x
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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Commission file number 1-16335
|
Delaware
|
|
73-1599053
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(State or other jurisdiction of
incorporation or organization)
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|
(I.R.S. Employer
Identification No.)
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Magellan GP, LLC
P.O. Box 22186, Tulsa, Oklahoma
|
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74121-2186
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(Address of principal executive offices)
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(Zip Code)
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Title of Each Class
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Name of Each Exchange on
Which Registered
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Common Units representing limited
partnership interests
|
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New York Stock Exchange
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Page
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PART I
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ITEM 1.
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ITEM 1A.
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ITEM 1B.
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ITEM 2.
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ITEM 3.
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ITEM 4.
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PART II
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ITEM 5.
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ITEM 6.
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ITEM 7.
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ITEM 7A.
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ITEM 8.
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ITEM 9.
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ITEM 9A.
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ITEM 9B.
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PART III
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ITEM 10.
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ITEM 11.
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ITEM 12.
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ITEM 13.
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ITEM 14.
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PART IV
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ITEM 15.
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•
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our refined products segment, including our 9,500-mile refined products pipeline system with 53 terminals as well as 27 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;
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•
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our crude oil segment, comprised of approximately 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million barrels, of which 12 million is used for leased storage; and
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•
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our marine storage segment, consisting of marine terminals located along coastal waterways with an aggregate storage capacity of approximately 27 million barrels.
|
•
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refined products,
which are the output from refineries and are primarily used as fuels by consumers. Refined products include gasoline, diesel fuel, aviation fuel, kerosene and heating oil. Collectively, diesel fuel and heating oil are referred to as distillates;
|
•
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liquefied petroleum gases, or LPGs,
which are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;
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•
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blendstocks,
which are blended with refined products to change or enhance their characteristics such as increasing a gasoline’s octane or oxygen content. Blendstocks include alkylates, oxygenates and natural gasoline;
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•
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heavy oils and feedstocks,
which are used as burner fuels or feedstocks for further processing by refineries and petrochemical facilities. Heavy oils and feedstocks include No. 6 fuel oil and vacuum gas oil;
|
•
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crude oil and condensate,
which are used as feedstocks by refineries and petrochemical facilities;
|
•
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biofuels,
such as ethanol and biodiesel, which are increasingly required by government mandates; and
|
•
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ammonia
, which is primarily used as a nitrogen fertilizer.
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Year Ended December 31,
|
||||
|
|
2011
|
|
2012
|
|
2013
|
Percent of consolidated revenue
|
|
87%
|
|
86%
|
|
81%
|
Percent of consolidated operating margin
|
|
77%
|
|
75%
|
|
71%
|
Percent of consolidated total assets
|
|
68%
|
|
57%
|
|
58%
|
|
|
Year Ended December 31,
|
|||||||
|
|
2011
|
|
2012
|
|
2013
|
|||
Shipments (thousand barrels):
|
|
|
|
|
|
|
|||
Refined products:
|
|
|
|
|
|
|
|||
Gasoline
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208,852
|
|
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223,692
|
|
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239,676
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Distillates
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136,003
|
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136,709
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146,493
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Aviation fuel
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25,245
|
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21,557
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21,117
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LPGs
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4,927
|
|
|
8,475
|
|
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7,827
|
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Total shipments
|
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375,027
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|
|
390,433
|
|
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415,113
|
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Company
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Refinery Location
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Calumet Specialty Products
|
|
Superior, WI
|
CVR Energy
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Coffeyville, KS
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CVR Energy
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Wynnewood, OK
|
Flint Hills Resources
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Rosemount, MN
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HollyFrontier
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El Dorado, KS
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HollyFrontier
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Tulsa, OK
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HollyFrontier
|
|
Cheyenne, WY
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Marathon
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Galveston Bay, TX
|
Marathon
|
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Texas City, TX
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National Cooperative Refining Association
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McPherson, KS
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Northern Tier
|
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St. Paul, MN
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Phillips 66
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Ponca City, OK
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Sinclair
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Evansville, WY
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Suncor Energy
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Commerce City, CO
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Valero
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Ardmore, OK
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Valero
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Houston, TX
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Valero
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Texas City, TX
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Western Refining
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El Paso, TX
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Wyoming Refining
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Newcastle, WY
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Pipeline/Terminal
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Connection Location
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Source of Product
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BP
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Manhattan, IL
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Whiting, IN refinery
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CHS
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Fargo, ND
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Laurel, MT refinery
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Explorer
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Glenpool, OK; Mt. Vernon, MO; Dallas, TX; East Houston, TX; Greenville, TX
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Various Gulf Coast refineries
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Holly Energy Partners
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Duncan, OK; El Paso, TX
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Big Spring, TX refinery, Artesia, NM refinery
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Kinder Morgan
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Galena Park and Pasadena, TX
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Various Gulf Coast refineries and imports
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Magellan Terminals Holdings
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Galena Park, TX
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Various Gulf Coast refineries and imports
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Mid-America (Enterprise)
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El Dorado, KS
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Conway, KS storage
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NuStar Energy
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El Dorado, KS; Minneapolis, MN; Denver, CO
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Various OK & KS refineries, Mandan, ND refinery, McKee, TX refinery
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ONEOK Partners
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Plattsburg, MO; Des Moines, IA; Wayne, IL
|
|
Bushton, KS storage and Chicago, IL area refineries
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Phillips 66
|
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Kansas City, KS; Denver, CO; Casper, WY
|
|
Borger, TX refinery, various Billings, MT area refineries
|
Shell
|
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East Houston, TX
|
|
Deer Park, TX refinery
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West Shore
|
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Chicago, IL
|
|
Various Chicago, IL area refineries
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|
|
Year Ended December 31,
|
||||
|
|
2011
|
|
2012
|
|
2013
|
Percent of consolidated revenue
|
|
4%
|
|
5%
|
|
10%
|
Percent of consolidated operating margin
|
|
10%
|
|
12%
|
|
18%
|
Percent of consolidated total assets
|
|
11%
|
|
20%
|
|
26%
|
|
|
Year Ended December 31,
|
||||
|
|
2011
|
|
2012
|
|
2013
|
Percent of consolidated revenue
|
|
9%
|
|
9%
|
|
9%
|
Percent of consolidated operating margin
|
|
13%
|
|
13%
|
|
11%
|
Percent of consolidated total assets
|
|
16%
|
|
15%
|
|
13%
|
•
|
an increase in the market prices of petroleum products, which may reduce demand. Market prices for petroleum products are subject to wide fluctuations in response to changes in global and regional supply and demand over which we have no control;
|
•
|
higher fuel taxes or other governmental or regulatory actions that increase the cost of the products we handle;
|
•
|
an increase in transportation fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles, technological advances by manufacturers or federal or state regulations. For example, in August 2012 the National Highway Traffic Safety Administration and the EPA finalized standards for passenger cars and light trucks manufactured in model years beginning in 2017 that will require significant increases in fuel efficiency. The proposed standards are intended to reduce demand for petroleum products, and if implemented these and any similar standards could reduce demand for our services; and
|
•
|
an increase in the use of alternative fuel sources, such as ethanol, biodiesel, natural gas, fuel cells, solar, electric and battery-powered engines. Current laws require a significant increase in the quantity of ethanol and biodiesel used in transportation fuels between now and 2022. Increases in domestic natural gas production have resulted in lower U.S. natural gas prices, which in turn has led to the promotion by the natural gas industry and some politicians of natural gas as an alternative fuel. Increases in the use of such alternative fuels could have a material impact on the volume of petroleum-based fuels transported on our pipelines or distributed through our terminals.
|
•
|
We were conducting business in a state but had not complied with that particular state's partnership statute; or
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•
|
Your rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.
|
•
|
provides that whenever our general partner is permitted or required to make a decision, in its capacity as our general partner, our general partner is permitted or required to make such a decision in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission if our general partner or its officers and directors, as the case may be, acted in good faith; and
|
•
|
provides that, in the absence of bad faith, our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
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Item 1B.
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Unresolved Staff Comments
|
Item 2.
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Properties
|
Item 3.
|
Legal Proceedings
|
Item 4.
|
Mine Safety Disclosures
|
Item 5.
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Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
|
2012
|
|
2013
|
||||||||||||||||||||
Quarter
|
|
High
|
|
Low
|
|
Distribution*
|
|
High
|
|
Low
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|
Distribution*
|
||||||||||||
1
st
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|
$
|
36.87
|
|
|
$
|
32.17
|
|
|
$
|
0.42000
|
|
|
$
|
53.91
|
|
|
$
|
44.00
|
|
|
$
|
0.50750
|
|
2
nd
|
|
$
|
36.46
|
|
|
$
|
33.31
|
|
|
$
|
0.47125
|
|
|
$
|
56.29
|
|
|
$
|
48.90
|
|
|
$
|
0.53250
|
|
3
rd
|
|
$
|
44.25
|
|
|
$
|
35.08
|
|
|
$
|
0.48500
|
|
|
$
|
57.18
|
|
|
$
|
51.93
|
|
|
$
|
0.55750
|
|
4
th
|
|
$
|
45.58
|
|
|
$
|
39.06
|
|
|
$
|
0.50000
|
|
|
$
|
63.86
|
|
|
$
|
55.30
|
|
|
$
|
0.58500
|
|
*
|
Represents declared distributions associated with each respective quarter. Distributions were declared and paid within 45 days following the close of each quarter.
|
|
|
12/31/2008
|
|
|
12/31/2009
|
|
|
12/31/2010
|
|
|
12/31/2011
|
|
|
12/31/2012
|
|
|
12/31/2013
|
|
||||||
Magellan Midstream Partners, L.P.
|
|
$
|
100
|
|
|
$
|
155
|
|
|
$
|
215
|
|
|
$
|
276
|
|
|
$
|
362
|
|
|
$
|
551
|
|
Alerian MLP Index
|
|
$
|
100
|
|
|
$
|
176
|
|
|
$
|
240
|
|
|
$
|
273
|
|
|
$
|
286
|
|
|
$
|
365
|
|
S&P 500
|
|
$
|
100
|
|
|
$
|
126
|
|
|
$
|
145
|
|
|
$
|
148
|
|
|
$
|
172
|
|
|
$
|
228
|
|
Item 6.
|
Selected Financial Data
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
||||||||||
|
|
(in thousands, except per unit amounts)
|
||||||||||||||||||
Income Statement Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Transportation and terminals revenue
|
|
$
|
678,945
|
|
|
$
|
793,599
|
|
|
$
|
893,369
|
|
|
$
|
970,744
|
|
|
$
|
1,138,328
|
|
Product sales revenue
|
|
334,465
|
|
|
763,090
|
|
|
854,528
|
|
|
799,382
|
|
|
744,669
|
|
|||||
Affiliate management fee revenue
|
|
761
|
|
|
758
|
|
|
770
|
|
|
1,948
|
|
|
14,609
|
|
|||||
Total revenue
|
|
1,014,171
|
|
|
1,557,447
|
|
|
1,748,667
|
|
|
1,772,074
|
|
|
1,897,606
|
|
|||||
Operating expenses
|
|
257,635
|
|
|
282,212
|
|
|
306,415
|
|
|
328,454
|
|
|
346,070
|
|
|||||
Cost of product sales
|
|
280,291
|
|
|
668,585
|
|
|
706,270
|
|
|
657,108
|
|
|
578,029
|
|
|||||
Earnings of non-controlled entities
|
|
(3,431
|
)
|
|
(5,732
|
)
|
|
(6,763
|
)
|
|
(2,961
|
)
|
|
(6,275
|
)
|
|||||
Operating margin
|
|
479,676
|
|
|
612,382
|
|
|
742,745
|
|
|
789,473
|
|
|
979,782
|
|
|||||
Depreciation and amortization expense
|
|
97,216
|
|
|
108,668
|
|
|
121,179
|
|
|
128,012
|
|
|
142,230
|
|
|||||
G&A expense
|
|
84,049
|
|
|
95,316
|
|
|
98,669
|
|
|
109,403
|
|
|
132,496
|
|
|||||
Operating profit
|
|
298,411
|
|
|
408,398
|
|
|
522,897
|
|
|
552,058
|
|
|
705,056
|
|
|||||
Interest expense, net
|
|
69,187
|
|
|
93,296
|
|
|
105,634
|
|
|
111,679
|
|
|
115,782
|
|
|||||
Debt placement fee amortization
|
|
1,112
|
|
|
1,401
|
|
|
1,831
|
|
|
2,087
|
|
|
2,424
|
|
|||||
Other (income) expense, net
|
|
(24
|
)
|
|
750
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Income before provision for income taxes
|
|
228,136
|
|
|
312,951
|
|
|
415,432
|
|
|
438,292
|
|
|
586,850
|
|
|||||
Provision for income taxes
|
|
1,661
|
|
|
1,371
|
|
|
1,866
|
|
|
2,622
|
|
|
4,613
|
|
|||||
Net income
|
|
$
|
226,475
|
|
|
$
|
311,580
|
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income allocation:
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Limited partner interests
|
|
$
|
126,746
|
|
|
$
|
311,977
|
|
|
$
|
413,629
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Non-controlling owners' interest
|
|
99,729
|
|
|
(397
|
)
|
|
(63
|
)
|
|
—
|
|
|
—
|
|
|||||
Net income
|
|
$
|
226,475
|
|
|
$
|
311,580
|
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Basic net income per limited partner unit
|
|
$
|
1.11
|
|
|
$
|
1.42
|
|
|
$
|
1.83
|
|
|
$
|
1.92
|
|
|
$
|
2.57
|
|
Diluted net income per limited partner unit
|
|
$
|
1.11
|
|
|
$
|
1.42
|
|
|
$
|
1.83
|
|
|
$
|
1.92
|
|
|
$
|
2.56
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Working capital (deficit)
(b)
|
|
$
|
94,571
|
|
|
$
|
109,536
|
|
|
$
|
301,135
|
|
|
$
|
307,658
|
|
|
$
|
(241,543
|
)
|
Total assets
|
|
$
|
3,163,148
|
|
|
$
|
3,717,900
|
|
|
$
|
4,045,001
|
|
|
$
|
4,420,067
|
|
|
$
|
4,820,812
|
|
Long-term debt (excluding current portion)
|
|
$
|
1,680,004
|
|
|
$
|
1,906,148
|
|
|
$
|
2,151,775
|
|
|
$
|
2,393,408
|
|
|
$
|
2,435,316
|
|
Owners’ equity
|
|
$
|
1,196,354
|
|
|
$
|
1,469,571
|
|
|
$
|
1,463,403
|
|
|
$
|
1,515,702
|
|
|
$
|
1,647,442
|
|
Cash Distribution Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash distributions declared per MMP unit
(c)
|
|
$
|
1.42
|
|
|
$
|
1.48
|
|
|
$
|
1.59
|
|
|
$
|
1.88
|
|
|
$
|
2.18
|
|
Cash distributions paid per MMP unit
(c)
|
|
$
|
1.42
|
|
|
$
|
1.45
|
|
|
$
|
1.56
|
|
|
$
|
1.78
|
|
|
$
|
2.10
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
||||||||||
|
|
(in thousands, except operating statistics)
|
||||||||||||||||||
Other Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating margin:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Refined products
|
|
$
|
388,083
|
|
|
$
|
491,290
|
|
|
$
|
574,030
|
|
|
$
|
592,828
|
|
|
$
|
693,985
|
|
Crude oil
|
|
8,492
|
|
|
28,517
|
|
|
74,225
|
|
|
91,367
|
|
|
176,420
|
|
|||||
Marine storage
|
|
79,262
|
|
|
89,566
|
|
|
91,571
|
|
|
102,323
|
|
|
106,198
|
|
|||||
Allocated partnership depreciation costs
(d)
|
|
3,839
|
|
|
3,009
|
|
|
2,919
|
|
|
2,955
|
|
|
3,179
|
|
|||||
Operating margin
|
|
$
|
479,676
|
|
|
$
|
612,382
|
|
|
$
|
742,745
|
|
|
$
|
789,473
|
|
|
$
|
979,782
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted EBITDA and distributable cash flow:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income
|
|
$
|
226,475
|
|
|
$
|
311,580
|
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Interest expense, net
|
|
69,187
|
|
|
93,296
|
|
|
105,634
|
|
|
111,679
|
|
|
115,782
|
|
|||||
Depreciation and amortization expense
(e)
|
|
98,328
|
|
|
110,069
|
|
|
123,010
|
|
|
130,099
|
|
|
144,654
|
|
|||||
Equity-based incentive compensation expense
(f)
|
|
6,123
|
|
|
15,499
|
|
|
10,243
|
|
|
8,038
|
|
|
11,823
|
|
|||||
Asset retirements and impairments
|
|
5,529
|
|
|
1,062
|
|
|
8,599
|
|
|
12,622
|
|
|
7,835
|
|
|||||
Commodity-related adjustments
(g)
|
|
24,262
|
|
|
7,751
|
|
|
(22,370
|
)
|
|
12,894
|
|
|
(339
|
)
|
|||||
Other
(h)
|
|
5,685
|
|
|
(1,582
|
)
|
|
(2,504
|
)
|
|
4,850
|
|
|
(409
|
)
|
|||||
Adjusted EBITDA
|
|
435,589
|
|
|
537,675
|
|
|
636,178
|
|
|
715,852
|
|
|
861,583
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, net
|
|
(69,187
|
)
|
|
(93,296
|
)
|
|
(105,634
|
)
|
|
(111,679
|
)
|
|
(115,782
|
)
|
|||||
Maintenance capital (net of reimbursements)
|
|
(37,999
|
)
|
|
(44,620
|
)
|
|
(70,002
|
)
|
|
(64,396
|
)
|
|
(76,081
|
)
|
|||||
Distributable cash flow
|
|
$
|
328,403
|
|
|
$
|
399,759
|
|
|
$
|
460,542
|
|
|
$
|
539,777
|
|
|
$
|
669,720
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating Statistics:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Refined products:
(i)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Transportation revenue per barrel shipped
|
|
$
|
1.205
|
|
|
$
|
1.197
|
|
|
$
|
1.175
|
|
|
$
|
1.230
|
|
|
$
|
1.313
|
|
Volume shipped (million barrels):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gasoline
|
|
169.9
|
|
|
194.3
|
|
|
208.9
|
|
|
223.7
|
|
|
239.7
|
|
|||||
Distillates
|
|
100.2
|
|
|
122.9
|
|
|
136.0
|
|
|
136.7
|
|
|
146.5
|
|
|||||
Aviation fuel
|
|
19.9
|
|
|
22.6
|
|
|
25.3
|
|
|
21.5
|
|
|
21.1
|
|
|||||
Liquefied petroleum gases
|
|
5.7
|
|
|
5.0
|
|
|
4.9
|
|
|
8.5
|
|
|
7.8
|
|
|||||
Total volume shipped
|
|
295.7
|
|
|
344.8
|
|
|
375.1
|
|
|
390.4
|
|
|
415.1
|
|
|||||
Crude oil:
(i)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Transportation revenue per barrel shipped
|
|
$
|
—
|
|
|
$
|
0.283
|
|
|
$
|
0.275
|
|
|
$
|
0.305
|
|
|
$
|
0.880
|
|
Volume shipped (million barrels)
|
|
—
|
|
|
14.7
|
|
|
43.2
|
|
|
72.0
|
|
|
113.2
|
|
|||||
Crude oil terminal average utilization (million barrels per month)
|
|
1.2
|
|
|
3.4
|
|
|
9.3
|
|
|
12.6
|
|
|
12.3
|
|
|||||
Marine storage:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Marine terminal average utilization (million barrels per month)
|
|
23.4
|
|
|
24.0
|
|
|
24.7
|
|
|
23.8
|
|
|
23.0
|
|
(a)
|
In September 2009, we simplified our capital structure wherein our general partner became our wholly-owned subsidiary, our requirement to pay incentive distribution rights was eliminated and we acquired all of the non-controlling owners' interests that existed at that time. Following the simplification, all of our net income was allocated to our limited partners until the formation of Magellan Crude Oil, LLC ("MCO") in 2010, which was partially owned by a private investment group. In February 2011, we acquired all of the non-controlling owners' interest in MCO.
|
(b)
|
Working capital deficit at December 31, 2013 included the current portion of long-term debt of approximately $250 million consisting of our 6.45% notes due 2014. We intend to refinance these notes with long-term debt prior to their maturity date in June 2014.
|
(c)
|
Cash distributions declared represent distributions declared associated with each calendar year. Distributions were declared and paid within 45 days following the close of each quarter. Cash distributions paid represent cash payments for distributions during each of the periods presented.
|
(d)
|
Certain depreciation expense was allocated to our various business segments, which in turn recognized these allocated costs as operating expense, reducing segment operating margin by these amounts.
|
(e)
|
Includes debt placement fee amortization.
|
(f)
|
Excludes the tax withholdings on settlement of these equity-based incentive awards, which were paid in cash.
|
(g)
|
See
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
—
Distributable Cash Flow
for a description of items included in our commodity-related adjustments.
|
(h)
|
Other primarily includes adjustments for earnings of non-controlled entities and distributions. In 2010 and 2011, other included non-controlling owners' interests losses included in net income, and in 2009, other also included expense credited to a former affiliate.
|
(i)
|
We acquired certain crude oil and refined products pipelines in South Texas during September 2010. Other than our equity interest in Osage Pipe Line Company, LLC (which is excluded from our operating statistics), we had no crude oil pipeline operations prior to that date. Until the completion of our Longhorn crude oil pipeline reversal project in 2013, all of the volumes on our crude oil pipelines traveled short distances, and we charged a significantly lower tariff rate for such shipments than for the rest of our pipeline systems.
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
our refined products segment, including our 9,500-mile refined products pipeline system with 53 terminals as well as 27 independent terminals not connected to our pipeline system and our 1,100-mile ammonia pipeline system;
|
•
|
our crude oil segment, comprised of approximately 1,100 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 18 million barrels, of which 12 million is used for leased storage; and
|
•
|
our marine storage segment, consisting of marine terminals located along coastal waterways with an aggregate storage capacity of approximately 27 million barrels.
|
•
|
a 50% interest in
Osage Pipe Line Company LLC (“Osage”)
, which owns a 135-mile pipeline that transports crude oil from Cushing, Oklahoma to refineries in El Dorado, Kansas;
|
•
|
a 50% interest in
Double Eagle Pipeline LLC (“Double Eagle”)
, which transports condensate from the Eagle Ford shale formation in South Texas via a 195-mile pipeline to our terminal in Corpus Christi. Double Eagle is operated by an affiliate of the other member of Double Eagle; and
|
•
|
a 50% interest in
BridgeTex
, which is constructing 450 miles of pipeline and related infrastructure to transport crude oil from Colorado City, Texas for delivery to the Houston-area refineries. This pipeline is expected to begin service in mid-2014.
|
|
|
Year Ended December 31,
|
|
Variance
Favorable (Unfavorable)
|
|||||||||||
|
|
2012
|
|
2013
|
|
$ Change
|
|
% Change
|
|||||||
Financial Highlights ($ in millions, except operating statistics)
|
|
|
|
|
|
|
|
|
|||||||
Transportation and terminals revenue:
|
|
|
|
|
|
|
|
|
|||||||
Refined products
|
|
$
|
723.8
|
|
|
$
|
801.1
|
|
|
$
|
77.3
|
|
|
11
|
%
|
Crude oil
|
|
92.3
|
|
|
178.4
|
|
|
86.1
|
|
|
93
|
%
|
|||
Marine storage
|
|
154.6
|
|
|
158.8
|
|
|
4.2
|
|
|
3
|
%
|
|||
Total transportation and terminals revenue
|
|
970.7
|
|
|
1,138.3
|
|
|
167.6
|
|
|
17
|
%
|
|||
Affiliate management fee revenue
|
|
2.0
|
|
|
14.6
|
|
|
12.6
|
|
|
630
|
%
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|
|||||||
Refined products
|
|
267.7
|
|
|
270.7
|
|
|
(3.0
|
)
|
|
(1
|
)%
|
|||
Crude oil
|
|
5.2
|
|
|
19.1
|
|
|
(13.9
|
)
|
|
(267
|
)%
|
|||
Marine storage
|
|
58.5
|
|
|
59.4
|
|
|
(0.9
|
)
|
|
(2
|
)%
|
|||
Intersegment eliminations
|
|
(2.9
|
)
|
|
(3.1
|
)
|
|
0.2
|
|
|
7
|
%
|
|||
Total operating expenses
|
|
328.5
|
|
|
346.1
|
|
|
(17.6
|
)
|
|
(5
|
)%
|
|||
Product margin:
|
|
|
|
|
|
|
|
|
|||||||
Product sales
|
|
799.4
|
|
|
744.7
|
|
|
(54.7
|
)
|
|
(7
|
)%
|
|||
Cost of product sales
|
|
657.1
|
|
|
578.0
|
|
|
79.1
|
|
|
12
|
%
|
|||
Product margin
(a)
|
|
142.3
|
|
|
166.7
|
|
|
24.4
|
|
|
17
|
%
|
|||
Earnings of non-controlled entities
|
|
3.0
|
|
|
6.3
|
|
|
3.3
|
|
|
110
|
%
|
|||
Operating margin
|
|
789.5
|
|
|
979.8
|
|
|
190.3
|
|
|
24
|
%
|
|||
Depreciation and amortization expense
|
|
128.0
|
|
|
142.2
|
|
|
(14.2
|
)
|
|
(11
|
)%
|
|||
G&A expense
|
|
109.4
|
|
|
132.6
|
|
|
(23.2
|
)
|
|
(21
|
)%
|
|||
Operating profit
|
|
552.1
|
|
|
705.0
|
|
|
152.9
|
|
|
28
|
%
|
|||
Interest expense (net of interest income and interest capitalized)
|
|
111.7
|
|
|
115.8
|
|
|
(4.1
|
)
|
|
(4
|
)%
|
|||
Debt placement fee amortization
|
|
2.1
|
|
|
2.4
|
|
|
(0.3
|
)
|
|
(14
|
)%
|
|||
Income before provision for income taxes
|
|
438.3
|
|
|
586.8
|
|
|
148.5
|
|
|
34
|
%
|
|||
Provision for income taxes
|
|
2.6
|
|
|
4.6
|
|
|
(2.0
|
)
|
|
(77
|
)%
|
|||
Net income
|
|
$
|
435.7
|
|
|
$
|
582.2
|
|
|
$
|
146.5
|
|
|
34
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Operating Statistics
|
|
|
|
|
|
|
|
|
|||||||
Refined products:
|
|
|
|
|
|
|
|
|
|||||||
Transportation revenue per barrel shipped
|
|
$
|
1.230
|
|
|
$
|
1.313
|
|
|
|
|
|
|||
Volume shipped (million barrels):
|
|
|
|
|
|
|
|
|
|||||||
Gasoline
|
|
223.7
|
|
|
239.7
|
|
|
|
|
|
|||||
Distillates
|
|
136.7
|
|
|
146.5
|
|
|
|
|
|
|||||
Aviation fuel
|
|
21.5
|
|
|
21.1
|
|
|
|
|
|
|||||
Liquefied petroleum gases
|
|
8.5
|
|
|
7.8
|
|
|
|
|
|
|||||
Total volume shipped
|
|
390.4
|
|
|
415.1
|
|
|
|
|
|
|||||
Crude oil:
|
|
|
|
|
|
|
|
|
|||||||
Transportation revenue per barrel shipped
|
|
$
|
0.305
|
|
|
$
|
0.880
|
|
|
|
|
|
|||
Volumes shipped (million barrels)
|
|
72.0
|
|
|
113.2
|
|
|
|
|
|
|||||
Crude oil terminal average utilization (million barrels per month)
|
|
12.6
|
|
|
12.3
|
|
|
|
|
|
|||||
Marine storage:
|
|
|
|
|
|
|
|
|
|||||||
Marine terminal average utilization (million barrels per month)
|
|
23.8
|
|
|
23.0
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
(a)
|
Product margin does not include depreciation or amortization expense.
|
•
|
an increase in refined products revenue of
$77.3
million. Excluding the pipeline systems we acquired in 2013, refined products revenue increased $65.3 million primarily due to a 3% increase in transportation volumes and higher rates. Shipments were higher primarily due to increased demand for gasoline and distillates. The average rate per barrel increased due to the mid-year 2012 and 2013 tariff rate increases of 8.6% and 4.6%, respectively;
|
•
|
an increase in crude oil revenue of
$86.1
million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately 85% of the increase. Our Longhorn pipeline began delivering crude oil in 2013 and averaged approximately 125,000 barrels per day since its mid-April start date. We also benefited from higher utilization on our Houston-area crude oil distribution system and additional condensate throughput at our Corpus Christi terminal; and
|
•
|
an increase in marine storage revenue of
$4.2
million primarily due to new storage placed into service at our Galena Park, Texas terminal since late 2012 and higher throughput fees, partially offset by lower utilization mainly due to additional integrity work during the 2013 period.
|
•
|
an increase in refined products expenses of
$3.0
million primarily due to higher asset integrity costs, compensation, power costs and property taxes, as well as $5.1 million of expenses related to operation of the pipeline systems we acquired in 2013, partially offset by higher product overages (which reduce operating expenses), lower losses on asset retirements, the 2013 favorable adjustment of an accrual for air emission fees at our East Houston terminal (see Notes to Consolidated Financial Statements, Note 17–
Commitments and Contingencies
for more information regarding the adjustment of this accrual) and lower environmental accruals. The higher compensation costs were due to increased employee headcount and higher bonus accruals. The higher power costs primarily reflect the increase in product shipments over 2012 and the higher property taxes are the result of asset additions and improved profitability over the past year;
|
•
|
an increase in crude oil expenses of
$13.9
million primarily due to costs related to the operation of our Longhorn pipeline in crude oil service in 2013, including pipeline rental costs to access product from third-party origination sources, higher personnel costs, power and integrity spending, partially offset by more favorable product overages (which reduce operating expenses); and
|
•
|
an increase in marine storage expenses of
$0.9
million primarily due to higher asset integrity costs in the current year resulting from additional tank work, higher insurance costs and higher property taxes, partially offset by the 2013 favorable adjustment of an accrual for potential air emission fees at our Galena Park facility (see Notes to Consolidated Financial Statements, Note 17–
Commitments and Contingencies
for more information regarding the adjustment of this accrual) and lower environmental accruals.
|
|
|
Year Ended December 31,
|
|
Variance
Favorable (Unfavorable)
|
|||||||||||
|
|
2011
|
|
2012
|
|
$ Change
|
|
% Change
|
|||||||
Financial Highlights ($ in millions, except operating statistics)
|
|
|
|
|
|
|
|
|
|||||||
Transportation and terminals revenue:
|
|
|
|
|
|
|
|
|
|||||||
Refined products
|
|
$
|
680.3
|
|
|
$
|
723.8
|
|
|
$
|
43.5
|
|
|
6
|
%
|
Crude oil
|
|
61.2
|
|
|
92.3
|
|
|
31.1
|
|
|
51
|
%
|
|||
Marine storage
|
|
151.9
|
|
|
154.6
|
|
|
2.7
|
|
|
2
|
%
|
|||
Total transportation and terminals revenue
|
|
893.4
|
|
|
970.7
|
|
|
77.3
|
|
|
9
|
%
|
|||
Affiliate management fee revenue
|
|
0.8
|
|
|
2.0
|
|
|
1.2
|
|
|
150
|
%
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|
|||||||
Refined products
|
|
250.8
|
|
|
267.7
|
|
|
(16.9
|
)
|
|
(7
|
)%
|
|||
Crude oil
|
|
(4.9
|
)
|
|
5.2
|
|
|
(10.1
|
)
|
|
n/a
|
|
|||
Marine storage
|
|
63.4
|
|
|
58.5
|
|
|
4.9
|
|
|
8
|
%
|
|||
Intersegment eliminations
|
|
(2.9
|
)
|
|
(2.9
|
)
|
|
—
|
|
|
—
|
|
|||
Total operating expenses
|
|
306.4
|
|
|
328.5
|
|
|
(22.1
|
)
|
|
(7
|
)%
|
|||
Product margin:
|
|
|
|
|
|
|
|
|
|||||||
Product sales
|
|
854.5
|
|
|
799.4
|
|
|
(55.1
|
)
|
|
(6
|
)%
|
|||
Cost of product sales
|
|
706.3
|
|
|
657.1
|
|
|
49.2
|
|
|
7
|
%
|
|||
Product margin
(a)
|
|
148.2
|
|
|
142.3
|
|
|
(5.9
|
)
|
|
(4
|
)%
|
|||
Earnings of non-controlled entities
|
|
6.8
|
|
|
3.0
|
|
|
(3.8
|
)
|
|
(56
|
)%
|
|||
Operating margin
|
|
742.8
|
|
|
789.5
|
|
|
46.7
|
|
|
6
|
%
|
|||
Depreciation and amortization expense
|
|
121.2
|
|
|
128.0
|
|
|
(6.8
|
)
|
|
(6
|
)%
|
|||
G&A expense
|
|
98.7
|
|
|
109.4
|
|
|
(10.7
|
)
|
|
(11
|
)%
|
|||
Operating profit
|
|
522.9
|
|
|
552.1
|
|
|
29.2
|
|
|
6
|
%
|
|||
Interest expense (net of interest income and interest capitalized)
|
|
105.6
|
|
|
111.7
|
|
|
(6.1
|
)
|
|
(6
|
)%
|
|||
Debt placement fee amortization
|
|
1.8
|
|
|
2.1
|
|
|
(0.3
|
)
|
|
(17
|
)%
|
|||
Income before provision for income taxes
|
|
415.5
|
|
|
438.3
|
|
|
22.8
|
|
|
5
|
%
|
|||
Provision for income taxes
|
|
1.9
|
|
|
2.6
|
|
|
(0.7
|
)
|
|
(37
|
)%
|
|||
Net income
|
|
$
|
413.6
|
|
|
$
|
435.7
|
|
|
$
|
22.1
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Operating Statistics
|
|
|
|
|
|
|
|
|
|||||||
Refined products:
|
|
|
|
|
|
|
|
|
|||||||
Transportation revenue per barrel shipped
|
|
$
|
1.175
|
|
|
$
|
1.230
|
|
|
|
|
|
|||
Volume shipped (million barrels):
|
|
|
|
|
|
|
|
|
|||||||
Gasoline
|
|
208.9
|
|
|
223.7
|
|
|
|
|
|
|||||
Distillates
|
|
136.0
|
|
|
136.7
|
|
|
|
|
|
|||||
Aviation fuel
|
|
25.3
|
|
|
21.5
|
|
|
|
|
|
|||||
Liquefied petroleum gases
|
|
4.9
|
|
|
8.5
|
|
|
|
|
|
|||||
Total volume shipped
|
|
375.1
|
|
|
390.4
|
|
|
|
|
|
|||||
Crude oil:
|
|
|
|
|
|
|
|
|
|||||||
Transportation revenue per barrel shipped
|
|
$
|
0.275
|
|
|
$
|
0.305
|
|
|
|
|
|
|||
Volumes shipped (million barrels)
|
|
43.2
|
|
|
72.0
|
|
|
|
|
|
|||||
Crude oil terminal average utilization (million barrels per month)
|
|
9.3
|
|
|
12.6
|
|
|
|
|
|
|||||
Marine storage:
|
|
|
|
|
|
|
|
|
|||||||
Marine terminal average utilization (million barrels per month)
|
|
24.7
|
|
|
23.8
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
(a)
|
Product margin does not include depreciation or amortization expense.
|
•
|
an increase in refined products revenue of $43.5 million resulting primarily from increases in the average per-barrel tariff rate principally reflecting the 6.9% and 8.6% tariff rate increases we implemented on July 1, 2011 and July 1, 2012, respectively, partially offset by more South Texas movements, which ship at a lower rate than our other shipments. We further benefited from higher transportation volumes between periods;
|
•
|
an increase in crude oil revenue of $31.1 million primarily due to additional revenue from leasing tanks constructed throughout 2011, including new crude oil storage at Cushing, Oklahoma, and a 67% increase in shipments on our Houston-area crude oil distribution system resulting from deliveries to additional locations that have been connected to our pipeline system and increased deliveries to existing customers; and
|
•
|
an increase in marine storage revenue of $2.7 million primarily due to increased demand at our Galena Park, Texas terminal.
|
•
|
an increase in refined products expenses of $16.9 million primarily due to an increase in property taxes, lower product overages (which reduce operating expenses), additional asset integrity work, higher personnel costs and higher losses on various asset retirements and replacements, partially offset by lower costs resulting from an accrual recognized in 2011 related to potential air emission fees with no corresponding charge in the 2012 period;
|
•
|
an increase in crude oil expenses of $10.1 million primarily due to lower product overages (which reduce operating expenses) and higher personnel and asset integrity costs; and
|
•
|
a decrease in marine storage expenses of $4.9 million primarily due to an accrual recognized in 2011 for potential air emission fees with no corresponding charge in the 2012 period, partially offset by higher losses on various asset retirements and replacements and higher operating taxes.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Net income
|
|
$
|
413.6
|
|
|
$
|
435.7
|
|
|
$
|
582.2
|
|
Interest expense, net
|
|
105.6
|
|
|
111.7
|
|
|
115.8
|
|
|||
Depreciation and amortization
(1)
|
|
123.0
|
|
|
130.1
|
|
|
144.7
|
|
|||
Equity-based incentive compensation expense
(2)
|
|
10.2
|
|
|
8.0
|
|
|
11.8
|
|
|||
Asset retirements and impairments
|
|
8.6
|
|
|
12.6
|
|
|
7.8
|
|
|||
Commodity-related adjustments:
|
|
|
|
|
|
|
||||||
Derivative losses (gains) recognized in the period associated with future product transactions
(3)
|
|
(5.9
|
)
|
|
6.4
|
|
|
8.1
|
|
|||
Derivative (losses) gains recognized in previous periods associated with product sales completed in the period
(4)
|
|
(15.2
|
)
|
|
3.7
|
|
|
(6.4
|
)
|
|||
Lower-of-cost-or-market adjustment
|
|
1.0
|
|
|
1.0
|
|
|
(2.0
|
)
|
|||
Houston-to-El Paso cost of sales adjustments
(5)
|
|
(2.3
|
)
|
|
1.8
|
|
|
—
|
|
|||
Total commodity-related adjustments
|
|
(22.4
|
)
|
|
12.9
|
|
|
(0.3
|
)
|
|||
Other
|
|
(2.5
|
)
|
|
4.9
|
|
|
(0.4
|
)
|
|||
Adjusted EBITDA
|
|
636.1
|
|
|
715.9
|
|
|
861.6
|
|
|||
Interest expense, net
|
|
(105.6
|
)
|
|
(111.7
|
)
|
|
(115.8
|
)
|
|||
Maintenance capital (net of reimbursements)
|
|
(70.0
|
)
|
|
(64.4
|
)
|
|
(76.1
|
)
|
|||
DCF
|
|
$
|
460.5
|
|
|
$
|
539.8
|
|
|
$
|
669.7
|
|
|
|
|
|
|
|
|
(1)
|
Depreciation and amortization includes debt placement fee amortization.
|
(2)
|
As we intend to satisfy vesting of units 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 December 31,
2011
,
2012
and
2013
was $17.6 million, $21.0 million and $24.1 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we paid in
2011
,
2012
and
2013
of $7.4 million, $13.0 million and $12.3 million, respectively, for equity-based incentive compensation units that vested on the previous year end, which reduce DCF.
|
(3)
|
Certain derivatives we use as economic hedges have not been designated as hedges for accounting purposes and the mark-to-market changes for the derivatives are recognized currently in earnings. These amounts represent the gains or losses from economic hedges recognized in our earnings during the period associated with products that had not yet been physically sold as of the period end date.
|
(4)
|
When we physically sell products that are economically hedged (but were not designated as hedges for accounting purposes), we include in our DCF calculations the full amount of the change in fair value of the associated derivative agreement.
|
(5)
|
Cost of sales adjustment related to commodity activities for our Houston-to-El Paso pipeline section to more closely resemble current market prices for DCF purposes rather than average inventory costing as used to determine our results of operations. As of December 31, 2012, we no longer perform this activity.
|
|
|
For the Year Ended
|
||||||||||
|
|
December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Distributable cash flow
|
|
$
|
460.5
|
|
|
$
|
539.8
|
|
|
$
|
669.7
|
|
Less: Cash reserves approved by our general partner
|
|
109.6
|
|
|
136.3
|
|
|
194.2
|
|
|||
Total cash distributions paid
|
|
$
|
350.9
|
|
|
$
|
403.5
|
|
|
$
|
475.5
|
|
•
|
The
$127.6 million
increase from
2012
to
2013
was primarily attributable to:
|
◦
|
a $160.8 million increase in net income and non-cash depreciation and amortization expense;
|
◦
|
a $13.2 million increase resulting from a $2.0 million increase in accounts payable in 2013 versus a $11.2 million decrease in accounts payable in 2012, primarily due to the timing of invoices paid to vendors and suppliers; and
|
◦
|
a $10.4 million increase resulting from a $16.8 million increase in deferred revenue in 2013 versus a $6.4 million increase in deferred revenue in 2012. The increase in 2013 was primarily due to an increase related to customers’ transportation deficiencies where our customers have the right to apply these deferrals against future product shipments and a deferral of a sale of an asset where the title had not yet passed, but the cash had been received.
|
◦
|
a $21.2 million decrease resulting from a $9.0 million decrease in accrued product purchases in 2013 versus a $12.2 million increase in accrued product purchases in 2012, primarily due to the timing of invoices paid to vendors and suppliers and lower butane prices in 2013;
|
◦
|
a $15.6 million decrease resulting from a $0.5 million increase in energy commodity derivatives contracts, net of derivatives deposits, in 2013 versus a $16.1 million increase in 2012 primarily due to the impact of changes in commodity prices on our economic hedges; and
|
◦
|
a $10.8 million decrease resulting from a $12.2 million decrease in current and noncurrent environmental liabilities in 2013 versus a $1.4 million decrease in current and noncurrent environmental liabilities in 2012, primarily due to an adjustment during 2013 of an accrual for potential air emission fees at our East Houston and Galena Park facilities (see
Environmental
below for more information regarding the adjustment of this accrual).
|
•
|
The
$67.8 million
increase from
2011
to
2012
was primarily attributable to:
|
◦
|
a $28.9 million increase in net income and non-cash depreciation and amortization expense;
|
◦
|
a $79.5 million increase primarily resulting from higher prices and volumes of inventory purchases in 2011 as compared to 2012; specifically, a $37.0 million decrease in inventory in 2012, primarily due to the sale of our Houston-to-El Paso pipeline section linefill working inventory, versus a $42.5 million increase in inventory in 2011; and
|
◦
|
a $35.9 million increase resulting from a $16.1 million increase in cash from energy commodity derivatives contracts, net of derivatives deposits in 2012, versus a $19.8 million decrease in 2011 primarily due to lower product prices and a decrease in the number of NYMEX commodity contracts during 2012.
|
◦
|
a $31.4 million decrease resulting from a $11.2 million decrease in accounts payable in 2012 versus a $20.2 million increase in accounts payable in 2011 primarily due to the timing of invoices paid to vendors and suppliers;
|
◦
|
an $18.3 million decrease resulting from a $1.4 million decrease in current and noncurrent environmental liabilities in 2012 versus a $16.9 million increase in current and noncurrent environmental liabilities in 2011 primarily due to potential air emission fees accrued in 2011 related to potential air emission fees at our East Houston and Galena Park facilities (see
Environmental
below for further details regarding this matter);
|
◦
|
a $16.7 million decrease resulting from a $10.9 million increase in trade accounts receivable and other accounts receivable in 2012 versus a $5.8 million decrease during 2011 primarily due to timing of payments from our customers; and
|
◦
|
a $14.4 million decrease due to a change in restricted cash. During first quarter 2011, we acquired the non-controlling owner's interest in one of our subsidiaries, which removed our restriction to that entity's cash. As a result of that transaction, cash from operations increased $14.4 million in 2011.
|
•
|
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 distributable cash flow; and
|
•
|
Expansion capital expenditures. These expenditures are undertaken primarily to generate incremental distributable cash flow 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 capital expenditures that increase storage or throughput volumes or develop pipeline connections to new supply sources.
|
|
|
|
|
Weighted-Average Interest Rate at December 31, 2013 (a)
|
||||||
|
|
|
|
|||||||
|
|
December 31,
|
|
|||||||
|
|
2012
|
|
2013
|
|
|||||
Revolving credit facility
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—%
|
$250.0 million of 6.45% Notes due 2014
|
|
249,905
|
|
|
249,971
|
|
|
6.3%
|
||
$250.0 million of 5.65% Notes due 2016
|
|
251,609
|
|
|
251,183
|
|
|
5.7%
|
||
$250.0 million of 6.40% Notes due 2018
|
|
261,411
|
|
|
259,346
|
|
|
5.4%
|
||
$550.0 million of 6.55% Notes due 2019
|
|
575,065
|
|
|
571,515
|
|
|
5.7%
|
||
$550.0 million of 4.25% Notes due 2021
|
|
558,088
|
|
|
557,213
|
|
|
4.0%
|
||
$250.0 million of 6.40% Notes due 2037
|
|
248,981
|
|
|
248,998
|
|
|
6.4%
|
||
$250.0 million of 4.20% Notes due 2042
|
|
248,349
|
|
|
248,377
|
|
|
4.2%
|
||
$300.0 million of 5.15% Notes due 2043
|
|
—
|
|
|
298,684
|
|
|
5.2%
|
||
Total debt
|
|
$
|
2,393,408
|
|
|
$
|
2,685,287
|
|
|
5.2%
|
|
|
|
|
|
|
|
(a)
|
Weighted-average interest rate includes the amortization/accretion of discounts and premiums and the amortization/accretion of gains and losses realized on historical cash flow and fair value hedges (see Note 13—
Derivative Financial Instruments
for detailed information regarding fair value hedges and interest rate swaps).
|
|
|
Total
|
|
< 1 year
|
|
1-3 years
|
|
3-5 years
|
|
> 5 years
|
||||||||||
Long-term debt obligations
(1)
|
|
$
|
2,650.0
|
|
|
$
|
250.0
|
|
|
$
|
250.0
|
|
|
$
|
250.0
|
|
|
$
|
1,900.0
|
|
Interest obligations
|
|
1,622.6
|
|
|
139.2
|
|
|
262.3
|
|
|
229.7
|
|
|
991.4
|
|
|||||
Operating lease obligations
|
|
130.0
|
|
|
16.2
|
|
|
32.6
|
|
|
29.7
|
|
|
51.5
|
|
|||||
Pension and postretirement medical obligations
(2)
|
|
52.2
|
|
|
20.4
|
|
|
22.5
|
|
|
1.8
|
|
|
7.5
|
|
|||||
Purchase commitments:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Product purchase commitments
|
|
126.2
|
|
|
93.7
|
|
|
32.5
|
|
|
—
|
|
|
—
|
|
|||||
Utility purchase commitments
|
|
11.8
|
|
|
6.7
|
|
|
4.7
|
|
|
0.4
|
|
|
—
|
|
|||||
Derivative instruments
(3)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Equity-based incentive awards
(4)
|
|
59.4
|
|
|
20.5
|
|
|
38.9
|
|
|
—
|
|
|
—
|
|
|||||
Environmental remediation
(5)
|
|
6.0
|
|
|
1.9
|
|
|
3.1
|
|
|
1.0
|
|
|
—
|
|
|||||
Capital project purchase obligations
|
|
71.3
|
|
|
71.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Maintenance obligations
|
|
39.4
|
|
|
39.2
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|||||
Other purchase obligations
|
|
2.5
|
|
|
1.9
|
|
|
0.5
|
|
|
0.1
|
|
|
—
|
|
|||||
Total
|
|
$
|
4,771.4
|
|
|
$
|
661.0
|
|
|
$
|
647.3
|
|
|
$
|
512.7
|
|
|
$
|
2,950.4
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
At
December 31, 2013
, 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.
|
(2)
|
Represents the projected benefit obligation of our pension and postretirement medical plans less the fair value of plan assets.
|
(3)
|
As of
December 31, 2013
, we had entered into commodity-related derivative contracts representing 2.9 million barrels of petroleum products that we expect to sell in the future and 0.1 million barrels of butane we expect to purchase in the future. At
December 31, 2013
, we had recorded a net liability of $4.5 million and made margin deposits of
$14.8 million
associated with these derivative agreements. We have excluded from this table the future net cash outflows, if any, under these derivative agreements and the amounts of future margin deposit requirements because those amounts are uncertain.
|
(4)
|
Represents the grant date fair value of unit awards accounted for as equity plus the
December 31, 2013
re-measured grant date fair value of award grants accounted for as liabilities. The total equity-based incentive awards liability is determined by multiplying the grant date per unit fair value by the number of unit award grants, multiplied by the percentage of the requisite service period completed, multiplied by the estimated payout percentage of the awards at
December 31, 2013
. Settlements of these awards will differ from these reported amounts primarily due to differences between actual and current estimates of payout percentages and forfeitures, changes in our unit price between
December 31, 2013
and the vesting dates of the awards and completion of the remaining portion of the requisite service periods.
|
(5)
|
During 2005, we entered into a 10-year agreement to reach contractual endpoint (as defined in the agreement) for 23 remediation sites. This contract obligated us to pay the remediation costs incurred by the contract counterparty associated with these 23 sites up to a maximum of $14.3 million. The amounts in the table above include the estimated remaining amounts to be paid under this agreement ($0.9 million as of
December 31, 2013
) and the estimated timing of these payments. Additionally, this agreement required us to pay the contract counterparty a performance bonus if the remediation sites are brought to contractual endpoint for less than $14.3 million. The table above includes our estimate of the performance bonus ($1.1 million as of
December 31, 2013
). During 2006, we entered into a separate 10-year agreement with an independent contractor to remediate certain of our environmental sites. This contract obligated us to pay $16.2 million over a 10-year period. The amounts in the table above include the remaining amounts to be paid under this agreement ($4.0 million as of
December 31, 2013
) and the estimated timing of those payments based on project progress to date.
|
•
|
NYMEX contracts covering 0.7 million barrels of crude oil to hedge against future price changes of crude oil linefill and tank bottom inventory. These contracts, which we are accounting for as fair value hedges, mature between January 2014 and November 2016. Through
December 31, 2013
, the cumulative amount of losses from these agreements was
$8.7 million
. The cumulative losses from these fair value hedges were recorded as adjustments to the asset being hedged, and there has been no ineffectiveness recognized for these hedges. As a result, none of these cumulative losses have impacted our consolidated income statement.
|
•
|
NYMEX contracts covering 1.9 million barrels of refined products related to our butane blending and fractionation activities. These contracts mature between January and April 2014 and are being accounted for as economic hedges. Through
December 31, 2013
, the cumulative amount of net unrealized losses associated with these agreements was $6.8 million. We recorded these losses as an adjustment to product sales revenue, all of which was recognized in 2013.
|
•
|
NYMEX contracts covering 0.3 million barrels of refined products and crude oil related to inventory we carry that resulted from pipeline product overages. These contracts, which mature in January and February 2014, are being accounted for as economic hedges. Through
December 31, 2013
, the cumulative amount of unrealized losses associated with these agreements was $0.2 million. We recorded these losses as an increase in operating expenses, all of which was recognized in 2013.
|
•
|
Butane futures agreements to purchase 0.1 million barrels of butane that mature between January and April 2014, which are being accounted for as economic hedges. Through
December 31, 2013
, the cumulative amount of unrealized gains associated with these agreements was $0.4 million. We recorded these gains as a decrease in cost of product sales, all of which was recognized in 2013.
|
•
|
We settled NYMEX contracts covering 8.2 million barrels of refined products related to economic hedges of products from our butane blending and fractionation activities that we sold during 2013. We recognized a gain of $0.6 million in 2013 related to these contracts which we recorded as an adjustment to product sales revenue.
|
•
|
We settled NYMEX contracts covering 0.2 million barrels of refined products related to cash flow hedges of products from our butane blending and fractionation activities that we sold during 2013. We recognized a loss of $4.4 million on the settlement of these contracts which we recorded as an adjustment to product sales revenue.
|
•
|
We settled NYMEX contracts covering 5.3 million barrels of refined products and crude oil related to economic hedges of product inventories from product overages on our pipeline systems which we sold during 2013. We recognized a loss of $3.6 million in 2013 on the settlement of these contracts which we recorded as an adjustment to operating expense.
|
•
|
We settled butane futures agreements covering 0.5 million barrels related to economic hedges of butane purchases we made during 2013 associated with our butane blending activities. We recognized a gain of $2.3 million in 2013 on the settlement of these contracts which we recorded as an adjustment to cost of product sales.
|
|
Year Ended December 31, 2012
|
||||||||||||||
|
Product Sales
|
|
Cost of Product Sales
|
|
Operating Expense
|
|
Net Impact on Results of Operations
|
||||||||
NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period
|
$
|
(30.5
|
)
|
|
$
|
0.1
|
|
|
$
|
0.1
|
|
|
$
|
(30.3
|
)
|
NYMEX gains from cash flow hedges that were reclassified from accumulated other comprehensive loss during the period
|
2.8
|
|
|
—
|
|
|
—
|
|
|
2.8
|
|
||||
NYMEX gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods
|
(6.5
|
)
|
|
1.1
|
|
|
(2.2
|
)
|
|
(7.6
|
)
|
||||
Net gain (loss) on NYMEX contracts
|
$
|
(34.2
|
)
|
|
$
|
1.2
|
|
|
$
|
(2.1
|
)
|
|
$
|
(35.1
|
)
|
|
Year Ended December 31, 2013
|
||||||||||||||
|
Product Sales
|
|
Cost of Product Sales
|
|
Operating Expense
|
|
Net Impact on Results of Operations
|
||||||||
NYMEX gains (losses) recognized during the period that were associated with economic hedges of physical product sales or purchases during the period
|
$
|
0.6
|
|
|
$
|
2.3
|
|
|
$
|
(3.6
|
)
|
|
$
|
(0.7
|
)
|
NYMEX losses from cash flow hedges that were reclassified from accumulated other comprehensive loss during the period
|
(4.4
|
)
|
|
—
|
|
|
—
|
|
|
(4.4
|
)
|
||||
NYMEX gains (losses) recorded during the period that were associated with products that will be or were sold or purchased in future periods
|
(6.8
|
)
|
|
0.4
|
|
|
(0.2
|
)
|
|
(6.6
|
)
|
||||
Net gain (loss) on NYMEX contracts
|
$
|
(10.6
|
)
|
|
$
|
2.7
|
|
|
$
|
(3.8
|
)
|
|
$
|
(11.7
|
)
|
Balance
|
|
2012
|
Balance
|
|
2013
|
|
Balance
|
|
||||||||||||||||||||||||||||||
12/31/11
|
|
Accruals
|
|
Expenditures
|
|
12/31/12
|
|
Accruals
|
|
Expenditures
|
|
|
12/31/13
|
|
||||||||||||||||||||||||
$
|
49.6
|
|
|
|
$
|
13.2
|
|
|
|
|
$
|
(14.5
|
)
|
|
|
|
$
|
48.3
|
|
|
|
|
$
|
(1.6
|
)
|
|
|
|
$
|
(8.2
|
)
|
|
|
|
$
|
38.5
|
|
|
|
|
Benefit Expense
|
|
Benefit Obligation
|
||||||||||||||||
|
|
One-Percentage-
|
|
One-Percentage-
|
|
One-Percentage-
|
|
One-Percentage-
|
||||||||||||
|
|
Point Increase
|
|
Point Decrease
|
|
Point Increase
|
|
Point Decrease
|
||||||||||||
Pension benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
$
|
(3,102
|
)
|
|
|
$
|
4,014
|
|
|
|
$
|
(18,030
|
)
|
|
|
$
|
22,802
|
|
|
Expected long-term rate of return on plan assets
|
|
|
(998
|
)
|
|
|
|
998
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
Rate of compensation increase
|
|
|
1,888
|
|
|
|
|
(1,888
|
)
|
|
|
|
8,014
|
|
|
|
|
(8,014
|
)
|
|
Other postretirement benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
(77
|
)
|
|
|
|
166
|
|
|
|
|
(1,115
|
)
|
|
|
|
1,364
|
|
|
Assumed health care cost trend rate
|
|
|
131
|
|
|
|
|
(53
|
)
|
|
|
|
533
|
|
|
|
|
(485
|
)
|
|
|
|
One-Percentage-Point Decrease
|
|
One-Percentage-Point Increase
|
||||
Projected return on assets
|
|
$
|
79
|
|
|
$
|
(79
|
)
|
Rate of compensation increase
|
|
$
|
(2,589
|
)
|
|
$
|
2,589
|
|
•
|
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 general economic conditions, interest rates and price levels;
|
•
|
changes in the financial condition of our customers, vendors, derivatives counterparties, joint venture co-owners or lenders;
|
•
|
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 on 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 patterns for our storage terminals due to geopolitical events;
|
•
|
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;
|
•
|
not being adequately insured or having losses that exceed our insurance coverage;
|
•
|
our ability to obtain insurance and to manage the increased cost of available insurance;
|
•
|
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;
|
•
|
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 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 blending activities or that could require significant capital outlays for compliance;
|
•
|
changes in laws and regulations to which we or our customers are or become subject, including tax withholding issues, safety, security, employment and environmental laws and regulations, including laws and regulations designed to address climate change and laws and regulations affecting hydraulic fracturing, and laws and regulations relating to derivatives transactions;
|
•
|
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 of 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 refined products and crude oil.
|
Item 7A.
|
Quantitative and Qualitative Disclosures About Market Risk
|
|
Notional Value
|
|
Barrels
|
||
Forward purchase contracts
|
$
|
122.8
|
|
|
2.0
|
Forward sale contracts
|
$
|
64.2
|
|
|
0.6
|
Item 8.
|
Financial Statements and Supplementary Data
|
|
|
By:
|
/
S
/ M
ICHAEL
N. M
EARS
|
|
Chairman of the Board, President, Chief Executive Officer and Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
|
By:
|
/
S
/ J
OHN
D. C
HANDLER
|
|
Senior Vice President and Chief Financial Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Transportation and terminals revenue
|
|
$
|
893,369
|
|
|
$
|
970,744
|
|
|
$
|
1,138,328
|
|
Product sales revenue
|
|
854,528
|
|
|
799,382
|
|
|
744,669
|
|
|||
Affiliate management fee revenue
|
|
770
|
|
|
1,948
|
|
|
14,609
|
|
|||
Total revenue
|
|
1,748,667
|
|
|
1,772,074
|
|
|
1,897,606
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Operating
|
|
306,415
|
|
|
328,454
|
|
|
346,070
|
|
|||
Cost of product sales
|
|
706,270
|
|
|
657,108
|
|
|
578,029
|
|
|||
Depreciation and amortization
|
|
121,179
|
|
|
128,012
|
|
|
142,230
|
|
|||
General and administrative
|
|
98,669
|
|
|
109,403
|
|
|
132,496
|
|
|||
Total costs and expenses
|
|
1,232,533
|
|
|
1,222,977
|
|
|
1,198,825
|
|
|||
Earnings of non-controlled entities
|
|
6,763
|
|
|
2,961
|
|
|
6,275
|
|
|||
Operating profit
|
|
522,897
|
|
|
552,058
|
|
|
705,056
|
|
|||
Interest expense
|
|
108,869
|
|
|
117,981
|
|
|
130,463
|
|
|||
Interest income
|
|
(61
|
)
|
|
(107
|
)
|
|
(342
|
)
|
|||
Interest capitalized
|
|
(3,174
|
)
|
|
(6,195
|
)
|
|
(14,339
|
)
|
|||
Debt placement fee amortization
|
|
1,831
|
|
|
2,087
|
|
|
2,424
|
|
|||
Income before provision for income taxes
|
|
415,432
|
|
|
438,292
|
|
|
586,850
|
|
|||
Provision for income taxes
|
|
1,866
|
|
|
2,622
|
|
|
4,613
|
|
|||
Net income
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
|
|
|
|
|
|
|
||||||
Allocation of net income (loss):
|
|
|
|
|
|
|
||||||
Limited partners' interest
|
|
$
|
413,629
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Non-controlling owners' interest
|
|
(63
|
)
|
|
—
|
|
|
—
|
|
|||
Net income
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
|
|
|
|
|
|
|
||||||
Basic net income per limited partner unit
|
|
$
|
1.83
|
|
|
$
|
1.92
|
|
|
$
|
2.57
|
|
|
|
|
|
|
|
|
||||||
Diluted net income per limited partner unit
|
|
$
|
1.83
|
|
|
$
|
1.92
|
|
|
$
|
2.56
|
|
|
|
|
|
|
|
|
||||||
Weighted average number of limited partner units outstanding used for basic net income per unit calculation
|
|
225,674
|
|
|
226,369
|
|
|
226,829
|
|
|||
|
|
|
|
|
|
|
||||||
Weighted average number of limited partner units outstanding used for diluted net income per unit calculation
|
|
225,974
|
|
|
226,608
|
|
|
227,094
|
|
|
Year Ended December 31,
|
||||||||||
|
2011
|
|
2012
|
|
2013
|
||||||
Net income
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Other comprehensive income:
|
|
|
|
|
|
||||||
Derivative activity:
|
|
|
|
|
|
||||||
Net gain (loss) on cash flow hedges
(1)
|
7,739
|
|
|
13,889
|
|
|
(4,744
|
)
|
|||
Reclassification of net loss (gain) on cash flow hedges to income
(1)
|
(7,903
|
)
|
|
(2,924
|
)
|
|
4,245
|
|
|||
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
|
|
|
|
|
|
||||||
Net actuarial (loss) gain
(2)
|
(37,058
|
)
|
|
(17,804
|
)
|
|
14,089
|
|
|||
Plan amendment
(2)
|
—
|
|
|
16,020
|
|
|
—
|
|
|||
Amortization of actuarial loss
(2)
|
1,591
|
|
|
4,626
|
|
|
5,369
|
|
|||
Amortization of prior service credit
(2)
|
(544
|
)
|
|
(1,664
|
)
|
|
(3,405
|
)
|
|||
Settlement cost
(2)
|
70
|
|
|
—
|
|
|
—
|
|
|||
Total other comprehensive income (loss)
|
(36,105
|
)
|
|
12,143
|
|
|
15,554
|
|
|||
Comprehensive income
|
377,461
|
|
|
447,813
|
|
|
597,791
|
|
|||
Comprehensive loss attributable to non-controlling owners’ interest in consolidated subsidiaries
|
(63
|
)
|
|
—
|
|
|
—
|
|
|||
Comprehensive income attributable to partners’ capital
|
$
|
377,524
|
|
|
$
|
447,813
|
|
|
$
|
597,791
|
|
|
|
December 31,
|
||||||
|
|
2012
|
|
2013
|
||||
ASSETS
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
328,278
|
|
|
$
|
25,235
|
|
Trade accounts receivable (less allowance for doubtful accounts of $5 and $0 at December 31, 2012 and 2013, respectively)
|
|
91,114
|
|
|
116,295
|
|
||
Other accounts receivable
|
|
12,329
|
|
|
6,462
|
|
||
Inventory
|
|
221,888
|
|
|
187,224
|
|
||
Energy commodity derivatives deposits
|
|
18,304
|
|
|
14,782
|
|
||
Other current assets
|
|
28,365
|
|
|
46,735
|
|
||
Total current assets
|
|
700,278
|
|
|
396,733
|
|
||
Property, plant and equipment
|
|
4,408,550
|
|
|
4,986,750
|
|
||
Less: accumulated depreciation
|
|
943,248
|
|
|
1,070,492
|
|
||
Net property, plant and equipment
|
|
3,465,302
|
|
|
3,916,258
|
|
||
Investments in non-controlled entities
|
|
107,356
|
|
|
360,852
|
|
||
Long-term receivables
|
|
5,135
|
|
|
2,730
|
|
||
Goodwill
|
|
53,260
|
|
|
53,260
|
|
||
Other intangibles (less accumulated amortization of $16,715 and $8,809 at December 31, 2012 and 2013, respectively)
|
|
13,274
|
|
|
7,290
|
|
||
Debt placement costs (less accumulated amortization of $7,886 and $9,113 at December 31, 2012 and 2013, respectively)
|
|
15,080
|
|
|
17,505
|
|
||
Tank bottom inventory
|
|
58,493
|
|
|
61,915
|
|
||
Other noncurrent assets
|
|
1,889
|
|
|
4,269
|
|
||
Total assets
|
|
$
|
4,420,067
|
|
|
$
|
4,820,812
|
|
|
|
|
|
|
||||
LIABILITIES AND PARTNERS' CAPITAL
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
112,002
|
|
|
$
|
76,326
|
|
Accrued payroll and benefits
|
|
32,434
|
|
|
42,243
|
|
||
Accrued interest payable
|
|
42,059
|
|
|
44,935
|
|
||
Accrued taxes other than income
|
|
33,089
|
|
|
38,574
|
|
||
Environmental liabilities
|
|
14,442
|
|
|
12,147
|
|
||
Deferred revenue
|
|
46,371
|
|
|
63,164
|
|
||
Accrued product purchases
|
|
72,049
|
|
|
63,033
|
|
||
Energy commodity derivatives contracts, net
|
|
7,338
|
|
|
6,737
|
|
||
Current portion of long-term debt
|
|
—
|
|
|
249,971
|
|
||
Other current liabilities
|
|
32,836
|
|
|
41,146
|
|
||
Total current liabilities
|
|
392,620
|
|
|
638,276
|
|
||
Long-term debt
|
|
2,393,408
|
|
|
2,435,316
|
|
||
Long-term pension and benefits
|
|
68,134
|
|
|
51,637
|
|
||
Other noncurrent liabilities
|
|
16,382
|
|
|
21,802
|
|
||
Environmental liabilities
|
|
33,821
|
|
|
26,339
|
|
||
Commitments and contingencies
|
|
|
|
|
||||
Partners' capital:
|
|
|
|
|
|
|||
Limited partner unitholders (226,201 units and 226,679 units outstanding at December 31, 2012 and 2013, respectively)
|
|
1,550,760
|
|
|
1,666,946
|
|
||
Accumulated other comprehensive loss
|
|
(35,058
|
)
|
|
(19,504
|
)
|
||
Total partners’ capital
|
|
1,515,702
|
|
|
1,647,442
|
|
||
Total liabilities and partners' capital
|
|
$
|
4,420,067
|
|
|
$
|
4,820,812
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Operating Activities:
|
|
|
|
|
|
|
||||||
Net income
|
|
$
|
413,566
|
|
|
$
|
435,670
|
|
|
$
|
582,237
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation and amortization expense
|
|
121,179
|
|
|
128,012
|
|
|
142,230
|
|
|||
Debt placement fee amortization
|
|
1,831
|
|
|
2,087
|
|
|
2,424
|
|
|||
Loss on sale and retirement of assets
|
|
8,599
|
|
|
12,625
|
|
|
7,835
|
|
|||
Earnings of non-controlled entities
|
|
(6,763
|
)
|
|
(2,961
|
)
|
|
(6,275
|
)
|
|||
Distributions from investments in non-controlled entities
|
|
5,598
|
|
|
2,961
|
|
|
2,494
|
|
|||
Equity-based incentive compensation expense
|
|
17,710
|
|
|
21,036
|
|
|
24,083
|
|
|||
Changes in employee benefit plan assets and benefit obligations
|
|
1,117
|
|
|
2,962
|
|
|
1,964
|
|
|||
Changes in components of operating assets and liabilities (Note 3)
|
|
14,486
|
|
|
42,699
|
|
|
15,708
|
|
|||
Net cash provided by operating activities
|
|
577,323
|
|
|
645,091
|
|
|
772,700
|
|
|||
Investing Activities:
|
|
|
|
|
|
|
||||||
Property, plant and equipment:
|
|
|
|
|
|
|
||||||
Additions to property, plant and equipment
|
|
(199,665
|
)
|
|
(354,168
|
)
|
|
(383,757
|
)
|
|||
Proceeds from sale and disposition of assets
|
|
6,299
|
|
|
1,056
|
|
|
3,610
|
|
|||
Increase (decrease) in accounts payable related to capital expenditures
|
|
2,126
|
|
|
55,133
|
|
|
(37,678
|
)
|
|||
Acquisition of business
|
|
—
|
|
|
—
|
|
|
(192,000
|
)
|
|||
Acquisition of assets
|
|
(17,807
|
)
|
|
—
|
|
|
(22,506
|
)
|
|||
Acquisition of non-controlling owners' interests
|
|
(40,500
|
)
|
|
—
|
|
|
—
|
|
|||
Investments in non-controlled entities
|
|
(8,094
|
)
|
|
(74,934
|
)
|
|
(250,495
|
)
|
|||
Distributions in excess of earnings of non-controlled entities
|
|
—
|
|
|
4,832
|
|
|
780
|
|
|||
Other
|
|
(1,100
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash used by investing activities
|
|
(258,741
|
)
|
|
(368,081
|
)
|
|
(882,046
|
)
|
|||
Financing Activities:
|
|
|
|
|
|
|
||||||
Distributions paid
|
|
(350,892
|
)
|
|
(403,485
|
)
|
|
(475,461
|
)
|
|||
Net repayments under revolver
|
|
(15,000
|
)
|
|
—
|
|
|
—
|
|
|||
Borrowings under long-term notes
|
|
260,914
|
|
|
248,345
|
|
|
298,680
|
|
|||
Debt placement costs
|
|
(4,575
|
)
|
|
(2,552
|
)
|
|
(4,849
|
)
|
|||
Net receipt from (payment on) interest rate derivatives
|
|
5,926
|
|
|
10,977
|
|
|
(184
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
(5,408
|
)
|
|
1,364
|
|
|
376
|
|
|||
Settlement of tax withholdings on long-term incentive compensation
|
|
(7,410
|
)
|
|
(13,001
|
)
|
|
(12,259
|
)
|
|||
Net cash used by financing activities
|
|
(116,445
|
)
|
|
(158,352
|
)
|
|
(193,697
|
)
|
|||
Change in cash and cash equivalents
|
|
202,137
|
|
|
118,658
|
|
|
(303,043
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
7,483
|
|
|
209,620
|
|
|
328,278
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
209,620
|
|
|
$
|
328,278
|
|
|
$
|
25,235
|
|
Supplemental non-cash financing activities:
|
|
|
|
|
|
|
||||||
Issuance of MMP limited partner units in settlement of long-term incentive plan awards
|
|
$
|
4,315
|
|
|
$
|
7,295
|
|
|
$
|
6,404
|
|
|
|
Partners' Capital
|
|
|
|
|
||||||||||
|
|
Limited Partners
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Non-controlling Owners' Interest
|
|
|
Total Owners' Equity
|
|||||||
Balance, January 1, 2011
|
|
$
|
1,466,404
|
|
|
$
|
(11,096
|
)
|
|
$
|
14,263
|
|
|
$
|
1,469,571
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
|
413,629
|
|
|
—
|
|
|
(63
|
)
|
|
413,566
|
|
||||
Total other comprehensive loss
|
|
—
|
|
|
(36,105
|
)
|
|
—
|
|
|
(36,105
|
)
|
||||
Total comprehensive income (loss)
|
|
413,629
|
|
|
(36,105
|
)
|
|
(63
|
)
|
|
377,461
|
|
||||
Distributions
|
|
(350,892
|
)
|
|
—
|
|
|
—
|
|
|
(350,892
|
)
|
||||
Equity method incentive compensation expense
|
|
11,043
|
|
|
—
|
|
|
—
|
|
|
11,043
|
|
||||
Issuance of MMP limited partner units in settlement of long-term incentive plan awards
|
|
4,315
|
|
|
—
|
|
|
—
|
|
|
4,315
|
|
||||
Settlement of tax withholdings on long-term incentive compensation
|
|
(7,410
|
)
|
|
—
|
|
|
—
|
|
|
(7,410
|
)
|
||||
Acquisition of non-controlling owners' interest
|
|
(26,300
|
)
|
|
—
|
|
|
(14,200
|
)
|
|
(40,500
|
)
|
||||
Other
|
|
(185
|
)
|
|
—
|
|
|
—
|
|
|
(185
|
)
|
||||
Balance, December 31, 2011
|
|
1,510,604
|
|
|
(47,201
|
)
|
|
—
|
|
|
1,463,403
|
|
||||
Comprehensive income:
|
|
|
|
|
|
|
|
|
||||||||
Net income
|
|
435,670
|
|
|
—
|
|
|
—
|
|
|
435,670
|
|
||||
Total other comprehensive income
|
|
—
|
|
|
12,143
|
|
|
—
|
|
|
12,143
|
|
||||
Total comprehensive income
|
|
435,670
|
|
|
12,143
|
|
|
—
|
|
|
447,813
|
|
||||
Distributions
|
|
(403,485
|
)
|
|
—
|
|
|
—
|
|
|
(403,485
|
)
|
||||
Equity method incentive compensation expense
|
|
14,118
|
|
|
—
|
|
|
—
|
|
|
14,118
|
|
||||
Issuance of MMP limited partner units in settlement of long-term incentive plan awards
|
|
7,295
|
|
|
—
|
|
|
—
|
|
|
7,295
|
|
||||
Settlement of tax withholdings on long-term incentive compensation
|
|
(13,001
|
)
|
|
—
|
|
|
—
|
|
|
(13,001
|
)
|
||||
Other
|
|
(441
|
)
|
|
—
|
|
|
—
|
|
|
(441
|
)
|
||||
Balance, December 31, 2012
|
|
1,550,760
|
|
|
(35,058
|
)
|
|
—
|
|
|
1,515,702
|
|
||||
Comprehensive income:
|
|
|
|
|
|
|
|
|
||||||||
Net income
|
|
582,237
|
|
|
—
|
|
|
—
|
|
|
582,237
|
|
||||
Total other comprehensive income
|
|
—
|
|
|
15,554
|
|
|
—
|
|
|
15,554
|
|
||||
Total comprehensive income
|
|
582,237
|
|
|
15,554
|
|
|
—
|
|
|
597,791
|
|
||||
Distributions
|
|
(475,461
|
)
|
|
—
|
|
|
—
|
|
|
(475,461
|
)
|
||||
Equity method incentive compensation expense
|
|
15,532
|
|
|
—
|
|
|
—
|
|
|
15,532
|
|
||||
Issuance of MMP limited partner units in settlement of long-term incentive plan awards
|
|
6,404
|
|
|
—
|
|
|
—
|
|
|
6,404
|
|
||||
Settlement of tax withholdings on long-term incentive compensation
|
|
(12,259
|
)
|
|
—
|
|
|
—
|
|
|
(12,259
|
)
|
||||
Other
|
|
(267
|
)
|
|
—
|
|
|
—
|
|
|
(267
|
)
|
||||
Balance, December 31, 2013
|
|
$
|
1,666,946
|
|
|
$
|
(19,504
|
)
|
|
$
|
—
|
|
|
$
|
1,647,442
|
|
•
|
Our refined products pipeline consists of approximately
9,500
miles of pipeline and
53
terminals that provide transportation, storage and distribution services. Our refined products pipeline covers a
15
-state area from the Gulf Coast across the central U.S. The products transported on our pipeline are primarily gasoline, distillates, aviation fuels and liquefied petroleum gases. Product originates on our pipeline from direct connections to refineries, at our terminals and through interconnections with other interstate pipelines for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end users. Our refined products pipeline also generates fees from ancillary services including ethanol and biodiesel loading and unloading, additive injection, custom blending, terminalling, laboratory testing and data services. Our blending activities involve purchasing liquefied petroleum gases and blending them into gasoline, which creates gasoline available for us to sell. Our fractionation activities include two fractionators along our pipeline system that separate transmix, an unusable mixture of various petroleum products, into gasoline and diesel fuel. We generate transmix from the commingling of products between different product batches during the transportation process on our pipelines. We also purchase transmix from third parties;
|
•
|
Our
27
independent terminals are part of a distribution network located principally throughout the southeastern U.S. We earn revenue at our independent terminals primarily from fees we charge based on the volumes of refined products distributed from these locations and from ancillary services such as additive injections and ethanol blending; and
|
•
|
Our ammonia pipeline consists of
1,100
miles of pipeline that transports and distributes ammonia from production facilities in Texas and Oklahoma to various distribution points in the Midwest for use as an agricultural fertilizer. We generate revenue principally from volume-based fees for the transportation of ammonia on our pipeline system.
|
•
|
Our Longhorn crude oil pipeline consists of approximately
450
miles of pipeline which originates from Crane, Texas for deliveries to Houston-area refineries and pipelines;
|
•
|
Our Houston-area crude oil distribution system originates at our East Houston, Texas terminal and other points in the Houston area for delivery to nearby refineries and other pipeline systems;
|
•
|
Our terminal in Cushing, Oklahoma, one of the largest crude oil trading hubs in the U.S., consists of approximately
10
million barrels used for leased storage. This terminal principally serves refiners, marketers and traders. We earn revenue primarily from leasing tanks as well as from throughput fees;
|
•
|
Our terminal at East Houston, Texas includes approximately
one million
barrels of crude oil storage used for leased storage and our terminal at Corpus Christi, Texas includes approximately
one million
barrels of condensate storage used for leased storage; and
|
•
|
We own approximately
300
miles of pipeline in Kansas and Oklahoma currently used for crude oil service. A majority of these pipelines are leased to third parties, and we earn revenue from these pipeline segments for capacity reserved even if not used by the customers.
|
•
|
a
50%
interest in
Osage Pipe Line Company LLC (“Osage”)
, which owns a
135
-mile pipeline that transports crude oil from Cushing, Oklahoma to refineries in El Dorado, Kansas;
|
•
|
a
50%
interest in
Double Eagle Pipeline LLC (“Double Eagle”)
, which
transports condensate from the Eagle Ford shale formation in South Texas via a
195
-mile pipeline to our terminal in Corpus Christi; and
|
•
|
a
50%
interest in
BridgeTex Pipeline Company, LLC (“BridgeTex”)
, which is constructing
450
miles of pipeline and related infrastructure that is being constructed to transport crude oil from Colorado City, Texas for delivery to the Houston and Texas City, Texas refineries. This pipeline is expected to begin service in mid-2014.
|
2.
|
Summary of Significant Accounting Policies
|
|
|
Derivative
Gains
(Losses)
|
|
Pension and
Postretirement
Liabilities
|
|
Accumulated
Other
Comprehensive
Loss
(3)
|
||||||
Balance, January 1, 2011
|
|
$
|
3,325
|
|
|
$
|
(14,421
|
)
|
|
$
|
(11,096
|
)
|
Derivative activity:
|
|
|
|
|
|
|
||||||
Net gain on cash flow hedges
(1)
|
|
7,739
|
|
|
—
|
|
|
7,739
|
|
|||
Reclassification of net gain on cash flow hedges to income
(1)
|
|
(7,903
|
)
|
|
—
|
|
|
(7,903
|
)
|
|||
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
|
|
|
|
|
|
|
||||||
Net actuarial loss
(2)
|
|
—
|
|
|
(37,058
|
)
|
|
(37,058
|
)
|
|||
Amortization of actuarial loss
(2)
|
|
—
|
|
|
1,591
|
|
|
1,591
|
|
|||
Amortization of prior service credit
(2)
|
|
—
|
|
|
(544
|
)
|
|
(544
|
)
|
|||
Settlement cost
(2)
|
|
—
|
|
|
70
|
|
|
70
|
|
|||
Balance, December 31, 2011
|
|
3,161
|
|
|
(50,362
|
)
|
|
(47,201
|
)
|
|||
Derivative activity:
|
|
|
|
|
|
|
||||||
Net gain on cash flow hedges
(1)
|
|
13,889
|
|
|
—
|
|
|
13,889
|
|
|||
Reclassification of net gain on cash flow hedges to income
(1)
|
|
(2,924
|
)
|
|
—
|
|
|
(2,924
|
)
|
|||
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
|
|
|
|
|
|
|
||||||
Net actuarial loss
(2)
|
|
—
|
|
|
(17,804
|
)
|
|
(17,804
|
)
|
|||
Plan amendment
(2)
|
|
—
|
|
|
16,020
|
|
|
16,020
|
|
|||
Amortization of actuarial loss
(2)
|
|
—
|
|
|
4,626
|
|
|
4,626
|
|
|||
Amortization of prior service credit
(2)
|
|
—
|
|
|
(1,664
|
)
|
|
(1,664
|
)
|
|||
Balance, December 31, 2012
|
|
14,126
|
|
|
(49,184
|
)
|
|
(35,058
|
)
|
|||
Derivative activity:
|
|
|
|
|
|
|
||||||
Net loss on cash flow hedges
(1)
|
|
(4,744
|
)
|
|
—
|
|
|
(4,744
|
)
|
|||
Reclassification of net loss on cash flow hedges to income
(1)
|
|
4,245
|
|
|
—
|
|
|
4,245
|
|
|||
Changes in employee benefit plan assets and benefit obligations recognized in other comprehensive income:
|
|
|
|
|
|
|
||||||
Net actuarial gain
(2)
|
|
—
|
|
|
14,089
|
|
|
14,089
|
|
|||
Amortization of actuarial loss
(2)
|
|
—
|
|
|
5,369
|
|
|
5,369
|
|
|||
Amortization of prior service credit
(2)
|
|
—
|
|
|
(3,405
|
)
|
|
(3,405
|
)
|
|||
Balance, December 31, 2013
|
|
$
|
13,627
|
|
|
$
|
(33,131
|
)
|
|
$
|
(19,504
|
)
|
3.
|
Consolidated Statements of Cash Flows
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Restricted cash
|
|
$
|
14,379
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Trade accounts receivable and other accounts receivable
|
|
5,791
|
|
|
(10,867
|
)
|
|
(19,314
|
)
|
|||
Inventory
|
|
(42,452
|
)
|
|
36,972
|
|
|
34,664
|
|
|||
Energy commodity derivatives contracts, net of derivatives deposits
|
|
(19,782
|
)
|
|
16,097
|
|
|
534
|
|
|||
Accounts payable
|
|
20,226
|
|
|
(11,175
|
)
|
|
2,002
|
|
|||
Accrued payroll and benefits
|
|
(2,209
|
)
|
|
2,250
|
|
|
9,809
|
|
|||
Accrued interest payable
|
|
4,069
|
|
|
1,512
|
|
|
2,876
|
|
|||
Accrued taxes other than income
|
|
617
|
|
|
5,519
|
|
|
5,485
|
|
|||
Accrued product purchases
|
|
12,476
|
|
|
12,249
|
|
|
(9,016
|
)
|
|||
Deferred revenue
|
|
5,250
|
|
|
6,388
|
|
|
16,793
|
|
|||
Current and noncurrent environmental liabilities
|
|
16,861
|
|
|
(1,372
|
)
|
|
(12,247
|
)
|
|||
Other current and noncurrent assets and liabilities
|
|
(740
|
)
|
|
(14,874
|
)
|
|
(15,878
|
)
|
|||
Total
|
|
$
|
14,486
|
|
|
$
|
42,699
|
|
|
$
|
15,708
|
|
4.
|
Investments in Non-Controlled Entities
|
|
|
Texas Frontera
|
|
Osage
|
|
Double Eagle
|
|
BridgeTex
|
|
Consolidated
|
||||||||||
Investment at December 31, 2012
|
|
$
|
15,728
|
|
|
$
|
18,888
|
|
|
$
|
40,840
|
|
|
$
|
31,900
|
|
|
$
|
107,356
|
|
Additional investment
|
|
—
|
|
|
—
|
|
|
35,500
|
|
|
214,995
|
|
|
250,495
|
|
|||||
Earnings (losses) of non-controlled entities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proportionate share of earnings (losses)
|
|
2,494
|
|
|
4,383
|
|
|
82
|
|
|
(20
|
)
|
|
6,939
|
|
|||||
Amortization of excess investment
|
|
—
|
|
|
(664
|
)
|
|
—
|
|
|
—
|
|
|
(664
|
)
|
|||||
Earnings (losses) of non-controlled entities
|
|
2,494
|
|
|
3,719
|
|
|
82
|
|
|
(20
|
)
|
|
6,275
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Distributions of earnings from investments in non-controlled entities
|
|
2,494
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,494
|
|
|||||
Distributions in excess of earnings of non-controlled entities
|
|
780
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
780
|
|
|||||
Investment at December 31, 2013
|
|
$
|
14,948
|
|
|
$
|
22,607
|
|
|
$
|
76,422
|
|
|
$
|
246,875
|
|
|
$
|
360,852
|
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
Business Combinations
|
•
|
New Mexico/Texas System.
In July 2013, we acquired a
250
-mile pipeline that transports refined petroleum products from El Paso, Texas north to Albuquerque, New Mexico and transports products south to the U.S.–Mexico border for delivery within Mexico via a third-party pipeline for
$57.0 million
, which we funded with cash on hand. This pipeline system serves as a natural extension of our existing refined products pipeline system and allows us to provide options to customers in Albuquerque and central New Mexico to access refined products from West Texas, Gulf Coast and Mid-Continent refiners. The operating results have been included in our refined products segment since the acquisition date.
|
•
|
Rocky Mountain System.
In November 2013, we acquired approximately
550
miles of common carrier pipeline that distributes refined petroleum products in Colorado, South Dakota and Wyoming. The system includes
four
terminals with nearly
1.7
million barrels of storage. We funded this
$135.0
million acquisition primarily with proceeds from our debt offering in October 2013. This pipeline system is a strategic fit with our existing assets and customer relationships and extends the reach of our pipeline system to allow us to serve new geographic markets. The operating results have been included in our refined products segment since the acquisition date.
|
Purchase price allocation:
|
$
|
192,000
|
|
Fair value of assets acquired (liabilities assumed):
|
|
||
Property, plant and equipment
|
$
|
192,422
|
|
Other current assets
|
2,048
|
|
|
Current environmental liabilities
|
(2,470
|
)
|
|
Total
|
$
|
192,000
|
|
Revenue
|
$
|
12,661
|
|
Operating profit
|
$
|
6,400
|
|
|
|
Year Ended December 31, 2012
|
|
Year Ended December 31, 2013
|
||||||||||||
|
|
As Reported
|
|
Pro-Forma
|
|
As Reported
|
|
Pro-Forma
|
||||||||
Revenue
|
|
$
|
1,772,074
|
|
|
$
|
1,812,635
|
|
|
$
|
1,897,606
|
|
|
$
|
1,924,316
|
|
Net income
|
|
$
|
435,670
|
|
|
$
|
442,096
|
|
|
$
|
582,237
|
|
|
$
|
591,377
|
|
6.
|
Inventory
|
|
|
2012
|
|
2013
|
||||
Refined petroleum products
|
|
$
|
88,630
|
|
|
$
|
77,144
|
|
Liquefied petroleum gases
|
|
45,657
|
|
|
23,476
|
|
||
Transmix
|
|
63,026
|
|
|
72,156
|
|
||
Crude oil
|
|
17,443
|
|
|
7,188
|
|
||
Additives
|
|
7,132
|
|
|
7,260
|
|
||
Total inventory
|
|
$
|
221,888
|
|
|
$
|
187,224
|
|
7.
|
Product Sales Revenue
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Physical sale of refined products
|
|
$
|
870,007
|
|
|
$
|
833,581
|
|
|
$
|
755,266
|
|
NYMEX contract adjustments:
|
|
|
|
|
|
|
||||||
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment and the effective portion of gains and losses of matured NYMEX contracts that qualified for hedge accounting treatment associated with our butane blending and fractionation activities
(1)
|
|
(4,330
|
)
|
|
(30,270
|
)
|
|
(10,586
|
)
|
|||
Change in value of NYMEX contracts that did not qualify for hedge accounting treatment associated with the Houston-to-El Paso pipeline section linefill working inventory
(1)
|
|
(11,149
|
)
|
|
(3,940
|
)
|
|
—
|
|
|||
Other
|
|
—
|
|
|
11
|
|
|
(11
|
)
|
|||
Total NYMEX contract adjustments
|
|
(15,479
|
)
|
|
(34,199
|
)
|
|
(10,597
|
)
|
|||
Total product sales revenue
|
|
$
|
854,528
|
|
|
$
|
799,382
|
|
|
$
|
744,669
|
|
8.
|
Property, Plant and Equipment
|
|
|
December 31,
|
|
Estimated Depreciable
Lives
|
||||||
|
|
2012
|
|
2013
|
|
|||||
Construction work-in-progress
|
|
$
|
247,571
|
|
|
$
|
165,129
|
|
|
|
Land and rights-of-way
|
|
83,014
|
|
|
78,405
|
|
|
|
||
Carrier property
|
|
1,835,265
|
|
|
2,135,905
|
|
|
7 to 59 years
|
||
Buildings
|
|
37,672
|
|
|
41,383
|
|
|
20 to 55 years
|
||
Storage tanks
|
|
975,277
|
|
|
1,141,271
|
|
|
10 to 40 years
|
||
Pipeline and station equipment
|
|
479,531
|
|
|
593,396
|
|
|
3 to 59 years
|
||
Processing equipment
|
|
645,140
|
|
|
716,103
|
|
|
3 to 56 years
|
||
Other
|
|
105,080
|
|
|
115,158
|
|
|
3 to 48 years
|
||
Property, Plant and Equipment, Gross
|
|
$
|
4,408,550
|
|
|
$
|
4,986,750
|
|
|
|
|
|
|
|
|
|
|
9.
|
Major Customers and Concentration of Risks
|
10.
|
Employee Benefit Plans
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
||||||||||||
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
|
$
|
113,914
|
|
|
$
|
142,703
|
|
|
$
|
23,786
|
|
|
$
|
13,195
|
|
Service cost
|
|
12,222
|
|
|
13,901
|
|
|
396
|
|
|
288
|
|
||||
Interest cost
|
|
4,862
|
|
|
5,368
|
|
|
821
|
|
|
412
|
|
||||
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
221
|
|
|
248
|
|
||||
Actuarial loss (gain)
|
|
15,975
|
|
|
(14,121
|
)
|
|
4,751
|
|
|
(2,675
|
)
|
||||
Benefits paid
|
|
(4,270
|
)
|
|
(5,541
|
)
|
|
(760
|
)
|
|
(1,050
|
)
|
||||
Plan amendment
|
|
—
|
|
|
—
|
|
|
(16,020
|
)
|
|
—
|
|
||||
Benefit obligation at end of year
|
|
142,703
|
|
|
142,310
|
|
|
13,195
|
|
|
10,418
|
|
||||
Change in plan assets:
|
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
|
70,052
|
|
|
87,106
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
|
13,336
|
|
|
15,470
|
|
|
539
|
|
|
802
|
|
||||
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
221
|
|
|
248
|
|
||||
Actual return on plan assets
|
|
7,988
|
|
|
3,521
|
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
|
(4,270
|
)
|
|
(5,541
|
)
|
|
(760
|
)
|
|
(1,050
|
)
|
||||
Fair value of plan assets at end of year
|
|
87,106
|
|
|
100,556
|
|
|
—
|
|
|
—
|
|
||||
Funded status at end of year
|
|
$
|
(55,597
|
)
|
|
$
|
(41,754
|
)
|
|
$
|
(13,195
|
)
|
|
$
|
(10,418
|
)
|
Accumulated benefit obligation
|
|
$
|
101,233
|
|
|
$
|
103,466
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
||||||||||||
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
||||||||
Amounts recognized in consolidated balance sheet:
|
|
|
|
|
|
|
|
|
||||||||
Current accrued benefit cost
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(658
|
)
|
|
$
|
(535
|
)
|
Long-term pension and benefit cost
|
|
(55,597
|
)
|
|
(41,754
|
)
|
|
(12,537
|
)
|
|
(9,883
|
)
|
||||
|
|
(55,597
|
)
|
|
(41,754
|
)
|
|
(13,195
|
)
|
|
(10,418
|
)
|
||||
Accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
||||||||
Net actuarial loss
|
|
51,899
|
|
|
36,151
|
|
|
11,418
|
|
|
7,708
|
|
||||
Prior service cost (credit)
|
|
340
|
|
|
33
|
|
|
(14,473
|
)
|
|
(10,761
|
)
|
||||
|
|
52,239
|
|
|
36,184
|
|
|
(3,055
|
)
|
|
(3,053
|
)
|
||||
Net amount recognized in consolidated balance sheet
|
|
$
|
(3,358
|
)
|
|
$
|
(5,570
|
)
|
|
$
|
(16,250
|
)
|
|
$
|
(13,471
|
)
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||||||||||
|
|
2011
|
|
2012
|
|
2013
|
|
2011
|
|
2012
|
|
2013
|
||||||||||||
Components of net periodic pension and postretirement benefit expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
|
$
|
9,628
|
|
|
$
|
12,222
|
|
|
$
|
13,901
|
|
|
$
|
430
|
|
|
$
|
396
|
|
|
$
|
288
|
|
Interest cost
|
|
4,343
|
|
|
4,862
|
|
|
5,368
|
|
|
999
|
|
|
821
|
|
|
412
|
|
||||||
Expected return on plan assets
|
|
(4,357
|
)
|
|
(5,066
|
)
|
|
(6,228
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of prior service cost (credit)
|
|
307
|
|
|
307
|
|
|
307
|
|
|
(851
|
)
|
|
(1,971
|
)
|
|
(3,712
|
)
|
||||||
Amortization of actuarial loss
|
|
1,424
|
|
|
3,605
|
|
|
4,334
|
|
|
167
|
|
|
1,021
|
|
|
1,035
|
|
||||||
Settlement cost
|
|
70
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic expense (credit)
|
|
$
|
11,415
|
|
|
$
|
15,930
|
|
|
$
|
17,682
|
|
|
$
|
745
|
|
|
$
|
267
|
|
|
$
|
(1,977
|
)
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
||||||||||||
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive loss:
|
|
|
|
|
|
|
|
|
||||||||
Net actuarial loss (gain)
|
|
$
|
13,053
|
|
|
$
|
(11,414
|
)
|
|
$
|
4,751
|
|
|
$
|
(2,675
|
)
|
Plan amendment
|
|
—
|
|
|
—
|
|
|
(16,020
|
)
|
|
—
|
|
||||
Amortization of actuarial loss
|
|
(3,605
|
)
|
|
(4,334
|
)
|
|
(1,021
|
)
|
|
(1,035
|
)
|
||||
Amortization of prior service credit (cost)
|
|
(307
|
)
|
|
(307
|
)
|
|
1,971
|
|
|
3,712
|
|
||||
Total recognized in other comprehensive loss
|
|
9,141
|
|
|
(16,055
|
)
|
|
(10,319
|
)
|
|
2
|
|
||||
Net periodic expense (credit)
|
|
15,930
|
|
|
17,682
|
|
|
267
|
|
|
(1,977
|
)
|
||||
Total recognized in net periodic benefit cost and other comprehensive loss
|
|
$
|
25,071
|
|
|
$
|
1,627
|
|
|
$
|
(10,052
|
)
|
|
$
|
(1,975
|
)
|
|
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
||||
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
Discount rate—Salaried plan
|
|
4.00%
|
|
4.89%
|
|
n/a
|
|
n/a
|
Discount rate—USW plan
|
|
3.39%
|
|
4.26%
|
|
n/a
|
|
n/a
|
Discount rate—IUOE plan
|
|
3.99%
|
|
4.89%
|
|
n/a
|
|
n/a
|
Discount rate—Other Postretirement Benefits
|
|
n/a
|
|
n/a
|
|
3.58%
|
|
4.52%
|
Rate of compensation increase—Salaried plan
|
|
5.00%
|
|
5.00%
|
|
n/a
|
|
n/a
|
Rate of compensation increase—USW plan
|
|
3.50%
|
|
3.50%
|
|
n/a
|
|
n/a
|
Rate of compensation increase—IUOE plan
|
|
5.00%
|
|
5.00%
|
|
n/a
|
|
n/a
|
|
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
|
2011
|
|
2012
|
|
2013
|
||
Discount rate—Salaried plan
|
|
5.54%
|
|
4.39%
|
|
4.00%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Discount rate—USW plan
|
|
5.07%
|
|
4.00%
|
|
3.39%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Discount rate—IUOE plan
|
|
5.52%
|
|
4.37%
|
|
3.99%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Discount rate—Other Postretirement Benefits
|
|
n/a
|
|
n/a
|
|
n/a
|
|
5.56%
|
|
3.75
|
%
|
|
3.58
|
%
|
Rate of compensation increase—Salaried plan
|
|
5.00%
|
|
5.00%
|
|
5.00%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Rate of compensation increase—USW plan
|
|
4.50%
|
|
3.50%
|
|
3.50%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Rate of compensation increase—IUOE plan
|
|
5.00%
|
|
5.00%
|
|
5.00%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Expected rate of return on plan assets—Salaried plan
|
|
6.80%
|
|
6.80%
|
|
6.80%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Expected rate of return on plan assets—USW plan
|
|
6.80%
|
|
6.80%
|
|
6.80%
|
|
n/a
|
|
n/a
|
|
n/a
|
||
Expected rate of return on plan assets—IUOE plan
|
|
3.25%
|
|
6.80%
|
|
6.80%
|
|
n/a
|
|
n/a
|
|
n/a
|
|
|
1%
Increase
|
|
1%
Decrease
|
||||
Change in total of service and interest cost components
|
|
$
|
39
|
|
|
$
|
35
|
|
Change in postretirement benefit obligation
|
|
$
|
533
|
|
|
$
|
486
|
|
Asset Category
|
|
Total
|
|
Quoted Prices in Active Markets for
Identical Assets
(Level 1)
|
|
Significant
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||
Domestic Equity Securities
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Small-cap fund
|
|
$
|
1,726
|
|
|
$
|
1,726
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mid-cap fund
|
|
1,708
|
|
|
1,708
|
|
|
—
|
|
|
—
|
|
||||
Large-cap fund
|
|
12,810
|
|
|
12,810
|
|
|
—
|
|
|
—
|
|
||||
International equity fund
|
|
8,019
|
|
|
8,019
|
|
|
—
|
|
|
—
|
|
||||
Fixed Income Securities
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Short-term bond funds
|
|
2,824
|
|
|
2,824
|
|
|
—
|
|
|
—
|
|
||||
Intermediate-term bond funds
|
|
16,677
|
|
|
16,677
|
|
|
—
|
|
|
—
|
|
||||
Long-term investment grade bond fund
|
|
40,370
|
|
|
40,370
|
|
|
—
|
|
|
—
|
|
||||
Other:
|
|
|
|
|
|
|
|
|
||||||||
Short-term investment fund
|
|
2,614
|
|
|
2,614
|
|
|
—
|
|
|
—
|
|
||||
Group annuity contract
|
|
358
|
|
|
—
|
|
|
—
|
|
|
358
|
|
||||
Fair value of plan assets
|
|
$
|
87,106
|
|
|
$
|
86,748
|
|
|
$
|
—
|
|
|
$
|
358
|
|
|
|
|
|
|
|
|
|
|
Asset Category
|
|
Total
|
|
Quoted Prices in Active Markets for
Identical Assets
(Level 1)
|
|
Significant
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||
Domestic Equity Securities
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Small-cap fund
|
|
$
|
2,480
|
|
|
$
|
2,480
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mid-cap fund
|
|
2,465
|
|
|
2,465
|
|
|
—
|
|
|
—
|
|
||||
Large-cap fund
|
|
18,642
|
|
|
18,642
|
|
|
—
|
|
|
—
|
|
||||
International equity fund
|
|
11,793
|
|
|
11,793
|
|
|
—
|
|
|
—
|
|
||||
Fixed Income Securities
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Short-term bond funds
|
|
3,243
|
|
|
3,243
|
|
|
—
|
|
|
—
|
|
||||
Intermediate-term bond funds
|
|
12,492
|
|
|
12,492
|
|
|
—
|
|
|
—
|
|
||||
Long-term investment grade bond funds
|
|
45,900
|
|
|
45,900
|
|
|
—
|
|
|
—
|
|
||||
Other:
|
|
|
|
|
|
|
|
|
||||||||
Short-term investment funds
|
|
3,244
|
|
|
3,244
|
|
|
—
|
|
|
—
|
|
||||
Group annuity contract
|
|
297
|
|
|
—
|
|
|
—
|
|
|
297
|
|
||||
Fair value of plan assets
|
|
$
|
100,556
|
|
|
$
|
100,259
|
|
|
$
|
—
|
|
|
$
|
297
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
2013
|
||||
Beginning balance
|
$
|
400
|
|
|
$
|
358
|
|
Actual return on plan assets:
|
|
|
|
||||
Relating to assets still held at the reporting date
|
16
|
|
|
(7
|
)
|
||
Purchases, issuances, sales and settlements:
|
|
|
|
||||
Settlements
|
(58
|
)
|
|
(54
|
)
|
||
Ending balance
|
$
|
358
|
|
|
$
|
297
|
|
|
|
|
Asset Category
|
|
Fund’s Investment Strategy
|
Domestic Equity Securities:
|
|
|
Small-cap fund
|
|
Seeks to track performance of the Center for Research in Security Prices ("CRSP") US Small Cap Index
|
Mid-cap fund
|
|
Seeks to track performance of the CRSP US Mid Cap Index
|
Large-cap fund
|
|
Seeks to track performance of the Standard & Poor’s 500 Index
|
International equity fund
|
|
Seeks long-term growth of capital by investing 65% or more of assets in international equities
|
|
|
|
Fixed Income Securities:
|
|
|
Short-term bond funds
|
|
Seek current income with limited price volatility through investment in primarily high quality bonds
|
Intermediate-term bond funds
|
|
Seek moderate and sustainable level of current income by investing primarily in high quality fixed income securities with maturities from five to ten years
|
Long-term investment grade bond funds
|
|
Seek high and sustainable current income through investment primarily in long-term high grade bonds
|
|
|
|
Other:
|
|
|
Short-term investment funds
|
|
Invest primarily in high quality commercial paper and government securities
|
Group annuity contract
|
|
Guarantees a specified return based on a specified index
|
|
|
2012
|
|
2013
|
||||
|
|
Actual
(a)
|
|
Target
|
|
Actual
(a)
|
|
Target
|
Equity securities
|
|
28%
|
|
30%
|
|
35%
|
|
30%
|
Debt securities
|
|
69%
|
|
67%
|
|
62%
|
|
67%
|
Other
|
|
3%
|
|
3%
|
|
3%
|
|
3%
|
|
|
|
|
|
|
|
|
|
(a)
|
Cash contributions of
$13.3 million
and
$15.5 million
were made to the pension plans during 2012 and 2013, respectively. Amounts contributed in 2012 and 2013 in excess of benefit payments made were to be invested in debt and equity securities over a twelve-month period, with the amounts that remained uninvested as of December 31, 2012 and 2013 scheduled for investment in accordance with the target. Excluding these uninvested cash amounts, the actual allocation percentages at December 31, 2012 would have been
29%
equity securities and
71%
debt securities and at December 31, 2013, would have been
36%
equity securities and
64%
debt securities. In 2014, we will invest these uninvested cash amounts to bring the total asset allocation in line with the target allocation
.
|
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
||||
2014
|
|
$
|
5,207
|
|
|
$
|
535
|
|
2015
|
|
$
|
5,507
|
|
|
$
|
590
|
|
2016
|
|
$
|
6,282
|
|
|
$
|
578
|
|
2017
|
|
$
|
9,267
|
|
|
$
|
627
|
|
2018
|
|
$
|
9,032
|
|
|
$
|
665
|
|
2019 through 2023
|
|
$
|
58,108
|
|
|
$
|
4,205
|
|
11.
|
Related Party Transactions
|
12.
|
Debt
|
|
|
|
|
Weighted-Average Interest Rate at December 31, 2013 (a)
|
||||||
|
|
December 31,
|
|
|||||||
|
|
2012
|
|
2013
|
|
|||||
Revolving credit facility
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—%
|
$250.0 million of 6.45% Notes due 2014
|
|
249,905
|
|
|
249,971
|
|
|
6.3%
|
||
$250.0 million of 5.65% Notes due 2016
|
|
251,609
|
|
|
251,183
|
|
|
5.7%
|
||
$250.0 million of 6.40% Notes due 2018
|
|
261,411
|
|
|
259,346
|
|
|
5.4%
|
||
$550.0 million of 6.55% Notes due 2019
|
|
575,065
|
|
|
571,515
|
|
|
5.7%
|
||
$550.0 million of 4.25% Notes due 2021
|
|
558,088
|
|
|
557,213
|
|
|
4.0%
|
||
$250.0 million of 6.40% Notes due 2037
|
|
248,981
|
|
|
248,998
|
|
|
6.4%
|
||
$250.0 million of 4.20% Notes due 2042
|
|
248,349
|
|
|
248,377
|
|
|
4.2%
|
||
$300.0 million of 5.15% Notes due 2043
|
|
—
|
|
|
298,684
|
|
|
5.2%
|
||
Total debt
|
|
$
|
2,393,408
|
|
|
$
|
2,685,287
|
|
|
5.2%
|
|
|
|
|
|
|
|
(a)
|
Weighted-average interest rate includes the amortization/accretion of discounts and premiums and the amortization/accretion of gains and losses realized on historical cash flow and fair value hedges on interest expense.
|
13.
|
Derivative Financial Instruments
|
|
Notional Value
|
|
Barrels
|
|||
Forward purchase contracts
|
$
|
122.8
|
|
|
2.0
|
|
Forward sale contracts
|
$
|
64.2
|
|
|
0.6
|
|
Type of Contract/Accounting Methodology
|
|
Product Represented by the Contract and Associated Barrels
|
|
Maturity Dates
|
NYMEX - Fair Value Hedges
|
|
0.7 million barrels of crude oil
|
|
Between January 2014 and November 2016
|
NYMEX - Economic Hedges
|
|
2.2 million barrels of refined products and crude oil
|
|
Between January and April 2014
|
Butane Futures Agreements - Economic Hedges
|
|
0.1 million barrels of butane
|
|
Between January and April 2014
|
|
|
December 31, 2012
|
||||||||||||||||||
Description
|
|
Gross Amounts of Liabilities
|
|
Gross Amounts of Assets
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
|
|
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
|
|
Net Amount
|
||||||||||
Energy commodity derivatives
|
|
$
|
(9,388
|
)
|
|
$
|
2,050
|
|
|
$
|
(7,338
|
)
|
|
$
|
18,304
|
|
|
$
|
10,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
||||||||||||||||||
Description
|
|
Gross Amounts of Liabilities
|
|
Gross Amounts of Assets
|
|
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(1)
|
|
Margin Deposit Amounts Not Offset in the Consolidated Balance Sheet
|
|
Net Amount
|
||||||||||
Energy commodity derivatives
|
|
$
|
(7,167
|
)
|
|
$
|
2,665
|
|
|
$
|
(4,502
|
)
|
|
$
|
14,782
|
|
|
$
|
10,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2012
|
||||||||||||
Derivative Instrument
|
|
Amount of Gain Recognized in AOCL on Derivative
|
|
Location of Gain Reclassified from AOCL into Income
|
|
Amount of Gain Reclassified from AOCL into Income
|
||||||||
Interest rate contracts
|
|
|
$
|
10,977
|
|
|
|
Interest expense
|
|
|
$
|
164
|
|
|
NYMEX commodity contracts
|
|
|
2,912
|
|
|
|
Product sales revenue
|
|
|
2,760
|
|
|
||
Total cash flow hedges
|
|
|
$
|
13,889
|
|
|
|
Total
|
|
|
$
|
2,924
|
|
|
|
|
Year Ended December 31, 2013
|
||||||||||||
Derivative Instrument
|
|
Amount of Loss Recognized in AOCL on Derivative
|
|
Location of Gain (Loss) Reclassified from AOCL into Income
|
|
Amount of Gain (Loss) Reclassified from AOCL into Income
|
||||||||
Interest rate contracts
|
|
|
$
|
(184
|
)
|
|
|
Interest expense
|
|
|
$
|
163
|
|
|
NYMEX commodity contracts
|
|
|
(4,560
|
)
|
|
|
Product sales revenue
|
|
|
(4,408
|
)
|
|
||
Total cash flow hedges
|
|
|
$
|
(4,744
|
)
|
|
|
Total
|
|
|
$
|
(4,245
|
)
|
|
|
|
|
|
Amount of Gain (Loss)
Recognized on Derivative |
||||||
|
|
|
|
Year Ended December 31,
|
||||||
Derivative Instrument
|
|
Location of Gain (Loss)
Recognized on Derivative
|
|
2012
|
|
2013
|
||||
NYMEX commodity contracts
|
|
Product sales revenue
|
|
$
|
(36,959
|
)
|
|
$
|
(6,189
|
)
|
NYMEX commodity contracts
|
|
Operating expenses
|
|
(2,055
|
)
|
|
(3,770
|
)
|
||
Butane futures agreements
|
|
Cost of product sales
|
|
1,203
|
|
|
2,682
|
|
||
|
|
Total
|
|
$
|
(37,811
|
)
|
|
$
|
(7,277
|
)
|
|
|
December 31, 2012
|
||||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||
Derivative Instrument
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
||||
NYMEX commodity contracts
|
|
Energy commodity derivatives contracts, net
|
|
$
|
473
|
|
|
Energy commodity derivatives contracts, net
|
|
$
|
207
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
||||
|
|
December 31, 2013
|
||||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||
Derivative Instrument
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
||||
NYMEX commodity contracts
|
|
Energy commodity derivatives contracts, net
|
|
$
|
—
|
|
|
Energy commodity derivatives contracts, net
|
|
$
|
146
|
|
NYMEX commodity contracts
|
|
Other noncurrent assets
|
|
2,235
|
|
|
Other noncurrent liabilities
|
|
—
|
|
||
|
|
Total
|
|
$
|
2,235
|
|
|
Total
|
|
$
|
146
|
|
|
|
December 31, 2012
|
||||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||
Derivative Instrument
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
||||
NYMEX commodity contracts
|
|
Energy commodity derivatives contracts, net
|
|
$
|
227
|
|
|
Energy commodity derivatives contracts, net
|
|
$
|
8,954
|
|
Butane futures agreements
|
|
Energy commodity derivatives contracts, net
|
|
1,350
|
|
|
Energy commodity derivatives contracts, net
|
|
227
|
|
||
|
|
Total
|
|
$
|
1,577
|
|
|
Total
|
|
$
|
9,181
|
|
|
|
December 31, 2013
|
||||||||||
|
|
Asset Derivatives
|
|
Liability Derivatives
|
||||||||
Derivative Instrument
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
||||
NYMEX commodity contracts
|
|
Energy commodity derivatives contracts, net
|
|
$
|
48
|
|
|
Energy commodity derivatives contracts, net
|
|
$
|
7,021
|
|
Butane futures agreements
|
|
Energy commodity derivatives contracts, net
|
|
382
|
|
|
Energy commodity derivatives contracts, net
|
|
—
|
|
||
|
|
Total
|
|
$
|
430
|
|
|
Total
|
|
$
|
7,021
|
|
14.
|
Leases
|
2014
|
$
|
16.2
|
|
2015
|
16.5
|
|
|
2016
|
16.1
|
|
|
2017
|
16.6
|
|
|
2018
|
13.1
|
|
|
Thereafter
|
51.5
|
|
|
Total
|
$
|
130.0
|
|
2014
|
$
|
240.8
|
|
2015
|
229.7
|
|
|
2016
|
174.6
|
|
|
2017
|
111.7
|
|
|
2018
|
71.3
|
|
|
Thereafter
|
170.5
|
|
|
Total
|
$
|
998.6
|
|
|
|
Equity Method
|
|
Liability Method Performance-Based Awards
|
|
|
|
|
||||||||||||||||||||
|
|
Performance-Based Awards
|
|
Retention Awards
|
|
|
Total Awards
|
|||||||||||||||||||||
|
|
Number of Unit
Awards
|
|
Weighted-Average Grant Date Fair Value
|
|
Number of Unit
Awards
|
|
Weighted-Average Grant Date Fair Value
|
|
Number of Unit
Awards
|
|
Weighted-Average Fair Value
|
|
Number of Unit
Awards
|
|
Weighted-Average Fair Value
|
||||||||||||
Non-vested units - 1/1/2013
|
|
444,090
|
|
|
$
|
31.24
|
|
|
58,802
|
|
|
$
|
24.60
|
|
|
111,025
|
|
|
$
|
43.19
|
|
|
613,917
|
|
|
$
|
32.77
|
|
Units granted during 2013
|
|
182,798
|
|
|
$
|
51.49
|
|
|
22,668
|
|
|
$
|
53.02
|
|
|
45,700
|
|
|
$
|
51.49
|
|
|
251,166
|
|
|
$
|
51.63
|
|
Units vested during 2013
|
|
(228,058
|
)
|
|
$
|
29.07
|
|
|
(2,207
|
)
|
|
$
|
34.02
|
|
|
(57,015
|
)
|
|
$
|
63.27
|
|
|
(287,280
|
)
|
|
$
|
35.90
|
|
Units forfeited during 2013
|
|
(9,420
|
)
|
|
$
|
35.98
|
|
|
(4,052
|
)
|
|
$
|
25.00
|
|
|
(2,355
|
)
|
|
$
|
63.27
|
|
|
(15,827
|
)
|
|
$
|
37.23
|
|
Non-vested units - 12/31/13
|
|
389,410
|
|
|
$
|
41.90
|
|
|
75,211
|
|
|
$
|
32.87
|
|
|
97,355
|
|
|
$
|
63.27
|
|
|
561,976
|
|
|
$
|
44.40
|
|
Grant Date
|
Unit Awards Granted
|
|
Estimated Forfeitures
|
|
Adjustment to Unit Awards in Anticipation of Achieving Above- Target Financial Results
|
|
Total Unit Award Accrual
|
|
Vesting Date
|
|
Unrecognized Compensation Expense
(a)
(in millions)
|
|
||||||
Performance-Based Awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2012 Awards
|
267,322
|
|
|
39,225
|
|
|
228,097
|
|
|
456,194
|
|
|
12/31/2014
|
|
$
|
6.0
|
|
|
2013 Awards
|
228,498
|
|
|
31,869
|
|
|
147,472
|
|
|
344,101
|
|
|
12/31/2015
|
|
12.4
|
|
|
|
Retention Awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
2014 Vesting Date
|
71,849
|
|
|
10,778
|
|
|
—
|
|
|
61,071
|
|
|
12/31/2014
|
|
0.7
|
|
|
|
2015 Vesting Date
|
444
|
|
|
22
|
|
|
—
|
|
|
422
|
|
|
12/31/2015
|
|
—
|
|
|
|
2016 Vesting Date
|
13,300
|
|
|
665
|
|
|
—
|
|
|
12,635
|
|
|
12/31/2016
|
|
0.7
|
|
|
|
Total
|
581,413
|
|
|
82,559
|
|
|
375,569
|
|
|
874,423
|
|
|
|
|
$
|
19.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Method
|
|
|
|||||||||||||||||
|
|
Performance-Based Awards
|
|
Retention Awards
|
|
Liability Method Performance-Based Awards
|
|||||||||||||||
|
|
Number of
Unit
Awards
|
|
Weighted-Average Grant Date Fair Value
|
|
Number of Unit
Awards
|
|
Weighted-Average Grant Date Fair Value
|
|
Number of Unit
Awards
|
|
Weighted-Average Fair Value
|
|||||||||
Units granted during 2011
|
|
281,180
|
|
|
$
|
28.52
|
|
|
59,880
|
|
|
$
|
23.96
|
|
|
70,296
|
|
|
$
|
34.32
|
|
Units granted during 2012
|
|
214,232
|
|
|
$
|
33.57
|
|
|
7,016
|
|
|
$
|
30.54
|
|
|
53,558
|
|
|
$
|
33.57
|
|
Units granted during 2013
|
|
182,798
|
|
|
$
|
51.49
|
|
|
22,668
|
|
|
$
|
53.02
|
|
|
45,700
|
|
|
$
|
51.49
|
|
Vesting Date
|
|
Vested
Limited
Partner Units
|
|
Fair Value of Unit Awards on Vesting Date (in millions)*
|
|
Intrinsic Value of Unit Awards on Vesting Date (in millions)
|
|||||
12/31/2011
|
|
1,100,276
|
|
|
$
|
16.5
|
|
|
$
|
37.9
|
|
12/31/2012
|
|
751,237
|
|
|
$
|
17.1
|
|
|
$
|
32.5
|
|
12/31/2013
|
|
572,353
|
|
|
$
|
20.5
|
|
|
$
|
36.2
|
|
|
|
|
|
|
|
|
Settlement Date
|
|
Number of Limited Partner Units Issued, Net of Tax Withholdings
|
|
Minimum Tax Withholdings
(in millions)
|
|
Employer Taxes (in millions)
|
|
Total Cash Taxes Paid (in millions)
|
|||||||
January 2011
|
|
505,492
|
|
|
$
|
7.4
|
|
|
$
|
0.9
|
|
|
$
|
8.3
|
|
January 2012
|
|
722,766
|
|
|
$
|
13.0
|
|
|
$
|
1.3
|
|
|
$
|
14.3
|
|
January 2013
|
|
476,682
|
|
|
$
|
12.3
|
|
|
$
|
1.1
|
|
|
$
|
13.4
|
|
|
Year Ended December 31, 2011
|
|
Year Ended December 31, 2012
|
|
Year Ended December 31, 2013
|
||||||||||||||||||||||||||||||
|
Equity
Method
|
|
Liability
Method
|
|
Total
|
|
Equity
Method
|
|
Liability
Method
|
|
Total
|
|
Equity
Method
|
|
Liability
Method
|
|
Total
|
||||||||||||||||||
2009 awards
|
$
|
4,418
|
|
|
$
|
4,264
|
|
|
$
|
8,682
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2010 awards
|
3,100
|
|
|
1,562
|
|
|
4,662
|
|
|
4,937
|
|
|
3,723
|
|
|
8,660
|
|
|
121
|
|
|
73
|
|
|
194
|
|
|||||||||
2011 awards
|
2,839
|
|
|
841
|
|
|
3,680
|
|
|
5,062
|
|
|
2,094
|
|
|
7,156
|
|
|
5,359
|
|
|
4,280
|
|
|
9,639
|
|
|||||||||
2012 awards
|
—
|
|
|
—
|
|
|
—
|
|
|
3,426
|
|
|
1,101
|
|
|
4,527
|
|
|
4,751
|
|
|
2,747
|
|
|
7,498
|
|
|||||||||
2013 awards
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,726
|
|
|
1,451
|
|
|
6,177
|
|
|||||||||
Retention awards
|
686
|
|
|
—
|
|
|
686
|
|
|
693
|
|
|
—
|
|
|
693
|
|
|
575
|
|
|
—
|
|
|
575
|
|
|||||||||
Total
|
$
|
11,043
|
|
|
$
|
6,667
|
|
|
$
|
17,710
|
|
|
$
|
14,118
|
|
|
$
|
6,918
|
|
|
$
|
21,036
|
|
|
$
|
15,532
|
|
|
$
|
8,551
|
|
|
$
|
24,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Allocation of LTIP expense on our consolidated statements of income:
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||
G&A expense
|
|
|
|
$
|
16,024
|
|
|
|
|
|
|
$
|
18,587
|
|
|
|
|
|
|
$
|
23,264
|
|
|||||||||||||
Operating expense
|
|
|
|
1,686
|
|
|
|
|
|
|
2,449
|
|
|
|
|
|
|
819
|
|
||||||||||||||||
Total
|
|
|
|
$
|
17,710
|
|
|
|
|
|
|
$
|
21,036
|
|
|
|
|
|
|
$
|
24,083
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2011
|
|
2012
|
|
2013
|
||||||
Phantom units earned pursuant to the LTIP
|
|
20,284
|
|
|
20,054
|
|
|
16,424
|
|
|||
|
|
|
|
|
|
|
||||||
(in thousands)
|
|
|
|
|
|
|
||||||
Compensation - phantom unit expense
|
|
$
|
446
|
|
|
$
|
523
|
|
|
$
|
533
|
|
Distribution equivalents
|
|
139
|
|
|
195
|
|
|
267
|
|
|||
Changes in market value of phantom units
|
|
568
|
|
|
973
|
|
|
2,535
|
|
|||
Total value of phantom units
|
|
1,153
|
|
|
1,691
|
|
|
3,335
|
|
|||
Compensation paid in cash
|
|
292
|
|
|
345
|
|
|
422
|
|
|||
Compensation paid in our limited partner units
|
|
140
|
|
|
170
|
|
|
85
|
|
|||
Total director compensation
|
|
1,585
|
|
|
2,206
|
|
|
3,842
|
|
|||
Distribution equivalents charged to partners' capital
|
|
(139
|
)
|
|
(195
|
)
|
|
(267
|
)
|
|||
Total director compensation expense
|
|
$
|
1,446
|
|
|
$
|
2,011
|
|
|
$
|
3,575
|
|
|
|
|
|
|
|
|
16.
|
Segment Disclosures
|
|
|
Year Ended December 31, 2011
|
||||||||||||||||||
|
|
Refined Products
|
|
Crude Oil
|
|
Marine Storage
|
|
Intersegment
Eliminations
|
|
Total
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Transportation and terminals revenue
|
|
$
|
680,235
|
|
|
$
|
61,205
|
|
|
$
|
151,929
|
|
|
$
|
—
|
|
|
$
|
893,369
|
|
Product sales revenue
|
|
848,902
|
|
|
591
|
|
|
5,035
|
|
|
—
|
|
|
854,528
|
|
|||||
Affiliate management fee revenue
|
|
—
|
|
|
770
|
|
|
—
|
|
|
—
|
|
|
770
|
|
|||||
Total revenue
|
|
1,529,137
|
|
|
62,566
|
|
|
156,964
|
|
|
—
|
|
|
1,748,667
|
|
|||||
Operating expenses
|
|
250,794
|
|
|
(4,898
|
)
|
|
63,438
|
|
|
(2,919
|
)
|
|
306,415
|
|
|||||
Cost of product sales
|
|
704,313
|
|
|
—
|
|
|
1,957
|
|
|
—
|
|
|
706,270
|
|
|||||
Earnings of non-controlled entities
|
|
—
|
|
|
(6,761
|
)
|
|
(2
|
)
|
|
—
|
|
|
(6,763
|
)
|
|||||
Operating margin
|
|
574,030
|
|
|
74,225
|
|
|
91,571
|
|
|
2,919
|
|
|
742,745
|
|
|||||
Depreciation and amortization expense
|
|
81,876
|
|
|
10,303
|
|
|
26,081
|
|
|
2,919
|
|
|
121,179
|
|
|||||
G&A expenses
|
|
80,746
|
|
|
1,773
|
|
|
16,150
|
|
|
—
|
|
|
98,669
|
|
|||||
Operating profit
|
|
$
|
411,408
|
|
|
$
|
62,149
|
|
|
$
|
49,340
|
|
|
$
|
—
|
|
|
$
|
522,897
|
|
Additions to long-lived assets
|
|
$
|
130,645
|
|
|
$
|
45,124
|
|
|
$
|
38,125
|
|
|
|
|
$
|
213,894
|
|
||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
As of December 31, 2011
|
||||||||||||||||||
Segment assets
|
|
$
|
2,736,522
|
|
|
$
|
432,073
|
|
|
$
|
638,451
|
|
|
|
|
$
|
3,807,046
|
|
||
Corporate assets
|
|
|
|
|
|
|
|
|
|
237,955
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
|
$
|
4,045,001
|
|
||||||||
Goodwill
|
|
$
|
38,369
|
|
|
$
|
12,082
|
|
|
$
|
2,809
|
|
|
|
|
$
|
53,260
|
|
||
Investments in non-controlled entities
|
|
$
|
—
|
|
|
$
|
24,936
|
|
|
$
|
10,658
|
|
|
|
|
$
|
35,594
|
|
|
|
Year Ended December 31, 2012
|
||||||||||||||||||
|
|
Refined Products
|
|
Crude Oil
|
|
Marine Storage
|
|
Intersegment
Eliminations
|
|
Total
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Transportation and terminals revenue
|
|
$
|
723,835
|
|
|
$
|
92,288
|
|
|
$
|
154,621
|
|
|
$
|
—
|
|
|
$
|
970,744
|
|
Product sales revenue
|
|
790,116
|
|
|
—
|
|
|
9,266
|
|
|
—
|
|
|
799,382
|
|
|||||
Affiliate management fee revenue
|
|
—
|
|
|
1,734
|
|
|
214
|
|
|
—
|
|
|
1,948
|
|
|||||
Total revenue
|
|
1,513,951
|
|
|
94,022
|
|
|
164,101
|
|
|
—
|
|
|
1,772,074
|
|
|||||
Operating expenses
|
|
267,694
|
|
|
5,229
|
|
|
58,486
|
|
|
(2,955
|
)
|
|
328,454
|
|
|||||
Cost of product sales
|
|
653,429
|
|
|
—
|
|
|
3,679
|
|
|
—
|
|
|
657,108
|
|
|||||
Earnings of non-controlled entities
|
|
—
|
|
|
(2,574
|
)
|
|
(387
|
)
|
|
—
|
|
|
(2,961
|
)
|
|||||
Operating margin
|
|
592,828
|
|
|
91,367
|
|
|
102,323
|
|
|
2,955
|
|
|
789,473
|
|
|||||
Depreciation and amortization expense
|
|
86,218
|
|
|
12,228
|
|
|
26,611
|
|
|
2,955
|
|
|
128,012
|
|
|||||
G&A expenses
|
|
87,309
|
|
|
5,420
|
|
|
16,674
|
|
|
—
|
|
|
109,403
|
|
|||||
Operating profit
|
|
$
|
419,301
|
|
|
$
|
73,719
|
|
|
$
|
59,038
|
|
|
$
|
—
|
|
|
$
|
552,058
|
|
Additions to long-lived assets
|
|
$
|
127,744
|
|
|
$
|
166,960
|
|
|
$
|
56,485
|
|
|
|
|
$
|
351,189
|
|
||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
As of December 31, 2012
|
||||||||||||||||||
Segment assets
|
|
$
|
2,530,770
|
|
|
$
|
875,005
|
|
|
$
|
656,855
|
|
|
|
|
$
|
4,062,630
|
|
||
Corporate assets
|
|
|
|
|
|
|
|
|
|
357,437
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
|
$
|
4,420,067
|
|
||||||||
Goodwill
|
|
$
|
38,369
|
|
|
$
|
12,082
|
|
|
$
|
2,809
|
|
|
|
|
$
|
53,260
|
|
||
Investments in non-controlled entities
|
|
$
|
—
|
|
|
$
|
91,629
|
|
|
$
|
15,727
|
|
|
|
|
$
|
107,356
|
|
|
|
Year Ended December 31, 2013
|
||||||||||||||||||
|
|
Refined Products
|
|
Crude Oil
|
|
Marine Storage
|
|
Intersegment
Eliminations
|
|
Total
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
Transportation and terminals revenue
|
|
$
|
801,128
|
|
|
$
|
178,409
|
|
|
$
|
158,791
|
|
|
$
|
—
|
|
|
$
|
1,138,328
|
|
Product sales revenue
|
|
738,271
|
|
|
—
|
|
|
6,398
|
|
|
—
|
|
|
744,669
|
|
|||||
Affiliate management fee revenue
|
|
—
|
|
|
13,361
|
|
|
1,248
|
|
|
—
|
|
|
14,609
|
|
|||||
Total revenue
|
|
1,539,399
|
|
|
191,770
|
|
|
166,437
|
|
|
—
|
|
|
1,897,606
|
|
|||||
Operating expenses
|
|
270,711
|
|
|
19,131
|
|
|
59,407
|
|
|
(3,179
|
)
|
|
346,070
|
|
|||||
Cost of product sales
|
|
574,703
|
|
|
—
|
|
|
3,326
|
|
|
—
|
|
|
578,029
|
|
|||||
Earnings of non-controlled entities
|
|
—
|
|
|
(3,781
|
)
|
|
(2,494
|
)
|
|
—
|
|
|
(6,275
|
)
|
|||||
Operating margin
|
|
693,985
|
|
|
176,420
|
|
|
106,198
|
|
|
3,179
|
|
|
979,782
|
|
|||||
Depreciation and amortization expense
|
|
86,926
|
|
|
24,119
|
|
|
28,006
|
|
|
3,179
|
|
|
142,230
|
|
|||||
G&A expenses
|
|
91,658
|
|
|
19,896
|
|
|
20,942
|
|
|
—
|
|
|
132,496
|
|
|||||
Operating profit
|
|
$
|
515,401
|
|
|
$
|
132,405
|
|
|
$
|
57,250
|
|
|
$
|
—
|
|
|
$
|
705,056
|
|
Additions to long-lived assets
|
|
$
|
361,134
|
|
|
$
|
199,362
|
|
|
$
|
32,563
|
|
|
|
|
$
|
593,059
|
|
||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
As of December 31, 2013
|
||||||||||||||||||
Segment assets
|
|
$
|
2,811,398
|
|
|
$
|
1,252,036
|
|
|
$
|
648,061
|
|
|
|
|
$
|
4,711,495
|
|
||
Corporate assets
|
|
|
|
|
|
|
|
|
|
109,317
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
|
$
|
4,820,812
|
|
||||||||
Goodwill
|
|
$
|
38,369
|
|
|
$
|
12,082
|
|
|
$
|
2,809
|
|
|
|
|
$
|
53,260
|
|
||
Investments in non-controlled entities
|
|
$
|
—
|
|
|
$
|
345,904
|
|
|
$
|
14,948
|
|
|
|
|
$
|
360,852
|
|
17.
|
Commitments and Contingencies
|
18.
|
Quarterly Financial Data (unaudited)
|
2012
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
Revenue
|
|
$
|
493,483
|
|
|
$
|
449,527
|
|
|
$
|
325,869
|
|
|
$
|
503,195
|
|
Total costs and expenses
|
|
$
|
372,318
|
|
|
$
|
283,724
|
|
|
$
|
248,334
|
|
|
$
|
318,601
|
|
Operating margin
|
|
$
|
178,067
|
|
|
$
|
224,181
|
|
|
$
|
138,527
|
|
|
$
|
248,698
|
|
Net income
|
|
$
|
93,524
|
|
|
$
|
137,821
|
|
|
$
|
50,522
|
|
|
$
|
153,803
|
|
Basic and diluted net income per limited partner unit
|
|
$
|
0.41
|
|
|
$
|
0.61
|
|
|
$
|
0.22
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
||||||||
2013
|
|
|
|
|
|
|
|
|
||||||||
Revenue
|
|
$
|
432,421
|
|
|
$
|
443,912
|
|
|
$
|
443,835
|
|
|
$
|
577,438
|
|
Total costs and expenses
|
|
$
|
291,967
|
|
|
$
|
260,191
|
|
|
$
|
291,586
|
|
|
$
|
355,081
|
|
Operating margin
|
|
$
|
208,893
|
|
|
$
|
251,905
|
|
|
$
|
222,649
|
|
|
$
|
296,335
|
|
Net income
|
|
$
|
112,967
|
|
|
$
|
153,640
|
|
|
$
|
125,623
|
|
|
$
|
190,007
|
|
Basic net income per limited partner unit
|
|
$
|
0.50
|
|
|
$
|
0.68
|
|
|
$
|
0.55
|
|
|
$
|
0.84
|
|
Diluted net income per limited partner unit
|
|
$
|
0.50
|
|
|
$
|
0.68
|
|
|
$
|
0.55
|
|
|
$
|
0.83
|
|
19.
|
Fair Value Disclosures
|
•
|
Cash and cash equivalents.
Cash equivalents include money market and mutual fund accounts and commercial paper. The carrying amounts reported on our consolidated balance sheets approximate fair value due to the short-term maturity or variable rates of these instruments.
|
•
|
Energy commodity derivatives deposits.
This asset represents short-term deposits we have made associated with our energy commodity derivatives contracts. The carrying amount reported on our consolidated balance sheets approximates fair value as the deposits change daily in relation to the associated contracts which are held in separate accounts.
|
•
|
Energy commodity derivatives contracts
. These include NYMEX futures and exchange-traded butane futures agreements related to petroleum products. These contracts are carried at fair value on our consolidated balance sheets and are valued based on quoted prices in active markets. See Note 13 –
Derivative Financial Instruments
for further disclosures regarding these contracts.
|
•
|
Long-term receivables.
These are primarily insurance receivables, whose fair value was determined by estimating the present value of future cash flows using a risk-free rate of interest derived from U.S. treasury rates.
|
•
|
Debt.
The fair value of our publicly traded notes was based on the prices of those notes at
December 31, 2012
and
2013
; however, where recent observable market trades were not available, prices were determined using adjustments to the last traded value for that debt issuance or by adjustments to the prices of similar debt instruments of peer entities that are actively traded. The carrying amount of borrowings, if any, under our revolving credit facility approximates fair value due to the variable rates of that instrument.
|
|
|
|
|
|
|
Fair Value Measurements as of
December 31, 2012 using:
|
||||||||||||||
Assets (Liabilities)
|
|
Carrying Amount
|
|
Fair Value
|
|
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||||
Energy commodity derivatives contracts (liabilities)
|
|
$
|
(7,338
|
)
|
|
$
|
(7,338
|
)
|
|
$
|
(7,338
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term receivables
|
|
$
|
5,135
|
|
|
$
|
5,108
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,108
|
|
Debt
|
|
$
|
(2,393,408
|
)
|
|
$
|
(2,721,985
|
)
|
|
$
|
(2,721,985
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
Fair Value Measurements as of
December 31, 2013 using:
|
||||||||||||||
Assets (Liabilities)
|
|
Carrying Amount
|
|
Fair Value
|
|
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||||
Energy commodity derivatives contracts (liabilities)
|
|
$
|
(4,502
|
)
|
|
$
|
(4,502
|
)
|
|
$
|
(4,502
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term receivables
|
|
$
|
2,730
|
|
|
$
|
2,658
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,658
|
|
Debt
|
|
$
|
(2,685,287
|
)
|
|
$
|
(2,815,210
|
)
|
|
$
|
—
|
|
|
$
|
(2,815,210
|
)
|
|
$
|
—
|
|
20.
|
Distributions
|
Payment Date
|
|
Per Unit Cash Distribution Amount
|
|
Total Cash Distribution
|
||||
2/14/2011
|
|
$
|
0.37875
|
|
|
$
|
85,398
|
|
5/13/2011
|
|
0.38500
|
|
|
86,807
|
|
||
8/12/2011
|
|
0.39250
|
|
|
88,498
|
|
||
11/14/2011
|
|
0.40000
|
|
|
90,189
|
|
||
Total
|
|
$
|
1.55625
|
|
|
$
|
350,892
|
|
|
|
|
|
|
||||
2/14/2012
|
|
$
|
0.40750
|
|
|
$
|
92,177
|
|
5/15/2012
|
|
0.42000
|
|
|
95,004
|
|
||
8/14/2012
|
|
0.47125
|
|
|
106,597
|
|
||
11/14/2012
|
|
0.48500
|
|
|
109,707
|
|
||
Total
|
|
$
|
1.78375
|
|
|
$
|
403,485
|
|
|
|
|
|
|
||||
2/14/2013
|
|
$
|
0.50000
|
|
|
$
|
113,340
|
|
5/15/2013
|
|
0.50750
|
|
|
115,040
|
|
||
8/14/2013
|
|
0.53250
|
|
|
120,707
|
|
||
11/14/2013
|
|
0.55750
|
|
|
126,374
|
|
||
Total
|
|
$
|
2.09750
|
|
|
$
|
475,461
|
|
|
|
|
|
|
Limited partner units outstanding on January 1, 2011
|
224,962,698
|
01/11—Settlement of 2008 award grants
|
505,492
|
01/11—Other
(a)
|
4,952
|
Limited partner units outstanding on December 31, 2011
|
225,473,142
|
01/12—Settlement of 2009 award grants
|
722,766
|
01/12—Other
(a)
|
4,964
|
Limited partner units outstanding on December 31, 2012
|
226,200,872
|
01/13—Settlement of 2010 award grants
|
476,682
|
01/13—Other
(a)
|
1,884
|
Limited partner units outstanding on December 31, 2013
|
226,679,438
|
(a)
|
Limited partner units issued to settle the equity-based retainer paid to independent directors of our general partner.
|
•
|
right to receive distributions of our available cash within
45 days
after the end of each quarter;
|
•
|
right to elect the board members of our general partner;
|
•
|
right to remove Magellan GP, LLC as our general partner upon a
100%
vote of outstanding unitholders;
|
•
|
right to transfer limited partner unit ownership to substitute limited partners;
|
•
|
right to receive an annual report, containing audited financial statements and a report on those financial statements by our independent public accountants, within
120 days
after the close of the fiscal year end;
|
•
|
right to receive information reasonably required for tax reporting purposes within
90 days
after the close of the calendar year;
|
•
|
right to vote according to the limited partners’ percentage interest in us at any meeting that may be called by our general partner; and
|
•
|
right to inspect our books and records at the unitholders’ own expense.
|
Item 9.
|
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
|
Item 9A.
|
Controls and Procedures
|
Item 9B.
|
Other Information
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
•
|
Director Election Proposal;
|
•
|
Executive Officers of our General Partner;
|
•
|
Section 16(a) Beneficial Ownership Reporting Compliance;
|
•
|
Code of Ethics;
|
•
|
Corporate Governance – Director Nominations; and
|
•
|
Corporate Governance – Board Committees.
|
Item 11.
|
Executive Compensation
|
•
|
Compensation of Directors and Executive Officers;
|
•
|
Compensation Committee Interlocks and Insider Participation; and
|
•
|
Compensation of Directors and Executive Officers – Compensation Committee Report.
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
•
|
Securities Authorized for Issuance Under Equity Compensation Plans; and
|
•
|
Security Ownership of Certain Beneficial Owners and Management.
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence
|
•
|
Transactions with Related Persons, Promoters and Certain Control Persons; and
|
•
|
Corporate Governance – Director Independence.
|
Item 14.
|
Principal Accountant Fees and Services
|
|
|
|
|
|
Page
|
Covered by reports of independent auditors:
|
|
|
|
||
|
||
|
||
|
||
|
||
|
||
Not covered by reports of independent auditors:
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
|
Exhibit 3
|
|
|
|
|
|
*(a)
|
|
Certificate of Limited Partnership of Magellan Midstream Partners, L.P. dated August 30, 2000, as amended on November 15, 2002 and August 12, 2003 (filed as Exhibit 3.1 to Form 10-Q filed November 10, 2003).
|
|
|
|
*(b)
|
|
Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 30, 2009).
|
|
|
|
*(c)
|
|
Amendment No. 1 dated October 27, 2011 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 28, 2011).
|
|
|
|
*(d)
|
|
Amended and Restated Certificate of Formation of Magellan GP, LLC dated November 15, 2002, as amended on August 12, 2003 (filed as Exhibit 3(f) to Form 10-K filed March 10, 2004).
|
|
|
|
*(e)
|
|
Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as Exhibit 3.2 to Form 8-K filed September 30, 2009).
|
|
|
|
Exhibit 4
|
|
|
|
|
|
*(a)
|
|
Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed May 25, 2004).
|
|
|
|
*(b)
|
|
First Supplemental Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 25, 2004).
|
|
|
|
*(c)
|
|
Second Supplemental Indenture dated as of October 15, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed October 15, 2004).
|
|
|
|
*(d)
|
|
Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed April 20, 2007).
|
|
|
|
*(e)
|
|
First Supplemental Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed April 20, 2007).
|
|
|
|
*(f)
|
|
Second Supplemental Indenture dated as of July 14, 2008 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed July 14, 2008).
|
|
|
|
*(g)
|
|
Third Supplemental Indenture dated as of June 26, 2009 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed June 26, 2009).
|
|
|
*
|
Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.
|
M
AGELLAN
M
IDSTREAM
P
ARTNERS
, L.P.
(Registrant)
|
||
|
|
|
By:
|
|
M
AGELLAN
GP, LLC, its general partner
|
|
|
|
By:
|
|
/s/ J
OHN
D. C
HANDLER
|
|
|
John D. Chandler
Senior Vice President
and Chief Financial Officer
|
Signature
|
|
Title
|
|
Date
|
|
|
|
||
/s/ M
ICHAEL
N. M
EARS
|
|
Chairman of the Board and Principal Executive Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
Michael N. Mears
|
|
|
|
|
|
|
|
||
/s/ J
OHN
D. C
HANDLER
|
|
Principal Financial and Accounting Officer of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
John D. Chandler
|
|
|
|
|
|
|
|
||
/s/ W
ALTER
R. A
RNHEIM
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
Walter R. Arnheim
|
|
|
|
|
|
|
|
||
/s/ R
OBERT
G. C
ROYLE
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
Robert G. Croyle
|
|
|
|
|
|
|
|
||
/s/ P
ATRICK
C. E
ILERS
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
Patrick C. Eilers
|
|
|
|
|
|
|
|
||
/s/ J
AMES
C. K
EMPNER
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
James C. Kempner
|
|
|
|
|
|
|
|
||
/s/ J
AMES
R. M
ONTAGUE
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
James R. Montague
|
|
|
|
|
|
|
|
||
/s/ B
ARRY
R. P
EARL
|
|
Director of Magellan GP, LLC, General Partner of Magellan Midstream Partners, L.P.
|
|
February 24, 2014
|
Barry R. Pearl
|
|
|
|
|
Exhibit No.
|
|
Description
|
|
|
|
Exhibit 3
|
|
|
|
|
|
*(a)
|
|
Certificate of Limited Partnership of Magellan Midstream Partners, L.P. dated August 30, 2000, as amended on November 15, 2002 and August 12, 2003 (filed as Exhibit 3.1 to Form 10-Q filed November 10, 2003).
|
|
|
|
*(b)
|
|
Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed September 30, 2009).
|
|
|
|
*(c)
|
|
Amendment No. 1 dated October 27, 2011 to Fifth Amended and Restated Agreement of Limited Partnership of Magellan Midstream Partners, L.P. dated September 28, 2009 (filed as Exhibit 3.1 to Form 8-K filed October 28, 2011).
|
|
|
|
*(d)
|
|
Amended and Restated Certificate of Formation of Magellan GP, LLC dated November 15, 2002, as amended on August 12, 2003 (filed as Exhibit 3(f) to Form 10-K filed March 10, 2004).
|
|
|
|
*(e)
|
|
Third Amended and Restated Limited Liability Company Agreement of Magellan GP, LLC dated September 28, 2009 (filed as Exhibit 3.2 to Form 8-K filed September 30, 2009).
|
|
|
|
Exhibit 4
|
|
|
|
|
|
*(a)
|
|
Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed May 25, 2004).
|
|
|
|
*(b)
|
|
First Supplemental Indenture dated as of May 25, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.2 to Form 8-K filed May 25, 2004).
|
|
|
|
*(c)
|
|
Second Supplemental Indenture dated as of October 15, 2004 between Magellan Midstream Partners, L.P. and SunTrust Bank, as trustee (filed as Exhibit 4.1 to Form 8-K filed October 15, 2004).
|
|
|
|
*(d)
|
|
Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed April 20, 2007).
|
|
|
|
*(e)
|
|
First Supplemental Indenture dated as of April 19, 2007 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed April 20, 2007).
|
|
|
|
*(f)
|
|
Second Supplemental Indenture dated as of July 14, 2008 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed July 14, 2008).
|
|
|
|
*(g)
|
|
Third Supplemental Indenture dated as of June 26, 2009 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed June 26, 2009).
|
|
|
|
*(h)
|
|
Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to Form 8-K filed August 16, 2010).
|
|
|
|
*(i)
|
|
First Supplemental Indenture dated as of August 11, 2010 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed August 16, 2010).
|
|
|
|
*(j)
|
|
Second Supplemental Indenture dated as of November 9, 2012 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed November 9, 2012).
|
|
|
|
*(k)
|
|
Third Supplemental Indenture dated as of October 10, 2013 between Magellan Midstream Partners, L.P. and U.S. Bank National Association, as trustee (filed as Exhibit 4.2 to Form 8-K filed October 10, 2013).
|
|
|
|
Exhibit 10
|
|
|
|
|
|
*(a)
|
|
Amended and Restated Magellan Midstream Partners Long-Term Incentive Plan dated January 22, 2013 (filed as Exhibit 10(a) to Form 10-K filed February 22, 2013).
|
|
|
|
(b)
|
|
Description of Magellan 2014 Annual Incentive Program.
|
|
|
|
(c)
|
|
Magellan GP, LLC Non-Management Director Compensation Program effective January 1, 2014.
|
|
|
|
(d)
|
|
Amended and Restated Director Deferred Compensation Plan effective January 28, 2014.
|
|
|
|
*(e)
|
|
$800,000,000 Credit Agreement dated as of October 27, 2011 among Magellan Midstream Partners, L.P., the Lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and an Issuing Bank, JPMorgan Chase Bank, N.A., as Co-Syndication Agent and an Issuing Bank, and Suntrust Bank, as Co-Syndication Agent and an Issuing Bank (filed as Exhibit 10.1 to Form 8-K filed October 28, 2011).
|
|
|
|
*(f)
|
|
First Amendment to Credit Agreement, dated as of November 21, 2013, among Magellan Midstream Partners, L.P., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (filed as Exhibit 10.1 to Form 8-K filed November 22, 2013).
|
|
|
|
*(g)
|
|
Executive Severance Pay Plan dated July 21, 2011 (filed as Exhibit 10.2 to Form 10-Q filed August 4, 2011).
|
|
|
|
(h)
|
|
Form of 2014 Phantom Unit Agreement for awards granted pursuant to the Magellan Midstream Partners Long-Term Incentive Plan.
|
|
|
|
*
|
Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.
|
EBITDA less Maintenance Capital (including commodities)
|
The combined financial metrics will be reset to the greater of actual metric results or a Target level payout at results of $955 million or more.
|
Metric
|
Weight
|
Threshold
|
Target
|
Stretch
|
EBITDA less Maintenance Capital
(1) (2)
|
65%
|
$656
|
$706
|
$741
|
Commodities
(1)
|
10%
|
$134
|
$174
|
$214
|
Operational Performance
(3)
|
15%
|
Discretionary
|
Discretionary
|
Discretionary
|
Safety - OSHA Incident Rate (IR)
(3)
|
5%
|
1.10
|
0.85
|
0.56
|
Environmental - Human Error Releases
(3)
|
5%
|
7
|
4
|
2
|
(1)
|
The overriding financial trigger will change the payout to at least a target level payout for the financial metrics when overall financial results have exceeded the trigger.
|
(2)
|
EBITDA less Maintenance Capital excludes commodities.
|
(3)
|
Payout will be zero if a fatality occurs related to activities under the control of Magellan.
|
|
Compensation
|
Timing of Payment
(1)
|
Annual Board Retainer
:
(2)
Cash
Common Units
|
$60,000
$100,000
(3)
|
Paid quarterly as of January 1
st
, April 1
st
, July 1
st
and October 1
st
As of January 1
st
|
Annual Chairman Retainer
:
(2)
Audit Committee
Compensation Committee
Conflicts Committee
Nominating and Governance Committee
Presiding Director
|
$15,000
$10,000
$10,000
$10,000
$10,000
|
Paid quarterly as of January 1
st
, April 1
st
, July 1
st
and October 1
st
|
Meeting Fees
:
Board Meeting Fees
Committee Meeting Fees
|
$1,500 per meeting
$1,500 per meeting
|
Paid quarterly as of January 1
st
, April 1
st
, July 1
st
and October 1
st
|
(1)
|
For newly elected directors or a newly appointed committee chairman, the annual board retainer and annual chairman retainer, if applicable, are payable pro-rata for the year of election.
|
(2)
|
Directors who resign from the board or relinquish their role of committee chairman after a payment date has occurred, but prior to the payment having been received, will receive a pro-rata annual board retainer and annual chairman retainer for the period of time between the payment date and the resignation/relinquishment.
|
(3)
|
The number of common units to be issued for the annual board retainer will be determined based on the closing price on the first business day immediately following the January 1
st
payment date.
|
1.
|
Grant of Phantom Units
. The Company hereby grants to the Participant effective February 3, 2014, (the “Effective Date”), subject to the terms and conditions of the Magellan Midstream Partners Long-Term Incentive Plan, as amended and restated (the “Plan”) and this Agreement, the right to be eligible to receive a target grant of
[number of units]
Phantom Units, with tandem distribution equivalent rights (“DERs”), of Magellan Midstream Partners, L.P. (the “Partnership”). The number of Units received at the end of the Restricted Period (as defined herein) will be determined based on performance criteria, employment status at that time and any other relevant provisions of the Plan and this Agreement. These Units, including the tandem DERs, are referred to in this Agreement as “Phantom Units” during the Restricted Period. Until the Phantom Units vest and are paid, the Participant shall have no rights as a unitholder of the Partnership with respect to the Phantom Units.
|
2.
|
Incorporation of Plan
. The Plan is hereby incorporated herein by reference and all capitalized terms used herein but not defined herein shall have the meaning set forth in the Plan. The Participant acknowledges receipt of a copy of the Plan and hereby accepts the Phantom Units subject to all the terms and provisions of the Plan and this Agreement.
|
3.
|
Compensation Committee of the Board Decisions and Interpretations
. The Participant hereby agrees to accept as binding, conclusive and final all decisions and interpretations of the Compensation Committee of the Board (the “Committee”) of the Company with respect to any questions arising under the Plan and this Agreement.
|
4.
|
Restricted Period of Phantom Units
. The Restricted Period begins with the Effective Date and ends with the first of the following events:
|
a.
|
December 31, 2016; or
|
b.
|
Your Termination of Affiliation (excluding any transfer to an Affiliate of the Company) with the Company, voluntarily for Good Reason, or involuntarily (other than due to Cause) within two years following a Change of Control as set forth in the Plan.
|
5.
|
Payment of Phantom Units
. To be eligible to receive payment of the Phantom Units at the end of the Restricted Period, the Participant must be employed by the Company or its Affiliates or their successors continuously throughout the Restricted Period and continues to be so employed on the last day of the Restricted Period, or must have terminated employment during the Restricted Period due to Retirement, death, or Disability. The final determination of the payout level of the Phantom Units will be based upon the performance metric outlined below in Paragraph 7 and additional conditions outlined below in Paragraph 8. In addition, at the end of the Restricted Period, the Company will pay to the Participant the value of the DERs on the gross number of Units received pursuant to the terms of this Agreement. The value of the DERs shall be the amount of all distributions per Unit that would have been earned and paid during the Restricted Period on the gross number of Units received, and no interest shall be paid on such amount. Such payment of DERs shall be in cash and used to satisfy all or part of the minimum tax withholding requirements related to the payout of the
|
6.
|
Termination of Employment Due to Retirement, Death or Disability
. In the event a Participant’s employment with the Company or its Affiliates terminates prior to the end of the Restricted Period due to Retirement, death or Disability, the initial target grant of Phantom Units will be prorated based upon the Participant’s months of employment between January 1, 2014 and December 31, 2016. Such prorated amount will continue to be restricted and subject to the terms of this Agreement until the Restricted Period ends. All Phantom Units in excess of the prorated amount shall be forfeited.
|
7.
|
Performance Metric
.
|
|
Payout Schedule
|
||
|
Threshold
50% Payout
|
Target
100% Payout
|
Stretch
200% Payout
|
2016 Distributable Cash Flow per Unit
|
$X.XX
|
$X.XX
|
$X.XX
|
(excluding commodities)
|
|
|
|
8.
|
Determination of Payout Level
.
|
a.
|
The number of Units awarded will be determined based on performance relative to the performance metric payout schedule in Paragraph 7. No payout will occur for results below the 50% payout level. The payout for results achieved between each payout level will be interpolated.
|
Average 30-day closing price* as of December 31, 2016
|
-
|
Average 30-day closing price
*
as of January 1, 2014
|
+
|
Distributions paid between January 1, 2014 through December 31, 2016
|
÷
|
Average 30-day closing price* as of January 1, 2014
|
Performance Metric Results
|
TUR Adjustment Range
|
||
Above Threshold but Below Target Results
|
|
+/- 20%*
|
|
At or Above Target but Below Stretch Results
|
|
+/- 30%
|
|
At or Above Stretch Results
|
|
+/- 50%
|
|
9.
|
Other Provisions
.
|
a.
|
The Participant understands and agrees that payments under this Agreement shall not be used for, or in the determination of, any other payment or benefit under any continuing agreement, plan, policy, practice or arrangement providing for the making of any payment or the provision of any benefits to or for the Participant or the Participant’s beneficiaries or representatives, including, without limitation, any employment agreement, any change of control severance protection plan or any employee benefit plan as defined in Section 3(3) of ERISA, including, but not limited to qualified and non-qualified retirement plans.
|
b.
|
Except as otherwise provided herein, and in the Plan, in the event that the Participant’s employment with the Company or its Affiliates or their successors terminates prior to the end of the Restricted Period, such Phantom Units shall be forfeited.
|
c.
|
The Participant acknowledges that this award and similar awards are made on a selective basis and are, therefore, to be kept confidential.
|
d.
|
Neither the Phantom Units, nor the Participant’s interest in the Phantom Units, may be sold, assigned, transferred, pledged, hedged or otherwise disposed of or encumbered at any time prior to the vesting and payment of such Phantom Units under this Agreement.
|
e.
|
If the Participant at any time forfeits any or all of the Phantom Units pursuant to this Agreement, the Participant agrees that all of the Participant’s rights to and interest in the Phantom Units shall terminate upon forfeiture without payment of consideration.
|
f.
|
The Committee shall make the determination as to whether an event has occurred resulting in the forfeiture of the Phantom Units, in accordance with this Agreement and the Plan, and all determinations of the Committee shall be final and conclusive.
|
g.
|
With respect to the right to receive payment of the Phantom Units under this Agreement, nothing contained herein shall give the Participant any rights that are greater than those of a general creditor of the Company.
|
10.
|
Notices
. All notices to the Company required hereunder shall be in writing and delivered by hand or by mail, addressed to Magellan Midstream Partners, L.P., One Williams Center, Mail Drop 28-4,
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
||||||||||
EARNINGS:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations before income taxes, extraordinary gain (loss) and cumulative effect of change in accounting principle*
|
$
|
224,705
|
|
|
$
|
307,219
|
|
|
$
|
408,669
|
|
|
$
|
435,331
|
|
|
$
|
580,575
|
|
Add: Fixed charges
|
74,750
|
|
|
97,991
|
|
|
110,946
|
|
|
120,321
|
|
|
133,511
|
|
|||||
Amortization of interest capitalized
|
715
|
|
|
729
|
|
|
739
|
|
|
755
|
|
|
816
|
|
|||||
Distributed income of equity investees
|
4,558
|
|
|
4,853
|
|
|
5,598
|
|
|
7,793
|
|
|
3,274
|
|
|||||
Less: Interest capitalized
|
(3,510
|
)
|
|
(2,943
|
)
|
|
(3,174
|
)
|
|
(6,195
|
)
|
|
(14,339
|
)
|
|||||
Total earnings
|
$
|
301,218
|
|
|
$
|
407,849
|
|
|
$
|
522,778
|
|
|
$
|
558,005
|
|
|
$
|
703,837
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FIXED CHARGES:
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense
|
$
|
69,847
|
|
|
$
|
93,436
|
|
|
$
|
105,695
|
|
|
$
|
111,786
|
|
|
$
|
116,124
|
|
Interest capitalized
|
3,510
|
|
|
2,943
|
|
|
3,174
|
|
|
6,195
|
|
|
14,339
|
|
|||||
Debt amortization expense
|
1,112
|
|
|
1,401
|
|
|
1,831
|
|
|
2,087
|
|
|
2,424
|
|
|||||
Rent expense representative of interest factor
|
281
|
|
|
211
|
|
|
246
|
|
|
253
|
|
|
624
|
|
|||||
Total fixed charges
|
$
|
74,750
|
|
|
$
|
97,991
|
|
|
$
|
110,946
|
|
|
$
|
120,321
|
|
|
$
|
133,511
|
|
Ratio of earnings to fixed charges
|
4.0
|
|
|
4.2
|
|
|
4.7
|
|
|
4.6
|
|
|
5.3
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
1)
|
Registration Statement (Form S-3 No. 333-183013) of Magellan Midstream Partners, L.P.;
|
|
2)
|
Registration Statement (Form S-8 No. 333-71670) pertaining to the Magellan Midstream Partners Long-Term Incentive Plan of Magellan Midstream Partners, L.P., as amended by Post-Effective Amendment No. 1;
|
|
3)
|
Registration Statement (Form S-8 No. 333-147206) pertaining to the Magellan Midstream Partners Long-Term Incentive Plan of Magellan Midstream Partners, L.P.; and
|
|
4)
|
Registration Statement (Form S-8 No. 333-176062) pertaining to the Magellan Midstream Partners Long-Term Incentive Plan of Magellan Midstream Partners, L.P.;
|
1.
|
I have reviewed this Annual Report on Form 10-K for the fiscal year ending December 31, 2013 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
/s/ Michael N. Mears
|
Michael N. Mears, principal executive officer
|
1.
|
I have reviewed this Annual Report on Form 10-K for the fiscal year ending December 31, 2013 (this “report”) of Magellan Midstream Partners, L.P. (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)
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Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
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5.
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The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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/s/ John D. Chandler
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John D. Chandler, principal financial and accounting officer
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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/s/ Michael N. Mears
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Michael N. Mears, Chief Executive Officer
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Date: February 24, 2014
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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/s/ John D. Chandler
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John D. Chandler, Chief Financial Officer
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Date: February 24, 2014
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