MAGELLAN MIDSTREAM PARTNERS LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

Edgar Glimpses |

Introduction

We are a publicly traded limited partnership principally engaged in the transportation, storage and distribution of petroleum products. Our three operating segments including the assets of our joint ventures include:

• our refined products segment, comprised of our 9,700-mile refined products

pipeline system with 53 terminals as well as 26 independent terminals not

       connected to our pipeline system and our 1,100-mile ammonia pipeline
       system;


• our crude oil segment, comprised of approximately 2,200 miles of crude oil

       pipelines and storage facilities with an aggregate storage capacity of
       approximately 26 million barrels, of which 16 million are used for
       contract storage; and


• our marine storage segment, consisting of five marine terminals located

       along coastal waterways with an aggregate storage capacity of
       approximately 26 million barrels.


The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this annual report on Form 10-K for the year ended .

See Item 1. Business for a detailed description of our business.

Overview


We are a key component of our nation's energy infrastructure and provide
essential transportation, distribution and storage services for our nation. We
own the longest refined petroleum products pipeline system in the country with
access to nearly 50% of the nation's refinery capacity, allowing us to transport
gasoline and diesel fuel throughout the central region of the United States.
During 2016, we extended the reach of our pipeline system to deliver petroleum
products to Little Rock, Arkansas, providing this market with new access to
Mid-Continent and Gulf Coast refinery production via our extensive pipeline
system. In addition, we are further connecting this system to a third-party
pipeline to add West Memphis as yet another delivery option for our customers
later this year. Industry feedback has been positive for the long-term strategic
value of these new pipeline extensions, and we continue to work with our
customers to further expand our network into new markets.

Our crude oil segment continues to grow and is an important component of the
energy value chain to deliver domestic crude oil production to strategic
locations such as Cushing, Oklahoma and the Houston Gulf Coast region. One of
our largest construction projects, the Saddlehorn pipeline, became operational
during the third quarter of 2016 to deliver crude oil from the DJ Basin in
Colorado to the Cushing storage hub, where we are one of the largest providers
of storage. We are a 40% owner of Saddlehorn, alongside other key industry
players, with commitments from the largest producers in that region.

The Longhorn and BridgeTex pipelines benefit from solid demand and are supported
by take-or-pay agreements to transport crude oil from the Permian Basin in West
Texas to our East Houston terminal. From there, we can further distribute
product via our Houston distribution system, a comprehensive pipeline network
with connectivity to all the refineries in the Houston and Texas City region.

Many in the industry believe that more crude oil pipeline capacity will be needed to meet growing Permian Basin production in the coming years. We are well-situated to accommodate incremental crude oil production volume and recently announced plans to expand the BridgeTex pipeline from 300,000 to 400,000 barrels per day so that we are adequately prepared to meet this opportunity. This expansion is extremely cost effective and will be available in the second quarter of 2017.



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Our marine storage terminals are located along coastal waterways, with our most
prominent presence in the Houston Gulf Coast region. U.S. Gulf Coast refiners
are some of the most competitive refineries in the world and have direct access
to growing U.S. crude oil production. As a result, demand is growing for storage
facilities and dock capacity for refined products exports. This has led to high
utilization of our marine facilities, and increased customer activity has
prompted us to initiate construction of a fifth dock at our largest facility in
Galena Park, Texas, which is located along the Houston Ship Channel.

Growth Projects


We spent a record $736 million on organic growth construction projects during
2016, and we continue to find attractive opportunities to further grow our
business. Based on the projects currently under construction, we expect to spend
an additional $900 million over the next two years to complete the projects now
in progress. This capital spending includes such large projects as our new dock
at Galena Park as well as construction of our new Pasadena refined products
marine terminal.

We announced plans to construct a new marine terminal at Pasadena, Texas to
handle refined products. We are initially building a dock and one million
barrels of storage, backed by a long-term customer commitment. Our new Pasadena
terminal is expected to be operational in early 2019. Based on the size of the
land for this new facility, we have the capability to build an incremental nine
million barrels of storage at this site and are in discussions with other
customers interested in supporting further investment.

We also have announced plans to increase the scale of our Seabrook joint
venture, which represents a key asset for our crude oil marine strategy. The
first phase of this joint venture is scheduled to come online in the second
quarter of 2017 and is backed by a long-term throughput agreement from a Gulf
Coast refiner.

The recently-announced second phase of Seabrook represents construction of 1.7
million barrels of storage and connectivity to our Houston distribution system,
providing attractive optionality for our long-haul crude oil pipeline and other
customers to access this new facility for crude oil exports once operational in
mid-2018. In addition to our further investment in Seabrook, we are separately
investing in a new pipeline within our Houston distribution system to ensure we
are prepared to handle incremental crude oil volume destined for the Houston
Gulf Coast area.

We are continually exploring new opportunities across all of our business segments that are complementary to our existing asset portfolio, primarily focusing on fee-based activities to serve our customers' needs. Our potential project list continues to exceed well over $500 million with a variety of opportunities for each of our operating segments.

We also remain active in evaluating acquisition opportunities. We have specifically communicated our desire to extend our crude oil value chain to include gathering assets and other value-added activities that could help direct barrels to our long-haul crude oil pipelines in the Permian Basin.

Recent Developments


Cash Distribution. In , the board of directors of our general
partner declared a quarterly cash distribution of $0.855 per unit for the period
of  through . This quarterly cash distribution
was paid on  to unitholders of record on . The
total distribution paid on 228.0 million limited partner units outstanding was
$195.0 million.

Corpus Christi Splitter. Our Corpus Christi condensate splitter is mechanically
complete, and the unit has been operating and generating products meeting market
specifications. However, the sole customer, an affiliate of Trafigura, AG, gave
notice to terminate its contract in . We believe this notice was in
breach of our agreement, and we have initiated legal action to seek all
available remedies. We have initiated discussions with multiple potential
customers regarding the future use of the splitter.

Results of Operations


We believe that investors benefit from having access to the same financial
measures utilized by management. Operating margin, which is presented in the
following tables, is an important measure used by management to evaluate the
economic performance of our core operations. Operating margin is not a generally
accepted accounting principles ("GAAP") measure, but the components of operating
margin are computed using amounts that are determined in accordance with GAAP. A
reconciliation of operating margin to operating profit, which is its nearest
comparable GAAP financial measure, is included in the following tables.
Operating profit includes expense items, such as depreciation and amortization
expense and general and administrative ("G&A") expenses, which management does
not focus on when evaluating the core profitability of our separate operating
segments. Additionally, product margin, which management primarily uses to
evaluate the profitability of our commodity-related activities, is provided in
these tables. Product margin is a non-GAAP measure; however, its components of
product sales and cost of product sales are determined in accordance with GAAP.
Our butane blending, fractionation and other commodity-related activities
generate significant revenue. We believe the product margin from these
activities, which takes into account the related cost of product sales, better
represents its importance to our results of operations.


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     Year Ended  Compared to Year Ended 
                                                                                        Variance
                                                 Year Ended December 31,         Favorable (Unfavorable)
                                                  2015             2016          $ Change         % Change
Financial Highlights ($ in millions, except
operating statistics)
Transportation and terminals revenue:
Refined products                              $    974.5       $  1,002.4     $       27.9             3  %
Crude oil                                          394.1            407.8             13.7             3  %
Marine storage                                     176.1            181.7              5.6             3  %
Intersegment eliminations                              -             (0.8 )           (0.8 )         n/a
Total transportation and terminals revenue       1,544.7          1,591.1             46.4             3  %
Affiliate management fee revenue                    13.9             14.7              0.8             6  %
Operating expenses:
Refined products                                   377.8            381.1             (3.3 )          (1 )%
Crude oil                                           89.5             88.8              0.7             1  %
Marine storage                                      62.5             65.7             (3.2 )          (5 )%
Intersegment eliminations                           (3.9 )           (5.8 )            1.9            49  %
Total operating expenses                           525.9            529.8             (3.9 )          (1 )%
Product margin:
Product sales                                      629.8            599.6            (30.2 )          (5 )%
Cost of product sales                              447.3            493.3            (46.0 )         (10 )%
Product margin                                     182.5            106.3            (76.2 )         (42 )%
Earnings of non-controlled entities                 66.5             78.7             12.2            18  %
Operating margin                                 1,281.7          1,261.0            (20.7 )          (2 )%
Depreciation and amortization expense              166.8            178.1            (11.3 )          (7 )%
G&A expense                                        151.3            147.8              3.5             2  %
Operating profit                                   963.6            935.1            (28.5 )          (3 )%
Interest expense (net of interest income
and interest capitalized)                          143.2            165.4            (22.2 )         (16 )%
Gain on exchange of interest in
non-controlled entity                                  -            (28.1 )           28.1           n/a
Other expense (income)                              (1.0 )           (8.2 )            7.2          (720 )%
Income before provision for income taxes           821.4            806.0            (15.4 )          (2 )%
Provision for income taxes                           2.3              3.2             (0.9 )         (39 )%
Net income                                    $    819.1       $    802.8     $      (16.3 )          (2 )%

Operating Statistics
Refined products:
Transportation revenue per barrel shipped     $    1.439       $    1.473
Volume shipped (million barrels):
Gasoline                                           268.1            275.4
Distillates                                        152.5            150.2
Aviation fuel                                       21.2             25.7
Liquefied petroleum gases                            9.7             10.4
Total volume shipped                               451.5            461.7
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel shipped     $    1.118       $    1.321
Volumes shipped (million barrels)                  209.9            187.0
Crude oil terminal average utilization
(million barrels per month)                         13.1             15.0
Select joint venture pipelines:
BridgeTex - volume shipped (million
barrels)(a)                                         75.2             79.0
Saddlehorn - volume shipped (million
barrels)(b)                                            -              5.2
Marine storage:
Marine terminal average utilization
(million barrels per month)                         24.0             23.8



(a) These volumes reflect the total shipments for the BridgeTex pipeline,

which is owned 50% by us.

(b) These volumes reflect the total shipments for the Saddlehorn pipeline,

       which began operations in  and is owned 40% by us.




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Transportation and terminals revenue increased by $46.4 million, resulting from:

• an increase in refined products revenue of $27.9 million. Transportation

revenue was favorably impacted by the mid-year 2015 tariff rate increase

of 4.6% and the mid-year 2016 increase which averaged approximately 2.0%

across all of our markets. Shipments increased 2% in 2016 primarily

associated with additional volumes from recent growth projects, including

our Little Rock pipeline extension which commenced commercial operations

in , and increased demand for gasoline and aviation fuel.

Additionally, revenue from storage services along our pipeline system

       increased due to new customer contracts;


• an increase in crude oil revenue of $13.7 million primarily due to higher

average rates, as well as new storage contracts. Overall crude oil

shipments declined and average rate per barrel increased due to fewer

barrels moving on our lower-priced Houston distribution system tariff

structure to their ultimate destination. Instead, customers utilized space

available on our capacity lease for shipments from the BridgeTex pipeline;

       and


• an increase in marine storage revenue of $5.6 million primarily due to

higher average rates from contract renewals and escalations. Total

utilization decreased slightly due in part to timing of project work to

convert tanks to crude oil service at our Galena Park, Texas terminal in

       2016.



Affiliate management fee revenue increased $0.8 million primarily resulting from
a one-time start-up fee received from Saddlehorn, which began operations in
, partially offset by lower construction management fees received
from our joint ventures and lower fees from Osage Pipe Line Company, LLC
("Osage") due to the transfer of our 50% membership interest in 2016.

Operating expenses increased $3.9 million, resulting from:

• an increase in refined products expenses of $3.3 million primarily

resulting from rental costs related to a pipeline segment we began leasing

in third quarter 2016 in connection with our Little Rock pipeline

extension, higher asset retirements and higher environmental accruals,

partially offset by lower asset integrity spending due to timing of tank

       maintenance work;



• a decrease in crude oil expenses of $0.7 million as lower power costs and

more favorable product overages (which reduce operating expenses) were

       primarily offset by increased personnel costs related to incremental
       headcount to support the crude oil segment; and


• an increase in marine storage expenses of $3.2 million primarily

attributable to higher asset integrity spending in the current year.




Product sales revenue resulted primarily from our butane blending activities,
transmix fractionation and the sale of product gains from our operations. We
utilize futures contracts to hedge against changes in the price of petroleum
products we expect to sell in future periods, as well as to hedge against
changes in the price of butane we expect to purchase. See Note 13 -Derivative
Financial Instruments in Item 8. Financial Statements and Supplementary Data for
a discussion of our hedging strategies and how our use of futures contracts
impacts our product margin. Product margin decreased $76.2 million primarily due
to lower margins from our butane blending activities as a result of lower
realized sales prices and higher losses on futures contracts recognized in 2016.
See Other Items-Commodity Derivative Agreements-Impact of Commodity Derivatives
on Results of Operations below for more information about our futures contracts.
Earnings of non-controlled entities increased $12.2 million primarily
attributable to increased earnings from BridgeTex due to higher shipments in
2016, as well as earnings from Saddlehorn, which began operating during third
quarter 2016, and higher earnings from Double Eagle.

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Depreciation and amortization expense increased $11.3 million in 2016 primarily due to recent expansion capital expenditures.


G&A expense decreased $3.5 million between periods primarily due to lower
equity-based incentive compensation and lower employee bonus accruals.
Interest expense, net of interest income and interest capitalized, increased
$22.2 million in 2016 primarily due to higher outstanding debt, partially offset
by higher capitalized interest. Our average outstanding debt increased from $3.3
billion in 2015 to $3.9 billion in 2016 primarily due to borrowings for
expansion capital expenditures. In addition, our weighted-average interest rate
of 4.9% in 2016 was higher than the 4.7% rate incurred in 2015.
In 2016, we recognized a $28.1 million gain related to the transfer of our 50%
membership interest in Osage. See Note 4 - Investments in Non-Controlled
Entities in Item 8. Financial Statements and Supplementary Data of this report
for more details regarding this transaction.
Other income increased $7.2 million due to a more favorable non-cash adjustment
in the current year for the change in the differential between the current spot
price and forward price on fair value hedges associated with our crude oil tank
bottoms. Additionally, other income for the current period includes a break-up
fee related to a potential acquisition.



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Year Ended Compared to Year Ended

                                                                                        Variance
                                               Year Ended December 31,          Favorable (Unfavorable)
                                                2014             2015           $ Change         % Change
Financial Highlights ($ in millions,
except operating statistics)
Transportation and terminals revenue:
Refined products                           $     946.6       $     974.5     $       27.9              3  %
Crude oil                                        341.9             394.1             52.2             15  %
Marine storage                                   170.7             176.1              5.4              3  %
Total transportation and terminals
revenue                                        1,459.2           1,544.7             85.5              6  %
Affiliate management fee revenue                  22.1              13.9             (8.2 )          (37 )%
Operating expenses:
Refined products                                 356.0             377.8            (21.8 )           (6 )%
Crude oil                                         83.2              89.5             (6.3 )           (8 )%
Marine storage                                    65.2              62.5              2.7              4  %
Intersegment eliminations                         (3.5 )            (3.9 )            0.4             11  %
Total operating expenses                         500.9             525.9            (25.0 )           (5 )%
Product margin:
Product sales                                    879.0             629.8           (249.2 )          (28 )%
Cost of product sales                            594.6             447.3            147.3             25  %
Product margin                                   284.4             182.5           (101.9 )          (36 )%
Earnings of non-controlled entities               19.4              66.5             47.1            243  %
Operating margin                               1,284.2           1,281.7             (2.5 )            -  %
Depreciation and amortization expense            161.7             166.8             (5.1 )           (3 )%
G&A expense                                      148.3             151.3             (3.0 )           (2 )%
Operating profit                                 974.2             963.6            (10.6 )           (1 )%
Interest expense (net of interest income
and interest capitalized)                        121.5             143.2            (21.7 )          (18 )%
Other expense (income)                             8.6              (1.0 )            9.6            n/a
Income before provision for income taxes         844.1             821.4            (22.7 )           (3 )%
Provision for income taxes                         4.6               2.3              2.3             50  %
Net income                                 $     839.5       $     819.1     $      (20.4 )           (2 )%

Operating Statistics
Refined products:
Transportation revenue per barrel
shipped                                    $     1.399       $     1.439
Volume shipped (million barrels):
Gasoline                                         256.1             268.1
Distillates                                      163.1             152.5
Aviation fuel                                     23.0              21.2
Liquefied petroleum gases                          9.9               9.7
Total volume shipped                             452.1             451.5
Crude oil:
Magellan 100%-owned assets:
Transportation revenue per barrel
shipped                                    $     1.192       $     1.118
Volumes shipped (million barrels)                185.5             209.9
Crude oil terminal average utilization
(million barrels per month)                       12.2              13.1
Select joint venture pipelines:
BridgeTex - volume shipped (million               18.3              75.2

barrels)(a)

Marine storage:
Marine terminal average utilization
(million barrels per month)                       22.9              24.0




(a) These volumes reflect the total shipments for the BridgeTex pipeline,

       which began operations in  and is owned 50% by us.



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Transportation and terminals revenue increased by $85.5 million, resulting from:

• an increase in refined products revenue of $27.9 million primarily

attributable to higher transportation revenue and related ancillary fees.

Higher transportation revenue was favorably impacted by higher rates,

which increased due to the mid-year 2014 and 2015 tariff rate increases of

3.9% and 4.6%, respectively. Volumes were essentially the same between

periods as lower distillate shipments were offset by higher gasoline

demand. Distillate shipments were 7% lower due to reduced demand from

drilling activities and wet agricultural conditions in the areas served by

our assets, whereas gasoline shipments increased 5% resulting from

refinery turnarounds that increased demand on our system and lower

gasoline prices that increased overall demand for gasoline. Additionally,

revenue from our independent terminals increased primarily from two

terminal acquisitions, revenue from storage services along our pipeline

system increased due to new customer contracts and our ammonia pipeline

       revenue increased due to higher rates and volumes;


• an increase in crude oil revenue of $52.2 million primarily due to revenue

received in 2015 from BridgeTex to lease capacity on our Houston-area

crude oil distribution system and higher crude oil deliveries on our

Longhorn pipeline, partially offset by lower tender deductions received

from customers. Shipments on our Longhorn pipeline averaged approximately

260,000 barrels per day in 2015, an increase of approximately 30,000

barrels per day over 2014. Additionally, terminalling revenue was higher

resulting from new storage contracts and from a customer buying out of its

remaining storage contract in 2015. Transportation revenue per barrel

shipped was lower in 2015 due to reduced average tariffs resulting from a

lower volume of spot shipments on the Longhorn pipeline system, which ship

at a higher rate, and more short-haul movements on our Houston-area crude

oil distribution system in 2015; and

• an increase in marine storage revenue of $5.4 million primarily due to

improved storage utilization from new contracts and less storage out of

service for maintenance work, as well as higher ancillary fees reflecting

increased customer activities at our marine facilities. Higher average

storage rates from contract renewals and escalations in 2015 were offset

by a one-time favorable contract adjustment in 2014.

Affiliate management fee revenue decreased $8.2 million in 2015 due to lower construction management fees related to BridgeTex, as the pipeline became operational in .

Operating expenses increased $25.0 million, resulting from:

• an increase in refined products expenses of $21.8 million primarily

resulting from higher asset integrity spending and higher personnel costs,

       partially offset by more favorable product overages (which reduce
       operating expense) and lower power costs;


• an increase in crude oil expenses of $6.3 million primarily due to higher

pipeline rental fees and costs associated with having more assets in crude

oil service in 2015, such as higher personnel costs and property taxes,

       partially offset by more favorable product overages (which reduce
       operating expense); and



•      a decrease in marine storage expenses of $2.7 million primarily
       attributable to lower asset integrity costs due to timing of project work
       and lower property taxes due to a favorable adjustment in 2015.



Product margin decreased $101.9 million primarily due to reduced gains on
futures contracts in 2015 versus 2014, partially offset by higher profits from
our transmix fractionation activities resulting from lower inventory costs and
higher volumes and favorable lower-of-cost-or-market ("LCM") inventory
adjustments (2014 included a $39.3 million LCM inventory adjustment to our
fractionation and butane blending inventories due to the significant decline in
commodity prices at the end of that year, compared to a $5.0 million LCM
inventory adjustment in 2015).
Earnings of non-controlled entities increased $47.1 million primarily due to our
share of earnings from BridgeTex, which began operations late in 2014.

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Depreciation and amortization expense increased $5.1 million in 2015 primarily
due to expansion capital projects placed into service and a $1.8 million asset
impairment charge recognized in 2015, partially offset by the $9.4 million
acceleration of depreciation for pipeline, terminal and related assets during
2014 that we later sold.

G&A expense increased $3.0 million between periods primarily due to higher
personnel costs resulting from an increase in employee headcount and higher
pension and benefit costs, partially offset by lower costs associated with
deferred board of director compensation and equity-based compensation resulting
from a decrease in the price of our limited partner units in 2015.
Interest expense, net of interest income and interest capitalized, increased
$21.7 million in 2015 primarily due to higher debt outstanding in 2015 compared
to 2014 and lower capitalized interest related to BridgeTex in 2015 since
BridgeTex began operations in . Our average outstanding debt
increased from $2.9 billion in 2014 to $3.3 billion in 2015 primarily due to
borrowings for expansion capital expenditures. Our weighted-average interest
rate decreased from 4.9% in 2014 to 4.7% in 2015 due to the impact of our
commercial paper borrowings and  debt issuances, which are both at
lower weighted-average rates than the debt we retired in mid-2014.
Other expense (income) included $9.6 million of favorable non-cash adjustments
for the change in the differential between the then-current spot price and
forward price on fair value hedges associated with our crude oil tank bottoms
and linefill assets.
Provision for income taxes was $2.3 million favorable due to a reduction in the
franchise tax rate for the state of Texas in 2015.



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Distributable Cash Flow


Distributable cash flow ("DCF") and Adjusted EBITDA are non-GAAP measures. See
Item 6. Selected Financial Data for a discussion of how management uses these
non-GAAP measures. A reconciliation of DCF and Adjusted EBITDA for the years
ended , 2015 and 2016 to net income, which is the nearest
comparable GAAP financial measure, is as follows (in millions):
                                                               Year Ended December 31,
                                                          2014          2015           2016
Net income                                             $   839.5     $   819.1     $    802.8
Interest expense, net(1)                                   121.5         143.2          165.4
Depreciation and amortization                              161.8         166.8          178.1
Equity-based incentive compensation expense(2)              12.5           6.5            5.0
Loss on sale and retirement of assets                        7.2           7.9           11.2
Gain on exchange of interest in non-controlled
entity(3)                                                      -             -          (28.1 )
Commodity-related adjustments:
Derivative losses (gains) recognized in the period
associated with future product transactions(5)             (87.5 )       (47.8 )         21.8
Derivative (losses) gains recognized in previous
periods associated with product sales completed in
the period(5)                                               (8.1 )        96.1           45.2
Lower-of-cost-or-market inventory adjustments(6)            39.3         (34.3 )         (2.8 )
Total commodity-related adjustments                        (56.3 )        14.0           64.2
Cash distributions received from non-controlled
entities in excess of (less than) earnings for the
period                                                      (8.7 )        14.5            9.3
Other(4)                                                       -             -            5.3
Adjusted EBITDA                                          1,077.5       1,172.0        1,213.2
Interest expense, net, excluding debt issuance cost
amortization(1)                                           (119.2 )      (140.5 )       (162.2 )
Maintenance capital(7)                                     (77.8 )       (88.7 )       (103.5 )
DCF                                                    $   880.5     $   942.8     $    947.5


(1) For the purpose of calculating DCF, we have excluded debt issuance cost

amortization from interest expense of $2.3 million, $2.7 million and $3.2

million for the years ended , 2015 and 2016,

respectively.

(2) Because we intend to satisfy vesting of unit awards under our equity-based

incentive compensation program with the issuance of limited partner units,

expenses related to this program generally are deemed non-cash and added

back for DCF purposes. Total equity-based incentive compensation expense

for the years ended , 2015 and 2016 was $27.3 million,

$24.3 million and $19.4 million, respectively. However, the figures above

include adjustments of $14.8 million, $17.8 million and $14.4 million,

respectively, for minimum statutory tax withholdings we paid in connection

with our equity-based incentive compensation program.

(3) In , we transferred our 50% membership interest in Osage to

an affiliate of HollyFrontier Corporation ("HFC"). In conjunction with

this transaction, we entered into several commercial agreements with

affiliates of HFC, which were recorded as intangible assets and other

       receivables on our consolidated balance sheets.  We recorded a $28.1
       million non-cash gain in relation to this transaction.


(4)    In conjunction with the  Osage transaction, HFC agreed to
       make certain payments to us until HFC completes a connection to our El

Paso terminal. These payments replace distributions we would have received

had the Osage transaction not occurred and are, therefore, included in our

calculation of DCF.

(5) Certain derivatives we use as economic hedges have not been designated as

       hedges for accounting purposes and the mark-to-market changes of these
       derivatives are recognized currently in earnings. In addition, we have

designated certain derivatives we use to hedge our crude oil tank bottoms

       as fair value hedges and the change in the differential between the
       current spot price and forward price on these hedges is recognized
       currently in earnings. We exclude the net impact of both of these
       adjustments from our determination of DCF until the hedged products are
       physically sold. In the period in which these hedged products are
       physically sold, the net impact of the associated hedges is included in
       our determination of DCF.


(6)    We add the amount of LCM adjustments on inventory and firm purchase
       commitments we recognize in each applicable period to determine DCF as

these are non-cash charges against income. In subsequent periods when we

       physically sell or purchase the related products, we deduct the LCM
       adjustments previously recognized to determine DCF.


(7)    Maintenance capital expenditures maintain our existing assets and do not

generate incremental DCF (i.e. incremental returns to our unitholders).

For this reason, we deduct maintenance capital expenditures to determine

       DCF.



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Liquidity and Capital Resources

Cash Flows and Capital Expenditures




Operating Activities. Net cash provided by operating activities was $1,107.3
million, $1,069.7 million and $964.0 million for the years ended , 2015 and 2016, respectively. The $105.7 million decrease from 2015 to 2016
was due to changes in our working capital, adjustments to non-cash items and
lower net income as previously described. The $37.6 million decrease from 2014
to 2015 was due to changes in our working capital and lower net income as
previously described, partially offset by adjustments to non-cash items.
Investing Activities. Net cash used by investing activities for the years ended
, 2015 and 2016 was $830.0 million, $810.8 million and $857.4
million, respectively. During 2016, we incurred $653.5 million for capital
expenditures, which included $103.5 million for maintenance capital and $550.0
million for expansion capital. Also during 2016, we contributed capital of
$200.0 million in conjunction with our joint venture capital projects, which we
account for as investments in non-controlled entities. During 2015, we incurred
$623.3 million for capital expenditures, which included $88.7 million for
maintenance capital and $534.6 million for expansion capital. Also during 2015,
we acquired a refined products terminal in the Atlanta, Georgia market for $54.7
million and we contributed capital of $152.5 million in conjunction with our
joint venture capital projects. During 2014, we incurred $366.4 million for
capital expenditures, which included $77.8 million for maintenance capital and
$288.6 million for expansion capital. Also during 2014, we contributed capital
of $408.0 million in conjunction with our joint venture capital projects
(primarily BridgeTex) and we acquired from a subsidiary of Oxy its ownership
interest in a 40-mile crude oil pipeline in the Houston Gulf Coast area for
$75.0 million.
Financing Activities. Net cash used by financing activities for the years ended
, 2015 and 2016 was $285.5 million, $247.3 million and $120.7
million, respectively. During 2016, we paid cash distributions of $739.2 million
to our unitholders. Additionally, we received net proceeds of $1.1 billion from
borrowings under long-term notes, which were used in part to repay our $250.0
million of 5.65% notes due 2016, to repay borrowings outstanding under our
commercial paper program and for general partnership purposes, including
expansion capital. Net commercial paper repayments during 2016 totaled $230.0
million. In connection with certain of the borrowings under long-term notes, we
paid $19.3 million in settlement of associated interest rate swap agreements.
Also, in , the cumulative amounts of the  equity-based
incentive compensation awards were settled by issuing 350,552 limited partner
units to the long-term incentive plan ("LTIP") participants, resulting in
payments of associated tax withholdings of $14.4 million. During 2015, we paid
cash distributions of $662.9 million to our unitholders. Additionally, we
received net proceeds of $499.6 million from borrowings under long-term notes,
which were used in part to repay borrowings outstanding under our commercial
paper program and for general partnership purposes, including expansion capital.
In connection with the borrowings under long-term notes, we paid $42.9 million
in settlement of associated interest rate swap agreements. Also, in , the cumulative amounts of the  equity-based incentive
compensation awards were settled by issuing 354,529 limited partner units to the
LTIP participants, resulting in payments of associated tax withholdings of $17.8
million. During 2014, we paid cash distributions of $568.8 million to our
unitholders. Additionally, we received net proceeds of $257.7 million from
borrowings under long-term notes and $296.9 million from borrowings under our
commercial paper program, which were used in part to repay our $250.0 million of
6.45% notes due 2014, to repay borrowings outstanding under our revolving credit
facility and for general partnership purposes, including expansion capital.
Also, in 2014, the cumulative amounts of the 2011 equity-based incentive
compensation awards were settled by issuing 387,216 limited partner units to the
LTIP participants, resulting in payments of associated tax withholdings of $14.8
million.
The quarterly distribution amount related to fourth quarter 2016 earnings was
$0.855 per unit, which was paid in . If we are able to meet
management's targeted distribution growth of 8% during 2017 and the number of
outstanding limited partner units remains at 228.0 million, total cash
distributions of approximately $817 million will be paid to our unitholders
related to 2017 earnings. Management believes we will have sufficient
distributable cash flow to fund these distributions.

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Capital Requirements

Our businesses require continual investment to upgrade or enhance existing operations and to ensure compliance with safety and environmental regulations. Capital spending for our businesses consists primarily of:

• Maintenance capital expenditures. These capital expenditures include costs

required to maintain equipment reliability and safety and to address

environmental or other regulatory requirements rather than to generate

       incremental DCF; and



•      Expansion capital expenditures. These expenditures are undertaken
       primarily to generate incremental DCF and include costs to acquire
       additional assets to grow our business and to expand or upgrade our

existing facilities, which we refer to as organic growth projects. Organic

growth projects include, for example, capital expenditures that increase

       storage or throughput volumes or develop pipeline connections to new
       supply sources.


During 2016, our maintenance capital spending was $103.5 million. For 2017, we expect to spend approximately $90.0 million on maintenance capital.


During 2016, we spent $550.0 million for expansion capital and contributed
$200.0 million to our joint venture capital projects, primarily related to our
investment in Saddlehorn. Based on the progress of expansion projects already
underway, we expect to spend approximately $550.0 million for expansion capital
during 2017, with an additional $350.0 million in 2018 to complete our current
projects. See Growth Projects above for additional information.

Liquidity


Cash generated from operations is a key source of liquidity for funding debt
service, maintenance capital expenditures and quarterly distributions.
Additional liquidity for purposes other than quarterly distributions, such as
expansion capital expenditures and debt repayments, is available through
borrowings under our commercial paper program and revolving credit facilities,
as well as from other borrowings or issuances of debt or limited partner units
(see Note 12 - Debt in Item 8. Financial Statements and Supplementary Data of
this report for detail of our borrowings and debt outstanding at  and 2016). If capital markets do not permit us to issue additional debt and
equity securities, our business may be adversely affected, and we may not be
able to acquire additional assets and businesses, fund organic growth projects
or continue paying cash distributions at the current level.

Off-Balance Sheet Arrangements
None.


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Contractual Obligations
The following table summarizes our contractual obligations as of  (in millions):

                                     Total        < 1 year      1-3 years       3-5 years      > 5 years
Long-term debt obligations(1)     $ 4,100.0     $        -     $    800.0     $     600.0     $  2,700.0
Interest obligations(1)             2,860.4          204.3          365.2           280.9        2,010.0
Operating lease obligations           238.4           38.6           54.0            35.2          110.6
Pension and postretirement
medical obligations(2)                 72.1           23.1           36.7             3.1            9.2
Purchase commitments:
Product purchase commitments(3)       166.4          111.3           45.2             9.9              -
Utility purchase commitments           19.4            8.4            9.4             1.5            0.1
Derivative instruments(4)                 -              -              -               -              -
Equity-based incentive
awards(5)                              40.0           22.6           17.4               -              -
Capital project purchase
obligations                           108.4          102.6            5.8               -              -
Maintenance obligations                90.3           90.0            0.3               -              -
Other                                   8.5            4.6            2.1             1.8              -
Total                             $ 7,703.9     $    605.5     $  1,336.1     $     932.4     $  4,829.9


(1) At , we had no borrowings outstanding under our revolving

credit facility. For purposes of this table, we have reflected no assumed

borrowings under our revolving credit facility for any periods presented.

We assumed that the amounts outstanding under our commercial paper program

at would be repaid in , the maturity date of

       our revolving credit facility, which supports our commercial paper
       program. Further, we have included interest obligations based on the
       stated amounts of our fixed-rate obligations. For our variable-rate debt,

we calculated interest obligations assuming the weighted-average interest

rate of our variable-rate debt at on amounts outstanding

       through the assumed repayment date.


(2)    Represents the projected benefit obligation of our pension and
       postretirement medical plans less the fair value of plan assets.


(3)    Includes product purchase commitments for which the price provisions are
       indexed based on the date of delivery. We have estimated the value of
       these commitments using the related index price as of .
       Also, we have excluded certain product purchase agreements for which there
       is no specified or minimum quantity.


(4)    As of , we had entered into exchange-traded futures

contracts representing 4.6 million barrels of petroleum products that we

expect to sell in the future and 0.7 million barrels of butane we expect

to purchase in the future. At , we had recorded a net

liability of $30.7 million and received margin deposits of $49.9 million.

We have excluded from this table the future net cash outflows, if any,

under these futures contracts and the amounts of future margin deposit

       requirements because those amounts are uncertain.


(5)    The total equity-based incentive awards obligation is determined by
       multiplying the grant date per unit fair value by the number of unit

awards granted, multiplied by the percentage of the requisite service

       period completed, multiplied by the estimated payout percentage of the
       awards at . Settlements of these awards will differ from
       these reported amounts primarily due to differences between actual and

current estimates of payout percentages and completion of the remaining

portion of the requisite service periods.

Environmental


Our operations are subject to federal, state and local environmental laws and
regulations. We have accrued liabilities for estimated costs at our facilities
and properties. We record liabilities when environmental costs are probable and
can be reasonably estimated. The determination of amounts recorded for
environmental liabilities involves significant judgments and assumptions by
management. Due to the inherent uncertainties involved in determining
environmental liabilities, it is reasonably possible that the actual amounts
required to extinguish these liabilities could be materially different from
those we have recognized.


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Other Items


Commodity Derivative Agreements. Certain of the business activities in which we
engage result in our owning various commodities, which exposes us to commodity
price risk. We use forward physical commodity contracts and exchange-based
futures contracts to help manage this commodity price risk. We use forward
physical contracts to purchase butane and sell refined products. We account for
these forward physical contracts as normal purchase and sale contracts, using
traditional accrual accounting.  We use futures contracts to hedge against
changes in prices of refined products and crude oil that we expect to sell and
of butane that we expect to purchase in future periods. We use and account for
those futures contracts that qualify for hedge accounting treatment as either
cash flow or fair value hedges, and we use and account for those futures
contracts that do not qualify for hedge accounting treatment as economic hedges.

As of and for the year ended , our open derivative contracts and the impact of the derivatives we settled during the period were as follows:

•      Futures contracts to hedge against future price changes of certain crude
       oil tank bottoms, which we account for as fair value hedges. The
       cumulative amount of gains from these agreements was recorded as an
       adjustment to the asset being hedged, and there has been no

ineffectiveness recognized for these hedges. We exclude the differential

between the current spot price and forward price from our assessment of

hedge effectiveness for these fair value hedges, and we recognize the net

       change in this excluded amount as other income on our consolidated
       statements of income.


• Futures contracts used to hedge sales and purchases of refined products,

crude oil and butane related to our butane blending, fractionation, and

certain crude oil inventory activities. These contracts were accounted for

as economic hedges, with the change in fair value of contracts that hedge

future sales recorded to product sales, and the change in fair value of

contracts that hedge future purchases recorded to cost of product sales.

• Futures contracts used to hedge sales of refined products and crude oil

inventory we carry that resulted from pipeline product overages. These

contracts were accounted for as economic hedges, with the change in fair

value of these contracts recorded to operating expense.




For further information regarding the quantities of refined products and crude
oil hedged at  and the fair value of open hedge contracts at
that date, please see Item 7A. Quantitative and Qualitative Disclosures about
Market Risk.

The following tables provide a summary of the impacts of the mark-to-market gains and losses associated with these futures contracts on our results of operations for the respective periods presented (in millions):

                                                               Year Ended December 31, 2014
                                                                                                          Net Impact on
                                  Product Sales       Cost of          Operating                            Results of
                                     Revenue       Product Sales        Expense        Other Expense        Operations
Gains (losses) recorded on open
futures contracts during the
period                           $        83.8     $    (10.6 )     $         8.2     $        (8.6 )   $           72.8
Gains (losses) recognized on
settled futures contracts during
the period                                61.5           (6.5 )               9.6                 -                 64.6

Net impact of futures contracts $ 145.3 $ (17.1 ) $

 17.8     $        (8.6 )   $          137.4




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                                                                 Year Ended December 31, 2015
                                                                                                             Net Impact on
                                  Product Sales     Cost of Product       Operating                            Results of
                                     Revenue             Sales             Expense        Other Income         Operations
Gains (losses) recorded on open
futures contracts during the
period                           $         41.3     $      (5.2 )      $         3.1     $         1.0     $           40.2
Gains (losses) recognized on
settled futures contracts during
the period                                 27.1            (3.8 )                8.7                 -                 32.0

Net impact of futures contracts $ 68.4 $ (9.0 ) $

    11.8     $         1.0     $           72.2



                                                                   Year Ended December 31, 2016
                                                                                                                 Net Impact on
                                  Product Sales        Cost of                                                     Results of
                                     Revenue        Product Sales     Operating Expense      Other Income          Operations
Gains (losses) recorded on open
futures contracts during the
period                           $      (30.2 )     $        6.1     $           (3.6 )     $         5.2     $        (22.5 )
Gains (losses) recognized on
settled futures contracts during
the period                               (8.4 )              4.9                 (1.4 )                 -               (4.9 )

Net impact of futures contracts $ (38.6 ) $ 11.0 $

(5.0 ) $ 5.2 $ (27.4 )




Pipeline Tariff Increase. The Federal Energy Regulatory Commission ("FERC")
regulates the rates charged on interstate common carrier pipeline operations
primarily through an indexing methodology, which establishes the maximum amount
by which index-based tariffs can be adjusted each year.  Approximately 40% of
our refined products tariffs are subject to this indexing methodology. The
remaining 60% of our refined products tariffs are either subject to regulations
by the states in which we operate or are deemed competitive by the FERC, and in
both cases these rates can be adjusted at our discretion based on market
factors.  The current FERC-approved indexing method is the annual change in the
producer price index for finished goods ("PPI-FG") plus 1.23%. The change in
PPI-FG for 2016 is preliminarily expected to be negative 1%. As a result, we
expect to slightly increase rates in the 40% of our markets that are subject to
the FERC's index methodology on .  While we continue to evaluate the
remaining 60% of our markets, we generally intend to increase rates in those
markets by 3% to 4% on , consistent with the 2016 rate increase for
our competitive markets.

Board of Director Changes in 2016. In , Lori A. Gobillot and Edward J.
Guay were elected to our general partner's board of directors as independent
directors.

In , Patrick C. Eilers, an independent member of our general partner's
board of directors, resigned from the board to pursue other interests. Mr.
Eilers accepted a full-time position with a firm that has a policy restricting
its employees from serving on the board of directors of a public company. Mr.
Eilers' resignation was not the result of any disagreement with us on any matter
relating to our operations, policies or practices.

Related Party Transactions. See Note 11 - Related Party Transactions in Item 8.
Financial Statements and Supplementary Data of this report for detail of our
related party transactions.

Critical Accounting Estimates

Our management has discussed the development and selection of the following critical accounting estimates with the audit committee of our general partner's board of directors, which has reviewed and approved these disclosures.

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Environmental Liabilities


We estimate the liabilities associated with environmental expenditures based on
site-specific project plans for remediation, taking into account prior
remediation experience. Remediation project managers evaluate each known case of
environmental liability to determine what associated costs can be reasonably
estimated and to ensure compliance with all applicable federal and state
requirements. The accounting estimate relative to environmental remediation
costs is a critical accounting estimate for each of our operating segments
because: (i) estimated expenditures are subject to cost fluctuations and could
change materially, (ii) as remediation work is performed and additional
information relative to each specific site becomes known, cost estimates for
those sites could change materially, (iii) unanticipated third-party liabilities
may arise, (iv) it is difficult to determine the amounts, if any, of penalties
that may be levied by governmental agencies with regard to certain environmental
events, and (v) when changes in federal, state and local environmental
regulations occur, these changes could significantly impact the amount of our
environmental liability accruals.

A defined process for project review is integrated into our system integrity
plan. Each year our remediation project managers meet to evaluate, in detail,
our known environmental sites. The purpose of the annual project review is to
assess all aspects of each project, evaluating what actions will be required to
achieve regulatory compliance and estimating the costs and timing to execute the
regulatory phases that can be reasonably estimated. During the site-specific
evaluations, we utilize all known information in conjunction with professional
judgment and experience to determine the appropriate approach for remediation
and to assess liabilities. The process to achieve regulatory compliance consists
of site investigation/delineation, site remediation and long-term monitoring.
Each of these phases can, and often does, include unknown variables that
complicate the task of evaluating the estimated costs to completion. At each
accounting period-end, we re-evaluate our environmental estimates taking into
account any new incidents that have occurred since the last annual meeting of
the remediation project managers, any changes in the site situation remediation,
including work to date, additional findings or changes in federal or state
regulations and changes in cost estimates. Changes in our environmental
liabilities since  were as follows (in millions):
Balance                2015                 Balance                 2016                Balance
12/31/14    Accruals      Expenditures      12/31/15     Accruals      Expenditures     12/31/16
 $36.3         $6.3          $(11.2)          $31.4         $8.4          $(15.8)        $24.0



During 2016, we accrued $8.4 million of environmental liabilities. Of this
amount, $8.6 million related to product releases that occurred during 2016, and
the remaining accrual adjustments of $(0.2) million related to historical
releases. At , we had recognized $4.1 million of receivables
from insurance carriers associated with environmental claims.

During 2015, we accrued $6.3 million of environmental liabilites. Of this
amount, $5.6 million related to product releases that occurred during 2015 and
$0.7 million related to historical releases. At , we had
recognized $2.6 million of receivables from insurance carriers associated with
environmental claims.

We based our period-end environmental liabilities on estimates that are subject
to change, and any changes to these estimates would affect our results of
operations and financial position. Any increase in our environmental liabilities
would decrease our operating profit and net income by the same amount, which
would negatively impact basic and diluted net income per limited partner unit.

Pension and Postretirement Obligations


We sponsor two union pension plans covering certain employees ("USW plan" and
"IUOE plan"), a pension plan for all non-union employees ("Salaried plan") and a
postretirement benefit plan for certain employees. Various estimates and
assumptions directly affect net periodic benefit expense and obligations for
these plans. These estimates and assumptions include the expected long-term
rates of return on plan assets, discount rates, expected rate of compensation
increase and the assumed health care cost trend rate. Management reviews these
assumptions annually and makes adjustments as necessary.

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The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations that would result from a 1% change in the specified assumption (in thousands):


                                            Benefit Expense                 

Benefit Obligation

                                    1% Increase         1% Decrease        1% Increase        1% Decrease
Pension benefits:
 Discount rate                    $   (3,356 )        $    3,858          $ (23,407 )        $  28,350
 Expected long-term rate of
return on plan assets             $   (1,073 )        $    2,128          $       -          $       -

Rate of compensation increase $ 2,614 $ (2,773 ) $

  11,761          $ (11,894 )
Other postretirement benefits:
 Discount rate                    $     (129 )        $      164          $  (1,437 )        $   1,840
 Assumed health care cost
trend rate                        $       87          $      (81 )        $     521          $    (481 )




The following table sets forth the increase (decrease) in our pension funding
based on our current funding policy assuming a 1% change in the specified
criterion (in thousands):
                                 1% Increase     1% Decrease
Projected return on assets      $      (131 )   $        131
Rate of compensation increase   $     3,483     $     (3,496 )



The discount rate directly affects the measurement of the benefit obligations of
our pension and other postretirement benefit plans. The objective of the
discount rate is to determine the amount, if invested at the 
measurement date in a portfolio of high-quality fixed income securities, that
would provide the necessary cash flows to make benefit payments when due.
Decreases in the discount rate increase the obligation and generally increase
the related expense, while increases in the discount rate have the opposite
effect. Changes in general economic and market conditions that affect interest
rates on long-term high-quality fixed income securities as well as the duration
of our plans' liabilities affect our estimate of the discount rate.

We estimate the long-term expected rate of return on plan assets using
expectations of capital market results, which includes an analysis of historical
results as well as forward-looking projections. We base these capital market
expectations on a long-term period and on our investment strategy and asset
allocation. We develop our estimates using input from several external sources,
including consultation with our third-party independent investment consultant.
We develop the forward-looking capital market projections using a consensus of
expectations by economists for inflation and dividend yield, along with expected
changes in risk premiums. Because our determined rate is an estimate of future
results, it could be significantly different from actual results. The expected
rates of return on plan assets are long-term in nature; therefore, short-term
market performance does not significantly affect our estimated long-term
expected rate of return.

The expected rate of compensation increase represents average long-term salary
increases. An increase in this rate causes the pension obligation and expense to
increase. We base the assumed health care cost trend rates on national trend
rates adjusted for our actual historical claims experience and plan design. An
increase in this rate causes the other postretirement benefit obligation and
expense to increase.

Valuation of Assets
The application of business combination and impairment accounting requires us to
use significant estimates and assumptions in determining the fair value of
assets and liabilities. The acquisition method of accounting for business
combinations requires us to estimate the fair value of assets acquired and
liabilities assumed to allocate the proper amount of the purchase price
consideration between goodwill and the assets that are depreciated and
amortized. We record intangible assets separately from goodwill and amortize
intangible assets with finite lives over their estimated useful life as
determined by management. We do not amortize goodwill or intangible assets with
indefinite lives but instead periodically assess these for impairment.


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For all material acquisitions, we engage the services of an independent
appraiser to assist us in determining the fair value of the acquired assets and
liabilities, including goodwill; however, the ultimate determination of those
values is the responsibility of our management. We base our estimates on
assumptions believed to be reasonable, but which are inherently uncertain. These
valuations require the use of management's assumptions, which would not reflect
unanticipated events and circumstances that may occur.

Goodwill and Impairment of Long-Lived Assets


Goodwill. At  and 2016, we had recognized goodwill of $53.3
million. Goodwill resulting from a business combination is not subject to
amortization. As required by Accounting Standards Codification ("ASC") 350,
Goodwill and Other, we test goodwill at the reporting unit level for impairment
annually and between annual tests if events or changes in circumstances indicate
the carrying amount may exceed fair value. For 2016, we performed a qualitative
assessment to determine whether the fair value of our reporting units was more
likely than not less than their respective carrying amounts. Our evaluation
consisted of assessing the general impact of how a number of different elements
would affect the fair value of our reporting units, including the current and
projected future earnings of our reporting units, our capitalization, our
current slate of capital projects, the growth in the distributions we pay to our
unitholders, current and future interest rates and the impact of lower commodity
prices on our earnings and the acquisition markets. Our qualitative assessment
indicated that there was no need to conduct further quantitative testing for
goodwill impairment and our analysis did not reflect any reporting units at risk
of impairment. Different judgments from those we used in our qualitative
analysis could result in the requirement to perform a quantitative goodwill
impairment analysis. Results from that quantitative analysis could use
projections and estimates different from those others might use, which could
result in the recognition of an impairment loss. Any such impairment losses
recognized could be material to our results of operations. The accounting
estimate relative to assessing the impairment of goodwill is a critical
accounting estimate for our refined products and crude oil segments. Based on
our assessments at , 2015 and 2016, we did not record a
goodwill impairment for any of these years.

Impairment of Long-Lived Assets. As prescribed by ASC 360-10-05, Property, Plant
and Equipment-General-Impairment or Disposal of Long-Lived Assets, we assess
property, plant and equipment for possible impairment whenever events or changes
in circumstances indicate that the carrying value of the assets may not be
recoverable. Such indicators include, among others, the nature of the asset, the
projected future economic benefit of the asset, changes in regulatory and
political environments and historical and future cash flow and profitability
measurements. If the carrying value of an asset exceeds the future undiscounted
cash flows expected from the asset, we recognize an impairment charge for the
excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves
management estimates on highly uncertain matters such as future commodity
prices, the effects of inflation and technology improvements on operating
expenses and the outlook for national or regional market supply and demand
conditions. We base the impairment reviews and calculations used in our
impairment tests on assumptions that are consistent with our business plans and
long-term investment decisions. Impairments recognized during 2014, 2015 and
2016 were not material.

An estimate as to the sensitivity to earnings for these periods had we used
other assumptions in our impairment reviews and impairment calculations is not
practicable, given the broad range of our property, plant and equipment and the
number of assumptions involved in the estimates. Favorable changes to some
assumptions might have avoided the need to impair any assets in these periods,
whereas unfavorable changes might have caused an increase in impairments
recognized.

For specific details of the impairment analysis of our Corpus Christi condensate
splitter, please refer to Note 2 - Summary of Significant Accounting Policies in
Item 8. Financial Statements and Supplementary Data of this report.

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New Accounting Pronouncements


See Note 2 - Summary of Significant Accounting Policies in Item 8. Financial
Statements and Supplementary Data of this report for a summary of new accounting
pronouncements.


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Forward-Looking Statements


Certain matters discussed in this Annual Report on Form 10-K include
forward-looking statements within the meaning of the federal securities laws
that discuss our expected future results based on current and pending business
operations. Forward-looking statements can be identified by words such as
"anticipates," "believes," "continue," "could," "estimates," "expects,"
"forecasts," "goal," "guidance," "intends," "may," "might," "plans,"
"potential," "projected," "scheduled," "should," "will" and other similar
expressions. Although we believe our forward-looking statements are based on
reasonable assumptions, statements made regarding future results are not
guarantees of future performance and are subject to numerous assumptions,
uncertainties and risks that are difficult to predict. Therefore, actual
outcomes and results may be materially different from the results stated or
implied in such forward-looking statements included in this report.

The following are among the important factors that could cause future results to
differ materially from any projected, forecasted, estimated or budgeted amounts
we have discussed in this report:

• overall demand for refined products, crude oil, liquefied petroleum gases

and ammonia in the U.S.;

• price fluctuations for refined products, crude oil, liquefied petroleum

gases and ammonia and expectations about future prices for these products;

• changes in the production of crude oil in the basins served by our pipelines;

• changes in general economic conditions, interest rates and price levels;

• changes in the financial condition of our customers, vendors, derivatives

       counterparties, lenders or joint venture co-owners;


•      our ability to secure financing in the credit and capital markets in

amounts and on terms that will allow us to execute our growth strategy,

       refinance our existing obligations when due and maintain adequate
       liquidity;

• development of alternative energy sources, including but not limited to

natural gas, solar power, wind power and geothermal energy, increased use

       of biofuels such as ethanol and biodiesel, increased conservation or fuel
       efficiency, as well as regulatory developments or other trends that could
       affect demand for our services;

• changes in the throughput or interruption in service of refined products

or crude oil pipelines owned and operated by third parties and connected

to our assets;

• changes in demand for storage in our refined products, crude oil or marine

       terminals;


•      changes in supply and demand patterns for our facilities due to

geopolitical events, the activities of the Organization of the Petroleum

Exporting Countries, changes in U.S. trade policies or in laws governing

the importing and exporting of petroleum products, technological

developments or other factors;

• our ability to manage interest rate and commodity price exposures;

• changes in our tariff rates implemented by the Federal Energy Regulatory

Commission, the U.S. Surface Transportation Board or state regulatory

agencies;

• shut-downs or cutbacks at refineries, oil wells, petrochemical plants,

ammonia production facilities or other customers or businesses that use or

supply our services;

• the effect of weather patterns and other natural phenomena, including

climate change, on our operations and demand for our services;

• an increase in the competition our operations encounter;

• the occurrence of natural disasters, terrorism, operational hazards,

       equipment failures, system failures or unforeseen interruptions;


•      our ability to obtain adequate levels of insurance at a reasonable cost,
       and the potential for losses to exceed the insurance coverage we do
       obtain;


•      the treatment of us as a corporation for federal or state income tax

purposes or if we become subject to significant forms of other taxation or

       more aggressive enforcement or increased assessments under existing forms
       of taxation;

• our ability to identify expansion projects or to complete identified

       expansion projects on time and at projected costs;


•      our ability to make and integrate accretive acquisitions and joint
       ventures and successfully execute our business strategy;



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• uncertainty of estimates, including accruals and costs of environmental

remediation;

• our ability to cooperate with and rely on our joint venture co-owners;

• actions by rating agencies concerning our credit ratings;


•      our ability to timely obtain and maintain all necessary approvals,
       consents and permits required to operate our existing assets and to
       construct, acquire and operate any new or modified assets;

• our ability to promptly obtain all necessary services, materials, labor,

       supplies and rights-of-way required for construction of our growth
       projects, and to complete construction without significant delays,
       disputes or cost overruns;


•      risks inherent in the use and security of information systems in our
       business and implementation of new software and hardware;

• changes in laws and regulations that govern product quality specifications

or renewable fuel obligations that could impact our ability to produce

       gasoline volumes through our butane blending activities or that could
       require significant capital outlays for compliance;

• changes in laws and regulations to which we or our customers are or could

become subject, including tax withholding requirements, safety, security,

       employment, hydraulic fracturing, derivatives transactions, trade and
       environmental laws and regulations, including laws and regulations
       designed to address climate change;

• the cost and effects of legal and administrative claims and proceedings

against us or our subsidiaries;

• the amount of our indebtedness, which could make us vulnerable to general

adverse economic and industry conditions, limit our ability to borrow

       additional funds, place us at competitive disadvantages compared to our
       competitors that have less debt or have other adverse consequences;

• the effect of changes in accounting policies;

• the potential that our internal controls may not be adequate, weaknesses

may be discovered or remediation of any identified weaknesses may not be

successful;

• the ability and intent of our customers, vendors, lenders, joint venture

co-owners or other third parties to perform on their contractual

obligations to us;

• petroleum product supply disruptions;

• global and domestic repercussions from terrorist activities, including

cyber attacks, and the government's response thereto; and

• other factors and uncertainties inherent in the transportation, storage

and distribution of petroleum products and ammonia, and the operation,

acquisition and construction of assets related to such activities.




This list of important factors is not exclusive. We undertake no obligation to
publicly update or revise any forward-looking statement, whether as a result of
new information, future events, changes in assumptions or otherwise.



                                       66

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