or 5% from the 2013 Quarter. Additionally, our costs and expenses decreased $51.5 million, or 5% 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 second quarter periods is primarily attributable to decreased volumes from our continuing operations relating to our supply and logistics segment, partially offset by an increase in market prices for crude oil and petroleum products as described below.
Volumes from continuing operations decreased in our supply and logistics segment by 9% quarter to quarter and 3% between the six month periods principally related to the transitioning of the operations of our refined products business in order to operate within current market conditions. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 9% to $103.00 per barrel in the second quarter of 2014, as compared to $94.22 per barrel in the second quarter of 2013. Segment Margin
The contribution of each of our segments to total Segment Margin in the three and six months ended June 30, 2014 and June 30, 2013 was as follows:
                           Three Months Ended         Six Months Ended
                                June 30,                  June 30,
                            2014         2013         2014         2013
                             (in thousands)            (in thousands)
Pipeline transportation $    27,966    $ 26,456    $  56,058    $  51,652
Refinery services            21,627      18,696       42,499       36,661
Supply and logistics         33,088      25,290       61,475       54,194
Total Segment Margin    $    82,681    $ 70,442    $ 160,032    $ 142,507

We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash 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.


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A reconciliation of Segment Margin to income from continuing operations for the periods presented is as follows:

                                            Three Months Ended             Six Months Ended
                                                 June 30,                      June 30,
                                           2014            2013           2014           2013
Segment Margin                         $    82,681     $   70,442     $  160,032     $  142,507
Corporate general and administrative
expenses                                   (13,789 )      (10,305 )      (24,850 )      (21,142 )
Depreciation and amortization              (20,491 )      (15,665 )      (39,771 )      (30,714 )
Interest expense                           (14,069 )      (12,255 )      (26,873 )      (23,696 )
Distributable cash from equity
investees in excess of equity in
earnings                                    (7,808 )       (4,891 )      (13,585 )      (11,455 )
Non-cash items not included in Segment
Margin                                      (3,043 )          960            282         (3,335 )
Cash payments from direct financing
leases in excess of earnings                (1,371 )       (1,263 )       (2,709 )       (2,495 )
Income tax (expense) benefit                  (962 )         (117 )       (1,603 )           86
Discontinued operations                          -           (294 )            -           (441 )
Income from continuing operations      $    21,148     $   26,612     $   50,923     $   49,315

Our reconciliation of Segment Margin to income from continuing operations 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 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 income from continuing operations 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.


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Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment
are presented below:

                                                    Three Months Ended         Six Months Ended
                                                         June 30,                  June 30,
                                                    2014          2013         2014         2013
                                                      (in thousands)            (in thousands)
Crude oil tariffs and revenues - onshore crude
oil pipelines                                    $  10,643     $  9,923     $ 20,888     $ 19,404
Segment Margin from offshore crude oil
pipelines, including pro-rata share of
distributable cash from equity investees            11,435        9,688       24,838       19,713
CO2 tariffs and revenues from direct financing
leases of CO2 pipelines                              6,367        6,930       12,874       13,754
Sales of onshore crude oil pipeline loss
allowance volumes                                    3,645        3,419        4,855        5,642
Onshore pipeline operating costs, excluding
non-cash charges for equity-based compensation
and other non-cash expenses                         (5,777 )     (4,997 )    (10,647 )     (9,865 )
Payments received under direct financing leases
not included in income                               1,371        1,263        2,709        2,495
Other                                                  282          230          541          509
Segment Margin                                   $  27,966     $ 26,456     $ 56,058     $ 51,652

Volumetric Data (barrels/day unless otherwise
noted):
Onshore crude oil pipelines:
Texas                                               60,662       54,929       54,769       54,175
Jay                                                 24,337       38,062       26,085       33,107
Mississippi                                         15,121       18,946       15,150       18,965
Louisiana (1)                                       22,435            -       13,574            -
Onshore crude oil pipelines total                  122,555      111,937      109,578      106,247

Offshore crude oil pipelines:
CHOPS (2)                                          169,371      126,819      180,288      120,531
Poseidon (2)                                       201,190      220,687      206,074      212,663
Odyssey (2)                                         40,492       44,493       42,735       43,837
GOPL                                                 4,197        9,335        5,814        9,132
Offshore crude oil pipelines total                 415,250      401,334      434,911      386,163

CO2 pipeline (Mcf/day):
Free State                                         178,500      227,168      185,010      217,844

(1) Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.
(2) Volumes for our equity method investees are presented on a 100% basis. Three Months Ended June 30, 2014 Compared with Three Months Ended June 30, 2013 Pipeline transportation Segment Margin for the 2014 Quarter increased $1.5 million, or 6%. The significant components and details of this change were as follows:

            Segment Margin from our offshore crude oil pipelines increased $1.7
             million, primarily as a result of higher volumes transported in our
             offshore pipelines as a result of additional wells being connected
             to the pipeline in the existing fields that they service.


            Crude oil tariff revenues of onshore crude oil pipelines increased
             primarily due to upward tariff indexing of approximately 4.6% for
             our FERC-regulated pipelines effective in July 2013. In addition,
             increases in crude oil tariff revenues were also a result of higher
             throughput volumes, including those from our Louisiana pipeline
             system, a new 18-mile 24-inch diameter crude oil pipeline connecting
             Port Hudson to the Baton


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Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm which was operational for the entirety of the 2014 Quarter. The increased crude oil tariff revenues were substantially offset by the increase in onshore crude oil pipeline operating costs also associated with the higher throughput volumes and related activity on our new Louisiana pipeline system.

            Although volumes on our Free State CO2 pipeline system decreased
             48,668 Mcf per day, or 21%, in the 2014 Quarter as compared to the
             2013 Quarter, that decrease did not materially affect contributions
             to Segment Margin by that pipeline. We provide transportation
             services on our Free State CO2 pipeline 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 on our Free State CO2
             pipeline system have a limited impact on Segment Margin.

Six Months Ended June 30, 2014 Compared with Six Months Ended June 30, 2013 Pipeline transportation Segment Margin for the six month periods increased $4.4 million, or 9%. The significant components and details of this change were as follows:

            Segment Margin from our offshore crude oil pipelines increased $5.1
             million, primarily as a result of higher volumes transported in our
             offshore pipelines as a result of additional wells being connected
             to the pipeline in the existing fields that they service.


            Crude oil tariff revenues of onshore crude oil pipelines increased
             primarily due to upward tariff indexing of approximately 4.6% for
             our FERC-regulated pipelines effective in July 2013. In addition,
             increases in crude oil tariff revenues were also a result of higher
             throughput volumes, including those from our Louisiana pipeline
             system, a new 18-mile 24-inch diameter crude oil pipeline connecting
             Port Hudson to the Baton Rouge Scenic Station and continuing
             downstream to the Anchorage Tank Farm which became operational
             during the latter part of the first quarter of 2014. The increased
             crude oil tariff revenues were substantially offset by the increase
             in onshore crude oil pipeline operating costs also associated with
             the higher throughput volumes and related activity on our new
             Louisiana pipeline system.


            Although volumes on our Free State CO2 pipeline system decreased
             32,834 Mcf per day, or 15%, in the first six months of 2014 as
             compared to the first six months of 2013, that decrease did not
             materially affect contributions to Segment Margin by that pipeline.
             We provide transportation services on our Free State CO2 pipeline
             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 on our Free State CO2 pipeline system have a limited impact
             on Segment Margin.


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Refinery Services Segment
Operating results for our refinery services segment were as follows:

                                           Three Months Ended             Six Months Ended
                                                June 30,                      June 30,
                                          2014            2013           2014           2013
Volumes sold (in Dry short tons
"DST"):
NaHS volumes                               37,607         36,665         78,509         73,287
NaOH (caustic soda) volumes                24,066         21,720         48,099         40,950
Total                                      61,673         58,385        126,608        114,237

Revenues (in thousands):
NaHS revenues                         $    41,162     $   40,462     $   84,270     $   79,297
NaOH (caustic soda) revenues               12,642         12,695         24,787         24,097
Other revenues                              1,748          1,131          3,602          3,073
Total external segment revenues       $    55,552     $   54,288     $  112,659     $  106,467

Segment Margin (in thousands)         $    21,627     $   18,696     $   42,499     $   36,661

Average index price for NaOH per DST
(1)                                   $       595     $      626     $      587     $      614
Raw material and processing costs as
% of segment revenues                          42 %           49 %           43 %           49 %

(1) Source: IHS Chemical Three Months Ended June 30, 2014 Compared with Three Months Ended June 30, 2013 Refinery services Segment Margin for the 2014 Quarter increased $2.9 million, or 16%. The significant components of this fluctuation were as follows:
NaHS revenues increased primarily as a function of increased sales volumes, which increase was partially offset by a decrease in the average index price for caustic soda (which is a component of our sales prices). The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks (primarily caustic soda), freight, labor, energy costs and government indexes. The frequency at which those adjustments are applied varies by contract, geographic region and supply point. The mix of NaHS sales volumes to which these adjustments apply varies between periods.

            Our raw material costs related to NaHS decreased correspondingly to
             the decrease in the average index price for caustic soda. We were
             able to realize benefits from operating efficiencies at several of
             our sour gas processing facilities, our favorable management of the
             acquisition (including economies of scale) and utilization of
             caustic soda in our (and our customers') operations, and our
             logistics management capabilities.


            Caustic soda revenues decreased slightly, while caustic soda sales
             volumes increased 11%. Although caustic sales volumes may fluctuate,
             the contribution to Segment Margin from these sales is not a
             significant portion of our refinery services activities. Caustic
             soda is a key component in the provision of our sulfur-removal
             service, from which we receive the by-product NaHS. Consequently, we
             are a very large consumer of caustic soda. In addition, our
             economies of scale and logistics capabilities allow us to
             effectively purchase additional caustic soda for re-sale to third
             parties. Our ability to purchase caustic soda volumes is currently
             sufficient to meet the demands of our refinery services operations
             and third-party sales.


            Average index prices for caustic soda decreased to $595 per DST in
             the second quarter of 2014 compared to $626 per DST during the
             second quarter of 2013. 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
. . .
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