Edgar Filing: MAGELLAN MIDSTREAM PARTNERS LP

MMP 12.31.14 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	Commission file number 1-16335

Magellan Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



Delaware		73-1599053
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
Magellan GP, LLC P.O. Box 22186, Tulsa, Oklahoma		74121-2186
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (918) 574-7000

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common Units representing limited partnership interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

The aggregate market value of the registrant’s voting and non-voting limited partner units held by non-affiliates computed by reference to the price at which the limited partner units were last sold as of June 30, 2014 was $19,041,935,144.

As of February 19, 2015, there were 227,426,329 limited partner units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement prepared for the solicitation of proxies in connection with the 2015 Annual Meeting of Limited Partners are to be incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS



		Page
	PART I
ITEM 1.	Business	1
ITEM 1A.	Risk Factors	17
ITEM 1B.	Unresolved Staff Comments	35
ITEM 2.	Properties	35
ITEM 3.	Legal Proceedings	35
ITEM 4.	Mine Safety Disclosures	35
	PART II
ITEM 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
ITEM 6.	Selected Financial Data	38
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	42
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
ITEM 8.	Financial Statements and Supplementary Data	69
ITEM 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	121
ITEM 9A.	Controls and Procedures	121
ITEM 9B.	Other Information	121
	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	122
ITEM 11.	Executive Compensation	122
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	122
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	122
ITEM 14.	Principal Accountant Fees and Services	122
	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	123

MAGELLAN MIDSTREAM PARTNERS, L.P.

FORM 10-K

PART I

Item 1. Business

(a) General Development of Business

We are a Delaware limited partnership formed in August 2000 and our limited partner units are traded on the New York Stock Exchange under the ticker symbol “MMP.” Magellan GP, LLC, a wholly-owned Delaware limited liability company, serves as our general partner. Unless indicated otherwise, the terms “our,” “we,” “us” and similar language refer to Magellan Midstream Partners, L.P. together with its subsidiaries.

(b) Financial Information About Segments

See Part II—Item 8. Financial Statements and Supplementary Data.

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of December 31, 2014, our asset portfolio, including the assets of our joint ventures, consisted of:


•	our refined products segment, comprised of 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 1,600 miles of crude oil pipelines and storage facilities with an aggregate storage capacity of approximately 21 million barrels, of which 12 million is used for leased storage. We own a 50% interest in BridgeTex Pipeline Company, LLC ("BridgeTex"), which began commercial operation of the BridgeTex pipeline in September 2014, and these assets are now included in the pipeline miles and storage capacity amounts of our crude oil segment; and


•	our marine storage segment, consisting of five marine terminals located along coastal waterways with an aggregate storage capacity of approximately 26 million barrels.

Industry Background

The U.S. petroleum products transportation and distribution system links sources of crude oil supply with refineries and ultimately with end users of petroleum products. This system is comprised of a network of pipelines, terminals, storage facilities, waterborne vessels, railcars and trucks. For transportation of petroleum products, pipelines are generally the safest, lowest-cost alternative for intermediate and long-haul movements between different markets. Throughout the distribution system, terminals play a key role in facilitating product movements by providing storage, distribution, blending and other ancillary services.

Terminology common in our industry includes the following terms, which describe products that we transport, store and distribute through our pipelines and terminals:


•	refined products, 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;


•	liquefied petroleum gases, or LPGs, are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs include butane and propane;


•	blendstocks, 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;


•	heavy oils and feedstocks, 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;


•	crude oil and condensate, are used as feedstocks by refineries and petrochemical facilities;


•	biofuels, such as ethanol and biodiesel, are increasingly required by government mandates; and


•	ammonia, is primarily used as a nitrogen fertilizer.

Except for ammonia, we use the term petroleum products to describe any, or a combination, of the above-noted products.

Description of Our Businesses

REFINED PRODUCTS

Our refined products segment consists of our common carrier refined products pipeline system, independent terminals and our ammonia pipeline system. Our refined products pipeline system is the longest common carrier pipeline system for refined products and LPGs in the U.S., extending approximately 9,500 miles from the Gulf Coast covering a 15-state area across the central U.S. The system includes approximately 42 million barrels of aggregate usable storage capacity at 53 connected terminals. Our network of independent terminals includes 27 refined products terminals with 6 million barrels of storage located primarily in the southeastern U.S. and connected to third-party common carrier interstate pipelines, including Colonial and Plantation pipelines. Our 1,100-mile common carrier ammonia pipeline system extends from production facilities in Texas and Oklahoma to terminals in agricultural demand centers in the Midwest.

Our refined products segment accounted for the following percentages of our consolidated revenue, operating margin and total assets:



	Year Ended December 31,
	2012	2013	2014
Percent of consolidated revenue	86%	81%	78%
Percent of consolidated operating margin	75%	71%	68%
Percent of consolidated total assets	57%	58%	52%

See Note 16—Segment Disclosures in the accompanying consolidated financial statements in Item 8 for additional financial information about our refined products segment.

Operations. Transportation, Terminalling and Ancillary Services. During 2014, 69% of the refined products segment's revenue (excluding product sales revenue) was generated from transportation tariffs on volumes shipped on our refined products pipeline system. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”) or appropriate state agency. Included as part of these tariffs are charges for terminalling and storage of products at 33 of our pipeline system's 53 connected terminals. Revenue from terminalling and storage at the other 20 terminals on our refined products pipeline system is at privately negotiated rates.

In 2014, the products transported on our refined products pipeline system were comprised of 57% gasoline, 36% distillates and 7% aviation fuel and LPGs. The operating statistics below reflect our pipeline system’s operations for the periods indicated:



	Year Ended December 31,
	2012	2013	2014
Shipments (million barrels):
Refined products:
Gasoline	223.7	239.7	256.1
Distillates	136.7	146.5	163.1
Aviation fuel	21.5	21.1	23.0
LPGs	8.5	7.8	9.9
Total shipments	390.4	415.1	452.1

Our refined products pipeline system generates additional revenue from leasing pipeline and storage tank capacity to shippers and from providing services such as terminalling, ethanol and biodiesel unloading and loading, additive injection, custom blending, laboratory testing and data services to shippers, which are performed under a mix of “as needed,” monthly and long-term agreements.

Our independent terminals generate revenue primarily by charging fees based on the amount of product delivered through our facilities and from ancillary services such as additive injections and ethanol blending. Our ammonia pipeline system generates revenue primarily through transportation tariffs on volumes shipped.

Substantially all of the transportation and throughput services we provide are for third parties, and we do not take title to those products. We do take title to products related to our butane blending and fractionation activities on our refined products pipeline system, and we previously took title to linefill related to a portion of the Houston-to-El Paso pipeline segment until the conversion of that pipeline segment from refined products service to crude oil service in 2012. Furthermore, under our tariffs, we are allowed to deduct a prescribed quantity of the products our shippers transport on our pipeline to compensate us for lost product during shipment due to metering inaccuracies, intermingling of products between batches (transmix), evaporation or other events that result in volume losses during the shipment process. To the extent we can manage our volume losses below the deducted amount, our operating expenses are reduced by the value of those excess products.

Commodity-Related Activities. Product sales revenue in our refined products segment primarily results from our butane blending and transmix fractionation activities, as well as from the sale of terminal product gains at our independent terminals. Our butane blending activity primarily involves purchasing butane and blending it into gasoline, which creates additional gasoline available for us to sell. This activity is limited by seasonal changes in gasoline vapor pressure specification requirements and by the varying quality of the gasoline products delivered to us. We typically hedge the economic margin from this blending activity by entering into either forward physical or New York Mercantile Exchange ("NYMEX") gasoline futures contracts at the time we purchase the related butane. These blending activities accounted for approximately 96% of the total product margin for the refined products segment during 2014. If the differential between the cost of butane and the price of gasoline were to narrow, which generally occurs when crude oil prices decrease (as has occurred in recent months), the product margin we earn from these activities will be negatively impacted. We also operate three fractionators along our pipeline system that separate transmix, which is an unusable mixture of various refined products, into its original components. In addition to fractionating the transmix that results from our pipeline operations, we also purchase and fractionate transmix from third parties and sell the resulting separated refined products.

Product margin from commodity-related activities in our refined products segment was $136.7 million, $163.6 million and $279.7 million for the years ended December 31, 2012, 2013 and 2014, respectively. The amount of margin we earn from these activities fluctuates with changes in petroleum prices. Product margin is not a generally accepted accounting principle ("GAAP") financial measure, but its components are determined in accordance with GAAP. Product margin, which is calculated as product sales revenue less cost of product sales, is used by

management to evaluate the profitability of our commodity-related activities. The components of product margin included in operating profit, the nearest GAAP measurement, is provided in Note 16—Segment Disclosures to the consolidated financial statements included in Item 8 of this report.

Our policy is generally to purchase only those products necessary to conduct our normal business activities. We do not acquire physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Our butane blending and fractionation activities require us to carry significant levels of inventories. We use derivative instruments to hedge against commodity price changes and manage risks associated with our various commodity purchase and sale obligations as well as for tank bottom and certain linefill inventories. Our risk management policies and procedures are designed to monitor our derivative instrument positions, as well as physical volumes, grades, locations, delivery schedules and storage capacity to help ensure that our hedging activities address our risks. Our strategies are primarily intended to mitigate and manage price risks that are inherent in our butane blending and fractionation activities and tank bottom and certain linefill inventories.

Markets and Competition. Shipments originate on our refined products pipeline system from direct connections to refineries, through interconnections with other interstate pipelines or at our terminals for transportation and ultimate distribution to retail gasoline stations, truck stops, railroads, airports and other end users. Through direct refinery connections and interconnections with other interstate pipelines, our refined products system can access approximately 48% of U.S. refining capacity, and in particular is well-connected to Gulf Coast, mid-continent and Chicago-area refineries. Our system is dependent on the ability of refiners and marketers to meet the demand for those products in the markets they serve through their shipments on our pipeline system. According to May 2014 projections provided by the Energy Information Administration, which represent the latest long-term outlook at this point, the demand for refined products in the primary market areas served by our pipeline system, known as the West North Central and West South Central census districts, is expected to remain relatively stable over the next 10 years. As a result of its extensive connections to multiple refining regions, our pipeline system is well positioned to accommodate any demand or supply shifts that may occur.

In 2014, approximately 72% of the products transported on our refined products pipeline system originated from 19 direct refinery connections and 28% originated from connections with other pipelines or terminals.

As set forth in the table below, our system is directly connected to and receives product from the following 19 refineries:

Major Origins—Refineries (Listed Alphabetically)




Company		Refinery Location
Black Elk Refining		Newcastle, WY
Calumet Specialty Products		Superior, WI
CVR Energy		Coffeyville, KS
CVR Energy		Wynnewood, OK
Flint Hills Resources		Rosemount, MN
HollyFrontier		El Dorado, KS
HollyFrontier		Tulsa, OK
HollyFrontier		Cheyenne, WY
Marathon		Galveston Bay, TX
Marathon		Texas City, TX
National Cooperative Refining Association		McPherson, KS
Northern Tier		St. Paul, MN
Phillips 66		Ponca City, OK
Sinclair		Evansville, WY
Suncor Energy		Commerce City, CO
Valero		Ardmore, OK
Valero		Houston, TX
Valero		Texas City, TX
Western Refining		El Paso, TX

Our system is also connected to multiple pipelines and terminals, including those shown in the table below:

Major Origins—Pipeline and Terminal Connections (Listed Alphabetically)




Pipeline/Terminal	Connection Location	Source of Product

BP	Manhattan, IL	Whiting, IN refinery
CHS	Fargo, ND	Laurel, MT refinery
Explorer	Glenpool, OK; Mt. Vernon, MO; Dallas, TX; East Houston, TX	Various Gulf Coast refineries
Holly Energy Partners	Duncan, OK; El Paso, TX	Big Spring, TX refinery, Artesia, NM refinery
Kinder Morgan	Galena Park and Pasadena, TX	Various Gulf Coast refineries and imports
Magellan Terminals Holdings	Galena Park, TX	Various Gulf Coast refineries and imports
Mid-America (Enterprise)	El Dorado, KS	Conway, KS storage
NuStar Energy	El Dorado, KS; Minneapolis, MN; Denver, CO	Various OK & KS refineries, Mandan, ND refinery, McKee, TX refinery
ONEOK Partners	Plattsburg, MO; Des Moines, IA; Wayne, IL	Bushton, KS storage and Chicago, IL area refineries
Phillips 66	Kansas City, KS; Denver, CO; Casper, WY	Borger, TX refinery, various Billings, MT area refineries
Shell	East Houston, TX	Deer Park, TX refinery
West Shore	Chicago, IL	Various Chicago, IL area refineries

In certain markets, barge, truck or rail provide an alternative source for transporting refined products; however, pipelines are generally the lowest-cost and environmentally safest alternative for refined products movements between different markets. As a result, our pipeline system's most significant competitors are other pipelines that serve the same markets.

Competition with other pipeline systems is based primarily on transportation charges, quality of customer service, proximity to end users and longstanding customer relationships. However, given the different supply sources on each pipeline, pricing at either the origin or terminal point on a pipeline may outweigh transportation costs when customers choose which pipeline to use.

Another form of competition for pipelines is the use of exchange agreements among shippers. Under these agreements, a shipper agrees to supply a market near its refinery or terminal in exchange for receiving supply from another refinery or terminal in a more distant market. These agreements allow the two parties to reduce the volumes transported and the transportation fees paid to us. We compete with these alternatives through price incentives and through long-term commercial arrangements with potential exchange partners.

Government mandates increasingly require the use of renewable fuels, particularly ethanol. Due to technical and operational concerns, pipelines have generally not shipped ethanol, and most ethanol is transported by railroad or truck. The increased use of ethanol has and will continue to compete with shipments on our pipeline system. However, most of our terminals have the necessary infrastructure to blend ethanol with refined products and we earn revenue for these services.

Our independent terminals receive product primarily from the interstate pipelines to which they are connected and serve the retail, industrial and commercial sales markets along those pipelines. Demand for our services is driven primarily by end user demand in those markets. Our terminals compete with other independent terminal operators as well as integrated oil companies on the basis of terminal location and versatility, services provided and price.

Our ammonia pipeline system receives product from ammonia production facilities in Texas and Oklahoma and delivers to agricultural markets in the Midwest, where the ammonia is used by farmers as a nitrogen fertilizer. Our system competes primarily with ammonia shipped by rail carriers, and in certain markets with a third-party ammonia pipeline.

Customers and Contracts. Our refined products pipeline system ships products for several different types of customers, including independent and integrated oil companies, wholesalers, retailers, traders, railroads, airlines and regional farm cooperatives. End markets for refined products deliveries are primarily retail gasoline stations, truck stops, farm cooperatives, railroad fueling depots and military and commercial jet fuel users. LPG shippers include wholesalers and retailers that, in turn, sell to commercial, industrial, agricultural and residential heating customers, as well as utilities who use propane as a fuel source. Published tariffs serve as contracts and shippers nominate the volume to be shipped up to a month in advance. In addition, we enter into agreements with shippers that commonly result in payment, volume and/or term commitments in exchange for reduced tariff rates or capital expansion commitments on our part. For 2014, approximately 47% of the shipments on our pipeline system were subject to these agreements. The average remaining life of these contracts was approximately four years as of December 31, 2014, with remaining terms of up to 14 years. While many of these agreements do not represent guaranteed volumes, they do reflect a significant level of shipper commitment to our refined products pipeline system.

For the year ended December 31, 2014, our refined products pipeline system had approximately 60 transportation customers. The top 10 shippers included independent refining companies, integrated oil companies and farm cooperatives. Revenue attributable to these top 10 shippers for the year ended December 31, 2014 represented 44% of total revenue for our refined products segment and 57% of revenue excluding product sales.

Customers of our independent terminals include independent and integrated oil companies, retailers, wholesalers and traders. Contracts vary in term and commitment and typically renew automatically at the end of the contract period.

Our ammonia pipeline system ships product for three customers who own production facilities connected to our system. We have rolling three-year agreements with these customers that contain minimum volume commitments whereby a customer must pay for unused pipeline capacity if the customer fails to ship its committed volume.

Product sales are primarily to trading and marketing companies. These sales agreements are generally short-term in nature.

CRUDE OIL

Our crude oil segment is comprised of approximately 1,600 miles of crude oil pipelines with an aggregate storage capacity of approximately 21 million barrels of storage, of which 12 million is used for leased storage, including: (i) the Longhorn crude oil pipeline; (ii) our Cushing, Oklahoma storage terminal; (iii) the Houston-area crude oil distribution system; (iv) the crude oil components of our East Houston, Texas terminal; (v) the condensate components of our Corpus Christi, Texas terminal; (vi) the Gibson, Louisiana terminal; and (vii) the assets owned by our Osage Pipe Line Company, LLC (“Osage”), Double Eagle Pipeline LLC (“Double Eagle”) and BridgeTex Pipeline Company, LLC ("BridgeTex") joint ventures.

Our crude oil segment accounted for the following percentages of our consolidated revenue, operating margin and total assets:



	Year Ended December 31,
	2012	2013	2014
Percent of consolidated revenue	5%	10%	14%
Percent of consolidated operating margin	12%	18%	23%
Percent of consolidated total assets	20%	26%	35%

See Note 16–Segment Disclosures in the accompanying consolidated financial statements in Item 8 for additional financial information about our crude oil segment.

Operations. Our crude oil assets are strategically located to serve crude oil supply, trading and demand centers. Revenue is generated primarily through transportation tariffs paid by shippers on our crude oil pipelines and storage fees paid by our crude oil terminal customers. In addition, we earn revenue for ancillary services including throughput fees. We generally do not take title to the products we ship or store for our crude oil customers. We do own certain tank bottoms and linefill assets at our crude oil terminal in Cushing, Oklahoma that are not sold in the normal course of business and are classified as long-term assets on our consolidated balance sheets. In addition, we are allowed under our tariffs to deduct a prescribed quantity of the crude oil our shippers transport on our pipeline to compensate us for lost product during shipment due to metering inaccuracies, evaporation or other events that result in volume losses during the shipment process. To the extent we can manage our volume losses below the deducted amount, our operating expenses are reduced by the value of those excess products.

The 450-mile Longhorn crude oil pipeline began transporting crude oil from the Permian Basin in West Texas to Houston, Texas in early 2013 when we completed the project to reverse a portion of our Houston-to-El Paso pipeline segment, which had previously transported refined products, and convert it to crude oil service. Shipments originate on the Longhorn pipeline in Crane or Midland, Texas via interconnections with crude oil gathering systems owned by third parties and are delivered to our terminal at East Houston or to various points on the Houston ship channel, including multiple refineries connected to our Houston-area crude oil distribution system that terminates in Texas City, Texas. During 2014, we expanded the Longhorn pipeline by 50,000 barrels per day to an operating capacity of 275,000 barrels per day.

Our East Houston terminal includes approximately five million barrels of crude oil storage, with approximately one million barrels used for leased storage and four million barrels dedicated to the operation of the Longhorn and BridgeTex pipelines, which deliver crude oil to our East Houston terminal. (See discussion of our BridgeTex joint venture under Joint Venture Activities below.) Our East Houston terminal is also connected to our Houston-area crude oil distribution system and to third-party pipelines, including the Houston-to-Houma pipeline. We are building additional operational storage at this location to facilitate movements on the Longhorn pipeline.

Our Houston-area crude oil distribution system consists of more than 100 miles of pipeline segments that connect our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and Texas City, Texas. In addition, it is directly connected to other third-party crude oil pipelines providing us access to crude oil from the Eagle Ford shale, the strategic crude oil hub in Cushing, Oklahoma and crude oil imports. In November 2014, we expanded our Houston-area crude oil distribution system by acquiring a 40-mile crude oil pipeline in the Houston Gulf Coast area.

Our Cushing terminal consists of approximately 12 million barrels of crude oil storage, of which two million barrels are reserved for working inventory, leaving 10 million barrels that we can lease. The facility primarily receives and distributes crude oil via the multiple common carrier pipelines that terminate in and originate from the Cushing crude oil trading hub, as well as short-haul pipeline connections with neighboring crude oil terminals.

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.

Our Corpus Christi, Texas terminal includes approximately two million barrels of condensate storage, with a portion used for leased storage and a portion used in conjunction with our Double Eagle joint venture discussed below. These assets receive product primarily from barges and pipelines that connect to our terminal and are for further distribution to end users by pipeline, via waterborne vessels or our condensate off-loading truck rack.

Joint Venture Activities. We own a 50% interest in Osage, which owns a 135-mile pipeline that transports crude oil from Cushing to two refineries in Kansas. We receive a management fee for serving as the operator of Osage.

We own a 50% interest in Double Eagle, a joint venture with Kinder Morgan Energy Partners, L.P. ("Kinder"), that transports condensate from the Eagle Ford shale formation in South Texas via a 195-mile pipeline to our terminal in Corpus Christi. An affiliate of Kinder serves as the operator of Double Eagle.

We own a 50% interest in BridgeTex, a joint venture with an affiliate of Plains All American Pipeline, L.P. BridgeTex was formed to construct and operate the BridgeTex pipeline system, which consists of a 400-mile pipeline capable of transporting up to 300,000 barrels per day of Permian Basin crude oil from Colorado City, Texas to our East Houston terminal as well as operational crude oil storage at Colorado City of approximately one million barrels. The BridgeTex pipeline began operations in September 2014. We received construction fees and continue to receive operational management fees from BridgeTex, which we report as affiliate management fee revenue on our consolidated statements of income.

Markets and Competition. Market conditions experienced by our crude oil pipelines vary significantly by location. Our Longhorn and BridgeTex pipelines deliver Permian Basin production to trading and demand centers in the Houston area, and consequently depend on the level of production in the Permian Basin for supply. Demand for shipments to the Houston area is driven primarily by the utilization of West Texas crude oil by Gulf Coast refineries and the price for crude oil on the Gulf Coast relative to its price at Cushing, Oklahoma. Permian Basin production may vary based on numerous factors including overall crude oil prices and changes in costs of production, while Gulf Coast refinery demand for Permian Basin production may change based on relative prices for competing crude oil or changes by refineries to their crude oil processing slates, as well as by overall domestic and international demand for refined products. Our Longhorn and BridgeTex pipelines compete with alternative outlets for Permian Basin production, including pipelines that transport crude oil to the Cushing crude oil trading hub as well as other

pipelines that currently transport or new pipelines that may transport Permian Basin crude to the Gulf Coast. These pipelines also compete with truck and rail alternatives for Permian Basin barrels. Indirectly, these pipelines also compete with other alternatives for delivering similar quality crude oil to the Gulf Coast, including pipelines from other producing basins such as the Eagle Ford shale or Gulf of Mexico, as well as waterborne imports. Competition is based primarily on tariff rates, proximity to both supply and demand centers, connectivity and customer relationships.

Volumes on our Houston-area crude oil distribution system are driven by our customers' demand for distribution of crude oil between our system's various connections and as a result are affected in part by changes in origins and destinations of crude oil processed in or distributed through the Gulf Coast region. Our system competes with other distribution facilities in the Houston area based primarily on tariff rates and connectivity.

Our crude oil storage facilities in Cushing serve customers who value Cushing's location as an interchange point for numerous interstate pipelines and its status as a crude oil trading hub. Demand for crude oil storage in Cushing could be affected by changes in crude oil pipeline flows that change the volume of crude oil that flows through or is stored in Cushing, as well as by developments of alternative trading hubs that reduce Cushing's relative importance. In addition, demand for our storage services in Cushing could be affected by crude oil price volatility or price structures or by regulatory or financial conditions that affect the ability of our customers to store or trade crude oil. We compete in Cushing with numerous other storage providers, with competition based on a combination of connectivity, storage rates and other terms, customer service and customer relationships.

The Double Eagle pipeline depends on condensate production from the Eagle Ford shale formation for its supply and competes with other pipelines that are capable of transporting condensate from the Eagle Ford production area. Competition is based primarily on tariff rates, delivery mode and customer service. The demand for Double Eagle's services could be affected by changes in Eagle Ford condensate production or changes in demand for different grades of condensate. Demand for our condensate storage at Corpus Christi is subject to similar market conditions and competitive forces.

Customers and Contracts. We ship crude oil as a common carrier for several different types of customers, including crude oil producers, end users such as refiners, and marketing and trading companies. Published transportation tariffs filed with the FERC or the Texas Railroad Commission serve as contracts to ship on our crude oil pipelines, and shippers nominate volumes to be transported up to a month in advance, with rates varying by origin and destination. In addition, tariff rates can vary with the volume of spot barrel movements on our pipelines, which generally ship at higher rates than those charged to committed shippers. Based on generally accepted practices, we reserve 10% of the shipping capacity of our pipelines for spot shippers. We have secured long-term agreements to support our crude oil pipeline assets. Specifically with regard to our Longhorn pipeline, all of the volumes shipped on that system are supported by long-term take-or-pay customer agreements. For 2014, approximately 50% of the shipments on our wholly-owned crude oil pipelines were subject to long-term agreements. The average remaining life of these contracts was approximately four years as of December 31, 2014. As of December 31, 2014, 100% of our crude oil storage used for leased storage was under contracts with terms in excess of one year, with an average remaining life of approximately two years. These contracts obligate the customer to pay for storage capacity reserved even if not used by the customer. Double Eagle and BridgeTex also have long-term contracts which support the capital investments in these pipeline systems.

MARINE STORAGE

We own and operate five marine storage terminals located along coastal waterways with approximately 25 million barrels of aggregate storage capacity and approximately one million additional barrels of storage jointly owned through our Texas Frontera, LLC joint venture ("Texas Frontera"). Our marine terminals provide distribution, storage, blending, inventory management and additive injection services for refiners and other large end users of petroleum products.

Our marine storage segment accounted for the following percentages of our consolidated revenue, operating margin and total assets:



	Year Ended December 31,
	2012	2013	2014
Percent of consolidated revenue	9%	9%	8%
Percent of consolidated operating margin	13%	11%	9%
Percent of consolidated total assets	15%	13%	12%

See Note 16–Segment Disclosures in the accompanying consolidated financial statements in Item 8 for additional financial information about our marine storage segment.

Operations. Our marine storage terminals generate revenue primarily through providing long-term storage services for a variety of customers. Refiners and chemical companies typically use our storage terminals due to tankage constraints at their facilities or the specialized handling requirements of the stored product. We also provide storage services to marketers and traders that require access to large storage capacity. Because the rates charged at these terminals are unregulated, the marketplace determines the prices we charge for our services. In general, we do not take title to the products that are stored in or distributed from our marine terminals.

Our Galena Park, Texas marine terminal is located along the Houston ship channel and is our largest marine facility with 13 million barrels of usable storage capacity. This facility currently stores a mix of refined products, blendstocks, heavy oils and crude oil. This facility receives and distributes products by pipeline, truck, rail, barge and ship. An advantage of our Galena Park facility is that it provides our customers with access to multiple common carrier pipelines, deep-water port facilities that accommodate both ship and barge traffic and loading and unloading facilities for trucks and rail cars. We also own a 50% interest in Texas Frontera, which owns approximately one million additional barrels of storage at our Galena Park terminal. This storage is leased under a long-term agreement with an affiliate of Texas Frontera. In addition to our portion of the net earnings of the joint venture, which we recognize as earnings of non-controlled entities, we receive a fee for operating the storage tanks of Texas Frontera, which we recognize as affiliate management fee revenue.

Our New Haven, Connecticut marine terminal is located on the Long Island Sound near the New York Harbor and has four million barrels of usable storage capacity and primarily handles heating oil, refined products, asphalt, ethanol and biodiesel. This facility receives and distributes products by pipeline, ship, barge and truck.

Our Marrero, Louisiana marine terminal is located on the Mississippi River and has approximately three million barrels of usable storage capacity. This facility primarily handles heavy oils, distillates and asphalt. We receive products at our Marrero terminal by ship and barge and deliver products from Marrero by rail, ship, barge and truck.

Our Wilmington, Delaware marine terminal is located at the Port of Wilmington along the Delaware River. The facility includes almost three million barrels of usable storage and primarily handles refined products, ethanol and heavy oils. We receive products at our Wilmington terminal by ship and barge and deliver products from this facility by truck, ship and barge.

Our Corpus Christi, Texas marine terminal is located near local refineries and petrochemical plants and includes almost two million barrels of usable storage capacity utilized for heavy oils and feedstocks. We receive and deliver products at our Corpus Christi facility primarily by ship, barge, truck and pipeline.

Markets and Competition. We believe that the continued strong demand for storage and ancillary services at our marine terminals results from our cost-effective distribution services and key transportation links, which provide us with a stable base of storage fee revenue. The ancillary services we provide at our marine terminals, such as product heating, blending, mixing and additive injection, attract additional demand for our storage services and

result in additional revenue opportunities. Demand can be influenced by projected changes in and volatility of petroleum product prices.

Several major and integrated oil companies have their own proprietary storage terminals that are or have been used in their refining operations. If these companies choose to shut down their refining operations and elect to store and distribute petroleum products through their proprietary terminals, we could experience increased competition for the services we provide. This trend is especially evident in the northeastern U.S., where our Wilmington, Delaware facility has experienced reduced utilization. In addition, other companies have facilities that offer competing storage and distribution services, and a significant amount of additional competing storage capacity has been constructed recently.

Customers and Contracts. We have long-standing relationships with refineries, suppliers and traders at our marine terminals. During 2014, approximately 90% of our storage terminal capacity was utilized with the remaining 10% not utilized due in part to tank integrity work throughout the year. As of December 31, 2014, approximately 77% of our usable storage capacity was under contracts with remaining terms in excess of one year or that renew on an annual basis. The average remaining life of our storage contracts was approximately three years as of December 31, 2014. These contracts obligate the customer to pay for terminal capacity reserved even if not used by the customer.

GENERAL BUSINESS INFORMATION

Major Customers

One customer accounted for 14%, 8% and 12% of our consolidated total revenue in 2012, 2013 and 2014, respectively. No other customer accounted for more than 10% of our consolidated revenues during these years. The majority of revenue from this customer resulted from sale of refined products that were generated in connection with our butane blending and fractionation activities, which are activities conducted by our refined products segment. We believe that other companies would purchase the petroleum products from us if this customer were unable or unwilling to do so.

Regulation

Interstate Tariff Regulation. Our refined products pipeline system's interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and rules and orders promulgated pursuant thereto. FERC regulation requires that interstate pipeline rates, including rates for all petroleum products, be filed with the FERC and posted publicly and that these rates be nondiscriminatory and “just and reasonable” when taking into account our cost of service. The rates of our interstate pipeline, which include approximately 40% of the shipments on our refined products pipeline system, are regulated by the FERC primarily through an index methodology, which for the five-year period beginning July 1, 2011 was set at the annual change in the producer price index for finished goods (“PPI-FG”) plus 2.65%. In general, we are permitted to raise our rates up to the ceiling established by the PPI-FG index plus 2.65%. The FERC's current indexing methodology will be revised in 2016. Any change in the current indexing methodology will impact our ability to raise our rates in the future. Rate increases and the overall level of our rates may be subject to challenge by the FERC or shippers. If the FERC determines that our rates are not just and reasonable, we may be required to reduce our rates and/or pay reparations for up to two years of over-earning. As an alternative to cost-of-service based rates, interstate pipeline companies may elect to support rate filings by obtaining authority to charge market-based rates, by settlement with respect to existing rates or through an agreement with an unaffiliated person who intends to use the related service. Approximately 60% of our refined products pipeline system's markets are either subject to regulations by the states in which we operate, or are deemed competitive by the FERC, in which case these rates can be adjusted at our discretion based on competitive factors.

The Surface Transportation Board, a part of the U.S. Department of Transportation, has jurisdiction over interstate pipeline transportation and rate regulations of ammonia. Transportation rates must be reasonable and a pipeline carrier may not unreasonably discriminate among its shippers.

Intrastate Tariff Regulation. Some shipments on our refined products and ammonia pipeline systems, and substantially all shipments on our wholly-owned crude oil pipelines move within a single state and thus are considered to be intrastate commerce. Our pipelines are subject to certain regulations with respect to such intrastate transportation by state regulatory authorities in the states of Colorado, Illinois, Iowa, Kansas, Minnesota, Nebraska, Oklahoma, Texas and Wyoming. In most instances, state commissions have not initiated investigations of the rates or practices of these pipelines in the absence of shipper complaints.

Commodity Market Regulation. Our conduct in petroleum markets and in hedging our exposure to commodity price fluctuations must comply with laws and regulations that prohibit market manipulation.

Wholesale sales of petroleum are subject to provisions of the Energy Independence and Security Act of 2007 (“EISA”) and regulations by the Federal Trade Commission ("FTC"). Under the EISA, the FTC issued a rule that prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined products. The FTC rule also bans intentional failures to state a material fact when the omission makes a statement misleading and distorts, or is likely to distort, market conditions for any product covered by the rule. The FTC holds substantial enforcement authority under the EISA, including authority to request that a court impose fines of up to $1 million per day per violation. FERC may also order reparations and suspend tariffs, including our authority to charge negotiated rates, for violations of the Interstate Commerce Act in connection with interstate oil pipeline transportation.

Under the Commodity Exchange Act, the Commodity Futures Trading Commission ("CFTC") is directed to prevent price manipulations for the commodities markets, including the physical energy, futures and swaps markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the physical energy, futures and swaps markets. The CFTC also has statutory authority to assess fines of up to the greater of $1 million or triple the monetary gain for violations of its anti-market manipulation regulations.

Should we violate these laws and regulations, we could be subject to material penalties, changes in the rates we can charge and liability to third parties.

Renewable Fuel Standard. Since the enactment of the Energy Policy Act of 2005, we became an obligated party under the Environmental Protection Agency's ("EPA") Renewable Fuel Standard (“RFS”) and are required to satisfy our Renewable Volume Obligation (“RVO”) on an annual basis. To meet the RVO, the gasoline products we produce in our butane blending activities must either contain the mandated renewable fuel components, or credits must be purchased to cover any shortfall. We met our RVO requirements for 2014 and expect to satisfy the requirements for 2015 mainly through the purchase of credits, known as Renewable Identification Numbers ("RINs"). As the RFS program is currently structured, the RVO of all obligated parties will increase annually unless adjusted by the EPA. The ability to incorporate increasing volumes of renewable fuel components into fuel products remains limited. This phenomenon, better known as the “blend wall”, is expected to present compliance challenges to the RFS standards in future years unless Congress takes action to reduce the renewable fuels requirements.

Environmental, Maintenance, Safety & Security

General. The operation of our pipeline systems, terminals and associated facilities is subject to strict and complex laws and regulations relating to the protection of the environment and workplace safety. These bodies of laws and regulations govern many aspects of our business including the work environment, the generation and disposal of waste, discharge of process and storm water, air emissions, remediation requirements and facility design requirements to protect against releases into the environment. We believe our assets are operated and maintained in material compliance with these laws and regulations and in accordance with other generally accepted industry standards and practices.

Environmental. Our estimates for remediation costs assume that we will be able to use traditionally acceptable remedial and monitoring methods, as well as associated engineering or institutional controls to comply with applicable regulatory requirements. These estimates include the cost of performing environmental assessments,

remediation and monitoring of the impacted environment such as soils, groundwater and surface water conditions. Our recorded remediation costs are estimates and total remediation costs may differ from current estimated amounts.

We may experience future releases of regulated materials into the environment or discover historical releases that were previously unidentified or not assessed. While an asset integrity and maintenance program designed to prevent, promptly detect and address releases is an integral part of our operations, damages and liabilities arising out of any environmental release from our assets identified in the future could have a material adverse effect on our results of operations, financial position and cash flow.

Environmental Liabilities. Liabilities recognized for estimated environmental costs were $38.5 million and $36.3 million at December 31, 2013 and 2014, respectively. Environmental liabilities have been classified as current or noncurrent based on management's estimates regarding the timing of actual payments. Management estimates that expenditures associated with these environmental liabilities will be substantially paid over the next 10 years.

Environmental Receivables. Receivables from insurance carriers related to environmental matters were $4.8 million and $5.1 million at December 31, 2013 and 2014, respectively.

Environmental Insurance Policies. We have insurance policies that provide coverage for environmental matters associated with liabilities arising from sudden and accidental releases of products applicable to all of our assets.

Stationary Engine Emission Standards. The EPA set May 2013 as the compliance date for the reduction of carbon monoxide from the exhausts of large stationary reciprocating internal combustion engines. The EPA rule, which became effective in May 2010, involves the installation of catalytic converters to the engine exhaust to achieve compliance. We received a one-year extension until May 2014 to meet the stationary engine emission standards. During 2014, prior to the extension deadline, we completed modifications to all of the affected engines and are now in full compliance with these EPA standards.

Hazardous Substances and Wastes. In most instances, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into water or soils, and include measures to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

Our operations generate wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements as our operations routinely generate only small quantities of hazardous wastes, and we are not a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA hazardous waste permit. While RCRA currently exempts a number of wastes from being subject to hazardous waste requirements, including many oil and gas exploration and production wastes, the EPA could consider the adoption of stricter disposal standards for non-hazardous wastes. Moreover, it is possible that additional wastes, which could include non-hazardous wastes currently generated during operations, may be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly storage and disposal requirements than non-hazardous wastes. Changes in the regulations could materially increase our expenses.

We own or lease properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties were previously operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including

wastes disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

As part of our assessment of facility operations, we have identified some above-ground tanks at our terminals that either are, or are suspected of being, coated with lead-based paints. The removal and disposal of any paints that are found to be lead-based, whenever such activities are conducted in the future as part of our day-to-day maintenance activities, will require increased handling. However, we do not expect the costs associated with this increased handling to be material.

Water Discharges. Our operations can result in the discharge of pollutants, including crude oil and refined products, and are subject to the Oil Pollution Act and Clean Water Act ("CWA"). The CWA subjects owners of facilities to strict, joint and potentially significant liability for removal costs and certain other consequences of a product spill such as natural resource damages, where the product spills into navigable waters, along federal shorelines or in the exclusive economic zone of the U.S. In the event of a product spill from one of our facilities into navigable waters, substantial liabilities could be imposed. States in which we operate have also enacted similar laws. The CWA imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. This law and comparable state laws require that permits be obtained to discharge pollutants into state and federal waters and impose substantial potential liability for non-compliance. Where required, we hold discharge permits that were issued under the CWA or a state-delegated program. While we have occasionally exceeded permit discharges at some of our terminals, we do not expect our non-compliance with existing permits to have a material adverse effect on our results of operations, financial position or cash flows.

Greenhouse Gas Emissions. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the Clean Air Act ("CAA"). Among several such regulations, in May 2010, the EPA finalized its "tailoring rule," determining which stationary sources of greenhouse gases are required to obtain permits and implement best available control technology standards on account of their greenhouse gas emission levels. The EPA's endangerment finding and greenhouse gas rules were upheld by the U.S. Court of Appeals for the D.C. Circuit in June 2012, and a petition for review of the case by the entire D.C. Circuit was denied in December 2012.

Congress has considered various proposals to reduce greenhouse gas emissions that may impose a carbon emissions tax, a cap-and-trade program or other programs aimed at carbon reduction. Such legislation would have established an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the earth's atmosphere and other climatic changes. The current administration supports legislation to reduce greenhouse gas emissions through an emission allowance system. As allowances under such a system would be expected to significantly escalate in cost over time, the net effect of any potential cap-and-trade legislation would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products and natural gas. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap-and-trade programs. Our compliance with any future legislation or regulation of greenhouse gases, if it occurs, may result in materially increased compliance and operating costs. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.

Maintenance. Our pipeline systems are subject to regulation by the U.S. Department of Transportation under the Hazardous Liquid Pipeline Safety Act of 1979, as amended ("HLPSA"), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. HLPSA covers crude oil, refined products and anhydrous ammonia and requires any entity that owns or operates pipeline facilities to comply with such regulations, permit access to and copying of records and make certain reports

and provide information as required by the Department of Transportation. Our assets are also subject to various federal security regulations, and we believe we are in substantial compliance with all applicable regulations.

The Department of Transportation requires operators of hazardous liquid interstate pipelines to develop and follow an integrity management program that provides for assessment of the integrity of all pipeline segments that could affect designated “high consequence areas,” including high population areas, drinking water, commercially navigable waterways and ecologically sensitive resource areas. Segments of our pipeline systems have the potential to impact high consequence areas. In addition to regulations applicable to all of our pipelines, as part of the Longhorn development projects, we have undertaken additional obligations to mitigate potential risks to health, safety and the environment on our Longhorn pipeline. Our compliance with these incremental obligations is subject to the oversight of the Department of Transportation through the Pipeline and Hazardous Materials Safety Administration ("PHMSA").

Our marine terminals along coastal waterways are subject to U.S. Coast Guard regulations and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of these assets.

Breakout Storage Tank Integrity Regulations. PHMSA defines a breakout tank as one that is used to relieve surges in a hazardous liquid pipeline system or to receive and store hazardous liquids transported by a pipeline for reinjection and continued transportation by a pipeline. In January 2015, amended regulations were published by the PHMSA, which require more frequent out-of-service inspections for breakout storage tanks. These newly published regulations would impact approximately 550 of our storage tanks. We are actively engaged in discussions with PHMSA to consider alternative, technically-viable inspection intervals. If we are unable to reach such an agreement with PHMSA, our compliance with the amended regulations could negatively impact our future financial results and could result in service disruptions to our customers.

Safety. Our assets are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, which, among other things, require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request. At qualifying facilities, we are subject to OSHA Process Safety Management regulations that are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We believe we are in material compliance with OSHA and comparable state safety regulations.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly-constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The PHMSA has also published notices and advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. Compliance with such legislative and regulatory changes could have a material effect on our results of operations, financial position or cash flows.

Title to Properties

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property, and in some instances, these rights-of-way have limited terms that may require periodic renegotiation or, if such negotiations are unsuccessful, may require us to seek to exercise the power of eminent domain. Several rights-of-way for our pipelines and other real property assets are shared with other pipelines and by third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases,

property for pipeline purposes was purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and land necessary for our pipelines.

Some of the leases, easements, rights-of-way, permits and licenses that have been transferred to us are only transferable with the consent of the grantor of these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects.

We believe that we have satisfactory title to all of our assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us or our predecessor, we believe that none of these burdens should materially detract from the value of our properties or from our interest in them or should materially interfere with their use in the operation of our business.

Employees

As of December 31, 2014, we had 1,565 employees, 880 of which were assigned to our refined products segment and concentrated in the central U.S. Approximately 26% of the 880 employees are represented by the United Steel Workers ("USW") and were covered by a collective bargaining agreement that expired January 31, 2015. We are operating under a 24-hour rolling extension of this agreement while negotiations for a new agreement continue. Management expects that we will be able to successfully negotiate a new long-term agreement with the USW; however, a prolonged work stoppage by these employees could have a material adverse effect on our business activities, results of operations and cash flows. At December 31, 2014, 88 of our employees were assigned to our crude oil segment and were concentrated in the central U.S., and none of these employees were covered by a collective bargaining agreement. The labor force of 169 employees assigned to our marine storage segment at December 31, 2014 was primarily located in the Gulf and East Coast regions of the U.S. Approximately 17% of these employees were represented by the International Union of Operating Engineers and covered by a collective bargaining agreement that expires October 31, 2016.

(d) Financial Information About Geographical Areas

We have no international activities. For all periods included in this report, all of our revenue was derived from operations conducted in, and all of our assets were located in, the U.S. See Note 16–Segment Disclosures in the notes to consolidated financial statements for information regarding our revenue and total assets.

(e) Available Information

We file annual, quarterly and current reports, proxy statements and other information electronically with the Securities and Exchange Commission (“SEC”). You may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including our filings.

Our internet address is www.magellanlp.com. We make available free of charge on or through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

Item 1A. Risk Factors

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of the material risks relating to our business activities that we have identified. In addition to the factors discussed elsewhere in this Annual Report on Form 10-K, you should carefully consider the risks and uncertainties described below, which could have a material adverse effect on our business, financial condition and results of operations. However, these risks are not the only risks that we face. Our business could also be impacted by additional risks and uncertainties not currently known or that we currently deem to be immaterial. If any of these risks actually occur, they could materially harm our business, financial condition or results of operations and impair our ability to implement our business plans or complete development projects as scheduled. In that case, the market price of our limited partner units could decline.

Risks Related to Our Business

The cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions following establishment of cash reserves.

The amount of cash we can distribute to our limited partners principally depends upon the cash we generate from our operations, as well as cash reserves established by our general partner. Our distributable cash flow does not depend solely on profitability, which is affected by non-cash items. As a result, we could pay cash distributions during periods when we record net losses and could be unable to pay cash distributions during periods when we record net income. In addition, the amount of cash we generate from operations fluctuates from quarter to quarter and may change over time. Significant and sustained reductions in the cash generated by our operations could reduce our ability to pay quarterly distributions in future periods. Any failure to pay distributions at expected levels could result in a loss of investor confidence and a decrease in the value of our unit price.

Our financial results depend on the demand for the petroleum products that we transport, store and distribute, among other factors. Unfavorable economic conditions, technological changes, regulatory developments or other factors could result in lower demand for these products for a sustained period of time.

Any sustained decrease in demand for petroleum products in the markets served by our pipelines or terminals could result in a significant reduction in the volume of products that we transport, store or distribute, and thereby reduce our cash flow and our ability to pay cash distributions. Global economic conditions have from time to time resulted in reduced demand for the products transported and stored by our pipelines and terminals and consequently for the services that we provide. Our financial results may also be affected by uncertain or changing economic conditions within certain regions. If economic and market conditions remain uncertain or adverse conditions persist for an extended period, we could experience material impacts on our business, financial condition and results of operations.

Other factors that could lead to a decrease in demand for the petroleum products we transport, store and distribute include:


•	an increase or decrease in the market prices of petroleum products, which may reduce supply or 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.

A decrease in crude oil production in the basins served by our crude oil pipelines could reduce our transportation revenues, which could adversely impact our results of operations and the amount of cash we generate.

Numerous factors could cause reductions in crude oil production in the regions served by our pipelines, including, among other factors, lower overall crude oil prices, regional price or quality differences, higher costs of crude oil production, weather or other natural causes, adverse regulatory or legal developments, disruptions in financial or credit markets that inhibit the ability of our customers to finance the costs of production, or lower overall demand for crude oil and the products derived from crude oil. Crude oil prices have historically exhibited significant volatility, and are influenced by, among other factors, worldwide and domestic supplies of and demand for crude oil, political and economic developments in often-volatile producing regions, actions taken by the Organization of Petroleum Exporting Countries, technological developments, government regulations and taxes, policies regarding the importing and exporting of crude oil and conditions in global financial markets. While the transportation revenues on our crude oil pipelines are in some cases supported by long-term contracts, lower production in the regions served by our pipelines could result in lower shipments of uncommitted volumes, or could cause us to be unable to renew our contracts at existing rates. Any sustained decrease in the production of crude oil in the regions served by our crude oil pipelines could result in a significant reduction in the volume of products that we transport or the rates we are able to charge for such transportation services or both, thereby reducing our cash flow and our ability to pay cash distributions.

A decrease in lease renewals or renewals at substantially lower rates at our storage terminals or in leased storage along our pipelines could cause our leased storage revenue to decline, which could adversely impact our results of operations and the amount of cash we generate.

The revenue we earn from leased storage at our marine and crude oil terminals and along our pipeline system is provided for in contracts negotiated with our leased storage customers. Many of those contracts are for multi-year periods and require our customers to pay a fixed rate for storage capacity regardless of market conditions during the contract period. Changing market conditions, including changes in petroleum product supply or demand patterns, forward-price structure, financial market conditions, regulations, accounting rules or other factors could cause our customers to be unwilling to renew their leased storage contracts with us when those contracts terminate, or make them willing to renew only at lower rates or for shorter contract periods. Failure by our customers to renew their leased storage contracts on terms and at rates substantially similar to our existing contracts could result in lower utilization of our facilities and could cause our leased storage revenue to be more volatile. We have built a significant amount of new storage to meet market demand in recent years, as have several of our competitors. In addition, storage facilities previously used to support refineries or other facilities have in some cases been redeployed to provide services that compete with our own services. Increased competition from other leased storage facilities could discourage our customers from renewing their contracts with us or cause them to renew their contracts with us at lower rates. We typically make capital investments in leased storage facilities only if we are able to secure contracts from our customers that support such investment; however, in some cases the initial term of those contracts is not sufficient to ensure that we fully earn the return we expect on those investments. If our customers do not renew such contracts or renew on less favorable terms, we could earn a return on those investments that is below our cost of capital, which could adversely affect our results of operations, financial position and cash flows.

Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in petroleum products, which could adversely affect the demand for our storage services.

We have constructed and continue to build new storage tanks in response to increased customer demand for storage. Many of our competitors have also built new storage facilities. The demand for new storage has resulted in part from our customers' desire to have the ability to take advantage of profit opportunities created by volatility in the prices of petroleum products. If the prices of petroleum products become relatively stable, or if federal or state regulations are passed that discourage our customers from storing these commodities, demand for our storage services could decrease, in which case we may be unable to lease storage capacity or be forced to reduce the rates we charge for leased storage capacity, either of which could materially reduce the amount of cash we generate.

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our results from operations, our liquidity and our ability to pay cash distributions.

The operation of our assets and the implementation of our growth strategy require significant expenditures for labor, materials, property, equipment and services. Increases in the cost of these items could materially increase our expenses or capital costs. We may not be able to pass these increased costs on to our customers in the form of higher fees for our services.

We use the FERC's PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines. For the five-year period beginning July 1, 2011, the indexing method provides for annual changes in rates by a percentage equal to the change in the PPI-FG plus 2.65%. This methodology could result in changes in our revenue that does not fully reflect changes in the costs we incur to operate and maintain our pipelines. For example, our costs could increase more quickly or by a greater amount than the PPI-FG index plus 2.65% used by the current FERC methodology. Further, in periods of general price deflation, the PPI-FG index could fall, in which case we could be required to reduce our index-based rates, even if the actual costs we incur to operate our assets increase. The FERC's PPI indexing methodology will be revised next year. Changes in price levels that lead to decreases in our revenue or increases in the prices we pay to operate and maintain our assets could adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

Our business involves many hazards and operational risks, the occurrence of which could materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.

Our operations are subject to many hazards inherent in the transportation and distribution of petroleum products and ammonia, including ruptures, leaks and fires. In addition, our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and earthquakes. Our storage and pipeline facilities located near the U.S. Gulf Coast, for example, have experienced damage and interruption of business due to hurricanes. These risks could result in substantial losses due to personal injury or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and may result in curtailment or suspension of our related operations. Some of our assets are located in or near high consequence areas such as residential and commercial centers or sensitive environments, and the potential damages are even greater in these areas. If a significant accident or event occurs, it could materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.

Our assets may not be adequately insured or could have losses that exceed our insurance coverage.

We are not fully insured against all hazards or operational risks related to our businesses, and the insurance we carry requires that we meet certain deductibles before we can collect for any losses we sustain. If a significant accident or event occurs that is not fully insured, it could materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.

We may encounter increased costs related to and decreases in the availability of insurance.

Premiums and deductibles for our insurance policies have increased significantly over the last few years, and could escalate further as a result of market conditions or losses experienced by us or by other companies. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. Increases in the cost of insurance or the inability to obtain insurance at rates that we consider commercially reasonable could materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.

Many of our storage tanks and significant portions of our pipeline system have been in service for several decades.

Our pipeline and storage assets are generally long-lived assets. As a result, some of those assets have been in service for several decades. The age and condition of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

We do not own most of the property on which our pipelines are constructed, and we rely on securing and retaining adequate rights-of-way and permits in order to operate our existing assets and complete growth projects.

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the relevant property, and in some instances these rights-of-way have limited terms that may require periodic renegotiation or, if such negotiations are unsuccessful, may require us to seek to exercise the power of eminent domain. Several rights-of-way for our pipelines and other real property assets are shared with other pipelines and third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the right-of-way grants. We require permits from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances these permits are revocable at the election of the grantor. Similarly, we have obtained permits from railroad companies to cross over or under certain lands or rights-of-way, many of which are also revocable at the grantor's election. We are subject to potential increases in costs under our agreements with landowners, and if any of our rights-of-way or permits were revoked, our operations could be disrupted or we could be required to relocate our pipelines. Similarly, if we are unable to secure rights-of-way required for our growth projects, we could be forced to re-design or re-route those projects, which could result in substantial delays, reduced revenue or increased costs on those projects. Our ability to exercise the power of eminent domain varies by state and by circumstance, and the availability of the power and the compensation we must provide landowners in connection with any eminent domain action may be determined by a court. Failure to obtain required new rights-of-way or permits or retain rights-of-way and permits on existing terms could have a material adverse effect on our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

We depend on producers, gatherers, refineries and petroleum pipelines owned and operated by others to supply our pipelines and terminals.

We depend on crude oil production and on connections with gathering systems, refineries and petroleum pipelines owned and operated by third parties to supply our assets. Changes in the quality or quantity of this crude oil production, outages at these refineries or reduced or interrupted throughput on these gathering systems or pipelines due to weather-related or other natural causes, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver products to our customers from our terminals or receive products for storage or reduce shipments on our pipelines and could materially adversely affect our cash flows and ability to pay cash distributions.

The closure of refineries that supply or are supplied by our refined products and crude oil pipelines could result in material disruptions or reductions in the volumes we transport and store and in the amount of cash we generate.

Refineries that supply or are supplied by our facilities are subject to regulatory developments, including but not limited to regulations regarding fuel specifications, plant emissions and safety and security requirements, that could significantly increase the cost of their operations and reduce their operating margins. In addition, the profitability of the refineries that supply our facilities is subject to regional and sometimes global supply and demand dynamics that are difficult to predict. A period of sustained weak demand or increased cost of supply could make refining uneconomic for some refineries, including those located along our refined products and crude oil pipelines. The closure of a refinery that delivers product to or receives crude from our refined products or crude oil pipelines could reduce the volumes we transport and the amount of cash we generate. Further, the closure of these or other refineries could result in our customers electing to store and distribute petroleum products through their proprietary terminals, which could result in a reduction of our storage volumes.

Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.

As of December 31, 2014, approximately 23% of the workforce assigned to our operating segments was covered by two collective bargaining agreements with different terms and dates of expirations. There can be no assurances that we will not experience a work stoppage in the future as a result of disagreements with these labor unions. A prolonged work stoppage could have a material adverse effect on our business activities, results of operations and cash flows.

Competition could lead to lower levels of profits and reduce the amount of cash we generate.

We compete with other existing pipelines and terminals that provide similar services in the same markets as our assets. In addition, our competitors could construct new assets or redeploy existing assets in a manner that would result in more intense competition in the markets we serve. We compete with other transportation, storage and distribution alternatives on the basis of many factors, including but not limited to rates, service levels, geographic location, connectivity and reliability. Our customers could utilize the assets and services of our competitors instead of our assets and services, or we could be required to lower our prices or increase our costs to retain our customers, either of which could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

Our business is subject to the risk of a capacity overbuild in some of the markets in which we operate.

We have made and continue to make significant investments in new energy infrastructure to meet market demand, as have several of our competitors. For example, we have invested significantly in new pipelines to deliver crude oil from the Permian Basin in West Texas to markets along the U.S. Gulf Coast. Similar investments have been made and additional investments may be made in the future by our competitors or by new entrants to the markets we serve. The success of these and similar projects largely relies on the realization of anticipated market demand, and these projects typically require significant development periods, during which time demand for such infrastructure may change, or additional investments by competitors may be made. If infrastructure investments by us or others in the markets we serve result in capacity that exceeds the demand in those markets, our facilities could be underutilized, we could be forced to reduce the rates we charge for our services, the value of our assets could decrease and the returns on our investments in those markets could fail to meet our expectations.

Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, thereby reducing the amount of cash we generate.

Mergers among our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where our systems compete. As a result, we could lose some or all of the volumes and associated revenue from these customers, and we could

experience difficulty in replacing those lost volumes and revenue. As most of our operating costs are fixed, a reduction in volumes would result not only in less revenue, but also a decline in cash flow of a similar magnitude, which could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.

The U.S. government has issued warnings that energy assets in general, and the nation's pipeline and terminal infrastructure in particular, may be targets of terrorist organizations. The threat of terrorist attacks has subjected our operations to increased risks. Any terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any terrorist attacks that severely disrupt the markets we serve could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

Fluctuations in prices of petroleum products that we purchase and sell could materially affect our results of operations.

We generate product sales revenue from our butane blending and fractionation activities, as well as from the sale of product generated by the operation of our pipelines and terminals. We also maintain product inventory related to these activities. Significant fluctuations in market prices of petroleum products (which have occurred in recent months) could result in losses or lower profits from these activities, thereby reducing the amount of cash we generate and our ability to pay cash distributions. Additionally, significant fluctuations in market prices of petroleum products could result in significant unrealized gains or losses on transactions we enter to hedge our exposure to commodity price changes. To the extent these transactions have not been designated as hedges for accounting purposes, the associated non-cash unrealized gains and losses directly impact our results of operations.

We hedge prices of petroleum products by utilizing physical purchase and sale agreements, exchange-traded futures contracts or over-the-counter transactions. These hedging arrangements may not eliminate all price risks, could result in fluctuations in quarterly or annual financial results and could result in material cash obligations that could negatively impact our financial position or our ability to pay distributions to our unitholders.

We hedge our exposure to price fluctuations for our petroleum products purchase and sale activities by utilizing physical purchase and sale agreements, exchange-traded futures contracts or over-the-counter transactions. To the extent these hedges do not qualify for hedge accounting treatment under Accounting Standards Codification 815, Derivatives and Hedging, or if they result in material amounts of ineffectiveness, we could experience material fluctuations in our quarterly or annual results of operations. To the extent these hedges are entered into on a public exchange, we may be required to post margin, which could result in material cash obligations. These contracts may be for the purchase or sale of product in markets different from those in which we are attempting to hedge our exposure, resulting in hedges that do not eliminate all price risks. If we incur material amounts of ineffectiveness in our hedging strategies, our quarterly or annual results of operations could be negatively impacted, which could have a negative impact on our unit price. Further, our requirement to post material amounts of margin on the hedge contracts we have entered into could negatively impact our ability to pay distributions to our unitholders.

Our expansion projects may not immediately produce operating cash flows and may exceed our cost estimates or experience delays.

We have begun numerous large expansion projects that have required and will continue to require us to make significant capital investments. We intend to finance those projects primarily with new borrowings, and we will incur financing costs during the planning and construction phases of these projects; however, the operating cash flows we expect these projects to generate will not materialize until sometime after the projects are completed, if at all. As a result, our leverage may increase during the period prior to the generation of those operating cash flows. In addition, the amount of time and investment necessary to complete these projects could materially exceed the estimates we used when determining whether to undertake them. For example, we must compete with other

companies for the materials and construction services required to complete these projects, and competition for these materials or services could result in significant delays or cost overruns. Similarly, we must secure and retain required permits and rights-of-way, including in some cases through the exercise of the power of eminent domain, in order to complete and operate these projects, and our inability to do so in a timely manner could result in significant delays or cost overruns. Further, in many instances the operations of our expansion projects are subject to the execution by third parties of pipeline connections or other related projects that are beyond our control. Delays or unanticipated costs associated with these third parties in the execution of these related projects could result in delays or cost overruns in the start-up of our own projects. Any cost overruns or unanticipated delays in the completion or commercial development of our expansion projects could reduce the anticipated returns on these projects, which in turn could materially increase our leverage and reduce our liquidity and our ability to pay cash distributions.

Potential future acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and liabilities, subjecting us to the risk of being unable to effectively integrate the new operations and diluting our limited partner unitholders.

From time to time we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. We may issue significant amounts of additional equity securities and incur substantial additional indebtedness to finance future acquisitions, and our capitalization and results of operations may change significantly as a result. Our limited partner unitholders will not have an opportunity to review or evaluate the information and assumptions we use to determine whether to pursue an acquisition. An acquisition that we expect to be accretive could nevertheless reduce our cash from operations if we rely on faulty information, make inaccurate assumptions, assume unidentified liabilities or otherwise improperly value the acquired assets. In addition, any equity securities we issue to finance acquisitions could dilute our existing limited partner unitholders and reduce our cash flow available for distribution on a per unit basis.

Acquisitions and business expansions involve numerous risks, including but not limited to difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise due to our unfamiliarity with new assets and the businesses associated with them and their markets, challenges in managing or retaining new employees and establishing relationships with and retaining new customers and business partners, and the diversion of management's attention from other business concerns. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse from the seller.

We compete for acquisitions and new projects with numerous other established energy companies and many other potential investors. Increased competition for acquisitions or growth projects could limit our ability to execute our growth strategy or could result in our executing that strategy on substantially less attractive terms than we have previously experienced, either of which could have a material adverse effect on our results of operations or cash flows, as well as our ability to pay cash distributions.

Failure to generate or complete additional growth projects or make future acquisitions could reduce our ability to increase cash distributions to our unitholders.

Our ability to increase distributions to our unitholders depends to a significant degree on our ability to successfully identify and execute additional growth projects and acquisitions. We face significant uncertainties and competition in the pursuit of such opportunities. For example, decisions regarding new growth projects rely on numerous estimates, including among other factors, predictions of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments, economic conditions and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forego certain investments or to lose opportunities to competitors who make investments based on more aggressive predictions. Valuations of energy infrastructure assets have generally been elevated in recent years, which has made it difficult for us to be successful in our attempts to acquire new assets, as other bidders for those assets have been willing to pay prices and accept terms that did not meet our risk and return criteria. If we are unable to acquire new assets or develop additional expansion projects, our ability to increase distributions to our unitholders will be reduced.

The amount and timing of distributions to us from our joint ventures is not within our control, and we may be unable to cause our joint ventures to take or refrain from taking certain actions that may be in our best interest.

We participate in several joint ventures and share control of the joint ventures with other entities according to the relevant joint venture agreements. Those agreements provide that the respective joint venture management committees, including our representatives along with the representatives of the other owners of those joint ventures, determine the amount and timing of distributions. In addition, many activities of the joint ventures may only be authorized by agreement between us and the other owners of those joint ventures. In the case of Double Eagle Pipeline LLC, our joint venture co-owner serves as operator, and consequently we rely on our joint venture co-owner for many of the management functions of that joint venture. Without the cooperation of the other owners of those joint ventures, we are unable to cause our joint ventures to take or not to take certain actions, even though those actions or inactions may be in the best interest of us or the particular joint venture. If we are unable to agree with our joint venture co-owner on a significant matter, it could result in a material adverse effect on that joint venture's financial condition, results of operations or cash flows. If the matter is significant to us, it could result in a material adverse effect on our results of operations, financial position or cash flows.

Moreover, subject to certain limitations in the respective joint venture agreements, any joint venture owner may sell or transfer its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint venture owners. Any such transaction could result in our being co-owners with different or additional parties with whom we have not had a previous relationship.

Our joint ventures could establish separate financing arrangements that could contain restrictive covenants that may limit or restrict the joint venture's ability to make cash distributions to us under certain circumstances. Any inability to generate cash or restrictions on cash distributions we receive from our joint ventures could impair our results of operations, cash flows and our ability to pay cash distributions.

Rate regulation or challenges by shippers of the rates we charge on our refined products and crude oil pipelines may reduce the amount of cash we generate.

The FERC regulates the tariff rates for interstate movements and state regulatory authorities regulate the tariff rates for intrastate movements on our refined products and crude oil pipelines. Shippers may protest our pipeline tariff filings, and the FERC or state regulatory authorities may investigate tariff rates. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under rates that are determined to be in excess of a just and reasonable level when taking into consideration our pipeline system's cost-of-service. State regulatory authorities could take similar measures for intrastate tariffs. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC and state regulatory authorities may also investigate tariff rates absent shipper complaint. If existing rates challenged by complaint are determined to be in excess of a just and reasonable level when taking into consideration our pipeline systems' cost-of-service, we could be required to pay reparations to complaining shippers and make other concessions.

The FERC's ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. The FERC's primary ratemaking methodology is price indexing. We use this methodology to establish our rates in approximately 40% of the markets for our refined products pipeline. The FERC's indexing methodology is subject to review every five years and currently allows a pipeline to change its rates each year to a new ceiling level, which is calculated as the previous year's ceiling level multiplied by a percentage. The FERC has established a price index level equal to the annual change in the PPI-FG expressed as a percentage, plus 2.65% for the five-year period beginning July 1, 2011. If the PPI-FG falls, we would be required to reduce our rates that are subject to the FERC's price indexing methodology. In July 2016, a new price index level will be established by the FERC. Any change in the current indexing methodology will change our ability to raise our rates in the future.

We establish rates in approximately 60% of the markets for our refined products pipeline using the FERC's market-based ratemaking regulations. These regulations allow us to establish rates based on conditions in individual

markets without regard to FERC's index level or our cost-of-service. If we were to lose our market-based rate authority, we would then be required to establish rates on some other basis, such as our cost-of-service.

Our operations are subject to extensive environmental, health, safety and other laws and regulations that impose significant requirements, costs and liabilities on us. These requirements, costs and liabilities could increase as a result of new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations. Our customers are also subject to extensive environmental, health, safety and other laws and regulations, and any new laws or regulations or changes in the interpretation, implementation or enforcement of existing laws and regulations, including laws and regulations related to hydraulic fracturing, could result in decreased demand for our services.

Our operations are subject to extensive federal, state and local laws and regulations relating to the protection or preservation of the environment, natural resources and human health and safety, including but not limited to the Clean Air Act ("CAA"), the RCRA, the Oil Pollution Act and Clean Water Act ("CWA"), the CERCLA, the HLPSA, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 and OSHA. Such laws and regulations affect almost all aspects of our operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, credits, inspections and other approvals. We incur substantial costs to comply with these laws and regulations, and any failure to comply may expose us to civil, criminal and administrative fees, fines, penalties and interruptions in our operations that could have a material adverse impact on our results of operations, financial position and prospects. For example, if an accidental release or spill of petroleum products, chemicals or other hazardous substances occurs at or from our pipelines, storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to remediate the release or spill, pay government penalties, address natural resource damages, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially adversely affect our results of operations, financial position and cash flows. In addition, emission controls required under the CAA and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.

Liability under such laws and regulations may be incurred without regard to fault under CERCLA, RCRA, the Water Pollution Control Act or analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

Our assets have been used for many years to transport, store or distribute petroleum products. Over time our operations, or operations by our predecessors or third parties not under our control, may have resulted in the disposal or release of hydrocarbons or solid wastes at or from these terminal properties and along such pipeline rights-of-way. In addition, some of our terminals and pipelines are located on or near current or former refining and terminal sites, and there is a risk that contamination is present on those sites. We may be subject to strict, joint and several liability under a number of these environmental laws and regulations for such disposal and releases of hydrocarbons or solid wastes or the existence of contamination, even in circumstances where such activities or conditions were caused by third parties not under our control or were otherwise lawful at the time they occurred.

The laws and regulations that affect our operations, and the enforcement thereof, have become increasingly stringent over time. We cannot ensure that these laws and regulations will not be further revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures to comply with laws and regulations, including expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. In addition to increasing our costs or liabilities, legal or regulatory changes or changes in the cost or availability of permits or related credits, where applicable, could also impact our ability to develop new projects. For example, changes that affect permitting or siting processes or the use of eminent domain could prevent or delay our ability to construct new pipelines or storage tanks. Revised or additional regulations that result in increased compliance costs or additional

operating restrictions or liabilities could have a material adverse effect on our business, financial position, results of operations and prospects.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly-constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. PHMSA has also published notices and advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements. Compliance with such legislative and regulatory changes could have a material adverse effect on our results of operations.

Our customers are also subject to extensive laws and regulations that affect their businesses, and new laws or regulations could materially adversely affect their businesses or prospects. For example, several of our most significant customers are refineries whose businesses could be significantly impacted by changes in environmental or health-related laws or regulations. In addition, we have made and continue to make significant investments in crude oil and condensate storage and transportation projects that serve customers who largely depend on production techniques, such as hydraulic fracturing, that are currently being scrutinized by federal and state authorities and that could be subjected to increased regulatory costs, delays or liabilities. Any changes in laws or regulations, or in the interpretation, implementation or enforcement of existing laws and regulations, that impose significant costs or liabilities on our customers, or that result in delays or cancellations of their projects, could reduce their demand for our services and materially adversely affect our results of operations, financial position or cash flows and our ability to pay cash distributions.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products that we transport, store or distribute.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Among several such regulations, in May 2010, the EPA finalized its “tailoring rule,” determining which stationary sources of greenhouse gases are required to obtain permits and implement best available control technology standards on account of their greenhouse gas emission levels. The EPA's endangerment finding and greenhouse gas rules were upheld by the U.S. Court of Appeals for the D.C. Circuit in June 2012, and a petition for review of the case by the entire D.C. Circuit was denied in December 2012. In addition, EPA issued a proposed rule for regulation of carbon dioxide emissions from existing stationary sources in June 2014, which would require states to meet specific carbon dioxide reduction goals for the power sector. The proposed rule is scheduled to be finalized in June 2015. Further, Congress has considered various proposals to reduce greenhouse gas emissions that may impose a carbon emissions tax, a cap-and-trade program or other programs aimed at carbon reduction. Such legislation would have established an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the earth's atmosphere and other climatic changes. The current administration supports legislation to reduce greenhouse gas emissions through an emission allowance system. As allowances under such a system would be expected to significantly escalate in cost over time, the net effect of any potential cap-and-trade legislation would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products and natural gas. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap-and-trade programs. Our compliance with any future legislation or regulation of greenhouse gases, if it occurs, may result in materially increased compliance and operating costs. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.

The effect on our operations of CAA regulations, legislative efforts or related implementation rules that regulate or restrict emissions of greenhouse gases in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program, among other things. We may be unable to include some or all of such increased costs in the rates charged to our customers and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations.

In addition, some scientists have concluded that increasing concentrations of greenhouse gases in the earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climate events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Our butane blending activities subject us to federal regulations that govern renewable fuel requirements in the United States.

The Energy Independence and Security Act of 2007 expanded the required use of renewable fuels in the United States. Each year, the EPA establishes a RVO requirement for refiners and fuel manufacturers based on overall quotas established by the federal government. By virtue of our butane blending activity and resulting gasoline production, we are an obligated party and receive an annual RVO from the EPA. In lieu of blending renewable fuels (such as ethanol and biodiesel), we have the option to purchase renewable energy credits, called RINs, to meet this obligation. RINs are generated when a gallon of biofuel such as ethanol or biodiesel is produced. RINs may be separated when the biofuel is blended into gasoline or diesel, at which point the RIN is available for use in compliance or is available for sale on the open market. Increases in the cost or decreases in the availability of RINs could have an adverse impact on our results of operations, cash flows and cash distributions.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store, transport or sell.

Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications for commodities sold into the public market. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For instance, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay cash distributions could be materially adversely affected.

In addition, changes in the product quality of the products we receive on our refined products pipeline, or changes in the product specifications in the markets we serve, could reduce or eliminate our ability to blend products, which would result in a reduction of our revenue and operating profit from blending activities. Any such reduction of our revenue or operating profit could have a material adverse effect on our results of operations, financial position, cash flows and ability to pay cash distributions.

We are exposed to counterparty risk. Nonpayment and nonperformance by our customers, vendors, lenders or derivative counterparties could materially reduce our revenue, impair our liquidity, increase our expenses or otherwise negatively impact our results of operations, financial position or cash flows and our ability to pay cash distributions.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, we frequently undertake capital expenditures based on commitments from customers upon

which we expect to realize the expected return on those expenditures, including take-or-pay commitments from our customers, and nonperformance by our customers on those commitments could result in substantial losses to us.

We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis, at the prices we expect and as required by contract could result in significant disruptions, costs to our operation, or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results and cash flows.

We also rely to a significant degree on the banks that lend to us under our commercial paper program and revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk.

Any substantial increase in the nonpayment or nonperformance by our customers, vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position and cash flows and our ability to pay cash distributions.

Losses sustained by any money market mutual fund or other investment vehicle in which we invest our cash or the failure of any bank or financial institution in which we deposit funds could adversely affect our financial position and our ability to pay cash distributions.

We may maintain material balances of cash and cash equivalents for extended periods of time. We typically invest any material amount of cash on hand in cash equivalents such as money market mutual funds. These funds are primarily comprised of highly rated short-term instruments. Significant market volatility and financial distress could cause such investments to lose value or reduce the liquidity of such investments. We may also maintain deposits at a commercial bank in excess of amounts insured by government agencies such as the Federal Deposit Insurance Corporation. In addition, certain exchange-traded derivatives transactions we enter into in order to hedge commodity-related price exposures frequently require us to make margin deposits with a broker. A failure of our commercial bank or our broker could result in our losing any funds we have deposited. Any losses we sustain on the investments or deposits of our cash could materially adversely affect our financial position and our ability to pay cash distributions.

We rely on access to capital to fund acquisitions and growth projects and to refinance existing debt obligations. Unfavorable developments in capital markets could limit our ability to obtain funding or require us to secure funding on terms that could limit our financial flexibility, reduce our liquidity, dilute the interests of our existing unitholders and/or reduce our cash flows and ability to pay distributions.

We regularly consider and pursue growth projects and acquisitions as part of our efforts to increase cash available for distribution to our unitholders. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. For example, we estimate that we will spend approximately $650 million to complete our current slate of organic growth projects during 2015. We generally do not retain sufficient cash flow to finance such projects and acquisitions, and consequently the execution of our growth strategy requires regular access to external sources of capital. Any limitations on our access to capital on satisfactory terms will impair our ability to execute this strategy and could reduce our liquidity and our ability to make cash distributions.

Similarly, we generally do not retain sufficient cash flow to repay our indebtedness when it matures, and we rely on new capital to refinance these obligations. For example, $250 million of our long-term notes matured in 2014, and another $250 million will mature in 2016. We refinanced the long-term notes that matured in 2014 with borrowings from our commercial paper program and we anticipate raising new capital to refinance the notes that will mature in 2016. Limitations on our access to capital, including on our ability to issue additional debt and

equity, could result from events or causes beyond our control, and could include, among other factors, decreases in our creditworthiness or profitability, significant increases in interest rates, increases in the risk premium generally required by investors or in the premium required specifically for investments in energy-related companies or master limited partnerships, and decreases in the availability of credit or the tightening of terms required by lenders. Any limitations on our ability to refinance these obligations by securing new capital on satisfactory terms could severely limit our liquidity, our financial flexibility or our cash flows, and could result in the dilution of the interests of our existing unitholders.

Increases in interest rates could increase our financing costs, reduce the amount of cash we generate and adversely affect the trading price of our units.

As of December 31, 2014, the face value of our outstanding fixed-rate debt was $2.65 billion. We expect to make floating-rate borrowings under our commercial paper program or revolving credit facility as needed to partially finance future expansion capital spending. As a result, we would have exposure to changes in short-term interest rates. We may also use interest rate derivatives to effectively convert some of our fixed-rate notes to floating-rate debt, thereby increasing our exposure to changes in short-term interest rates. In addition, the execution of our growth strategy and the refinancing of our existing debt could require that we issue additional fixed-rate debt, and consequently we also have potential exposure to changes in long-term interest rates. Rising interest rates could reduce the amount of cash we generate and materially adversely affect our liquidity and our ability to pay cash distributions. Moreover, the trading price of our units is sensitive to changes in interest rates and could be materially adversely affected by any increase in interest rates.

Restrictions contained in our debt instruments may limit our financial flexibility.

We are subject to restrictions with respect to our debt that may limit our flexibility in structuring or refinancing existing or future debt and may prevent us from engaging in certain beneficial transactions. These restrictions include, among other provisions, the maintenance of certain financial ratios, as well as limitations on our ability to incur additional indebtedness, to grant liens or to repay existing debt without prepayment premiums. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash.

Cyber attacks that circumvent our security measures and other breaches of our information security measures could disrupt our operations and result in increased costs.

We operate our assets and manage our businesses using a telecommunications network. A security breach of that network could result in improper operation of our assets, potentially including contamination or degradation of the products we transport, store or distribute, delays in the delivery or availability of our customers' product or releases of petroleum products for which we could be held liable. In addition, we rely on third-party systems, including for example the electric grid, which could also be subject to security breaches or cyber attacks, and the failure of which could have a significant adverse effect on the operation of our assets. We and the operators of the third-party systems on which we depend may not have the resources or technical sophistication to anticipate or prevent every emerging type of cyber attack, and such an attack, or additional measures taken to prevent such an attack, could adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

We also collect and store sensitive data on our networks, including our proprietary business information and information about our customers, suppliers and other counterparties, and personally identifiable information of our employees. The secure maintenance of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. We do not maintain specialized insurance for such attacks and any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information or regulatory penalties, could disrupt our operation, and could damage our reputation, which could adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

Failure of critical information technology systems may impact our ability to operate our assets or manage our businesses, thereby reducing the amount of cash available for distribution.

We utilize information technology systems to operate our assets and manage our businesses. Some of these systems are proprietary systems that require specialized programming capabilities, while others are based upon or reside on technology that has been in service for many years. Failures of these systems could result in a breach of critical operational or financial controls and lead to a disruption of our operations, commercial activities or financial processes. Such failures could adversely affect our results of operations, financial position or cash flow, as well as our ability to pay cash distributions.

An impairment of long-lived assets, investments in non-controlled entities or goodwill could reduce our earnings and negatively impact the value of our limited partner units.

At December 31, 2014, we had $4,329.3 million of net property, plant and equipment, $613.9 million of investments in non-controlled entities and $53.3 million of goodwill. U.S. generally accepted accounting principles requires us to periodically test long-lived assets, investments in non-controlled entities and goodwill for impairment. If we were to determine that any of our long-lived assets, investments in non-controlled entities or goodwill were impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity. Such charges could be material to our results of operations and could adversely impact the value of our limited partner units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders' voting rights are restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership due to the absence of a takeover premium in the trading price.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:


•	We were conducting business in a state but had not complied with that particular state's partnership statute; or


•	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.

Our general partner's board of directors' absolute discretion in determining our level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our general partner's board of directors to deduct from available cash the amount of any cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our general partner's board of directors to reduce available cash by

establishing cash reserves for the proper conduct of our business, to comply with applicable laws or agreements to which we are a party or to provide funds for future distributions to partners. Any such cash reserves will reduce the amount of cash currently available for distribution to our unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our limited partner units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its sole discretion, free of any duties to us and holders of our limited partner units other than the implied contractual covenant of good faith and fair dealing. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us or our limited partners. By owning a limited partner unit, a holder is treated as having consented to the provisions in our partnership agreement.

Our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:


•	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.

If you are not a citizenship eligible holder, your limited partner units may be subject to redemption.

Our partnership agreement contains provisions that apply if we determine that the nationality, citizenship or other related status of a holder of our limited partnership units creates a substantial risk of cancellation or forfeiture of any property in which we have an interest. If a holder of our limited partner units is not a person who meets the requirements to be a citizenship-eligible holder, which generally includes U.S. entities and individuals who are U.S. citizens, and, therefore, creates a risk to the partnership, the holder may have its limited partner units redeemed by us. In addition, if a holder of our limited partner units does not meet the requirements to be a citizenship-eligible holder, such holder will not be entitled to voting rights and may not receive distributions in kind upon our liquidation.

Tax Risks to Limited Partner Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, or otherwise subject us to entity-level taxation, it would reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in our limited partner units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Payments to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our limited partner units.

The tax treatment of our structure could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, from time to time the U.S. government considers substantive changes to the existing federal income tax laws that affect publicly traded partnerships. We are unable to predict whether any such changes or any other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact a unitholder's investment in our limited partner units.

At the state level, changes in current state law may subject us to additional entity-level taxation by individual states. Due to widespread state budget deficits and for other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may materially reduce the cash available for distribution to our unitholders.

If the IRS contests the federal income tax positions we take, the market for our limited partner units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our limited partner units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders as the costs will reduce our cash available for distribution.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our limited partner units could be more or less than expected.

If our unitholders sell their limited partner units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those limited partner units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a limited partner unit, which decreased their tax basis in that limited partner unit, will, in effect, become taxable income to our unitholders if the limited partner unit is sold at a price greater than their tax basis in that limited partner unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of nonrecourse liabilities, if our unitholders sell their limited partner units, they may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning our limited partner units that may result in adverse tax consequences to them.

Investment in limited partner units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities or foreign persons should consult their tax advisor before investing in our limited partner units.

We will treat each purchaser of limited partner units as having the same tax benefits without regard to the actual limited partner units purchased. The IRS may challenge this treatment, which could adversely affect the value of our limited partner units.

Primarily because we cannot match transferors and transferees of limited partner units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of limited partner units and could have a negative impact on the value of our limited partner units or result in audit adjustments to our unitholders' tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our limited partner units each month based upon the ownership of our limited partner units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our limited partner units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly

traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Further, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose limited partner units are loaned to a “short seller” to cover a short sale of limited partner units may be considered to have disposed of those limited partner units. If so, he would no longer be treated for tax purposes as a partner with respect to those limited partner units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose limited partner units are loaned to a “short seller” to cover a short sale of limited partner units may be considered to have disposed of the loaned limited partner units, the unitholder may no longer be treated for tax purposes as a partner with respect to those limited partner units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those limited partner units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those limited partner units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their limited partner units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our partners. The IRS may challenge this treatment, which could adversely affect the value of our limited partner units.

When we issue additional limited partner units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our partners. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between our partners, which may be unfavorable to certain unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their IRS Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our partners.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of our limited partner units and could have a negative impact on the value of our limited partner units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit are counted only once. Our technical termination would not affect our classification as a partnership for federal income tax purposes, but could, among other things, result in the closing of our taxable year for all unitholders, which could result in our filing two tax returns for one fiscal year, and in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year results in more than 12 months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination.

Our unitholders may be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our limited partner units.

In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in 24 states, most of which impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax.


Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

See Item 1(c) for a description of the locations and general character of our material properties.


Item 3.	Legal Proceedings

2011 EPA Clean Water Act Information Request for Pipeline Release in Texas. In July 2011, we received an information request from the Environmental Protection Agency ("EPA") pursuant to Section 308 of the Clean Water Act regarding a pipeline release in February 2011 in Texas. We have accrued $0.2 million for potential monetary sanctions related to this matter. While the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

2012 EPA Clean Water Act Information Request for Pipeline Release in Nebraska. In April 2012, we received an information request from the EPA pursuant to Section 308 of the Clean Water Act regarding a pipeline release in December 2011 in Nebraska. We have accrued $1.4 million for potential monetary sanctions related to this matter. While the results cannot be predicted with certainty, we believe that the ultimate resolution of this matter will not have a material impact on our results of operations, financial position or cash flows.

U.S. Oil Recovery, EPA ID No.: TXN000607093 Superfund Site. We have liability at the U.S. Oil Recovery Superfund Site in Pasadena, Texas as a potential responsible party ("PRP") under Section 107(a) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended ("CERCLA"). As a result of the EPA’s Administrative Settlement Agreement and Order on Consent for Removal Action, filed August 25, 2011, EPA Region 6, CERCLA Docket No. 06-10-11, we voluntarily entered into the PRP group responsible for the site investigation, stabilization and subsequent site cleanup. Currently, there is an ongoing removal action designed to stabilize the site, remove the immediate threat posed at the site and set the stage for a later more comprehensive action, known as the assessment phase. We have paid $15,000 associated with the assessment phase. Until this assessment phase has been completed, we cannot reasonably estimate our proportionate share of the remediation costs associated with this site.

We are a party to various other claims, legal actions and complaints arising in the ordinary course of business. While the results cannot be predicted with certainty, management believes the ultimate resolution of these claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our future results of operations, financial position or cash flows.


Item 4.	Mine Safety Disclosures

Not applicable.

PART II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our limited partner units representing limited partnership interests are listed and traded on the New York Stock Exchange under the ticker symbol “MMP.” At the close of business on February 19, 2015, we had 227,426,329 limited partner units outstanding that were owned by approximately 153,000 record holders and beneficial owners (held in street name).

The year-end closing sales price of our limited partner units was $63.27 on December 31, 2013 and $82.66 on December 31, 2014. The high and low trading prices for our limited partner units and distribution paid per unit by quarter for 2013 and 2014 were as follows:



	2013						2014
Quarter	High		Low		Distribution*		High		Low		Distribution*
1^st	$	53.91	$	44.00	$	0.5075	$	71.25	$	60.23	$	0.6125
2^nd	$	56.29	$	48.90	$	0.5325	$	84.41	$	69.56	$	0.6400
3^rd	$	57.18	$	51.93	$	0.5575	$	87.50	$	77.14	$	0.6675
4^th	$	63.86	$	55.30	$	0.5850	$	90.08	$	66.36	$	0.6950


*	Represents declared distributions associated with each respective quarter. Distributions were declared and paid within 45 days following the close of each quarter.

We must distribute all of our available cash, as defined in our partnership agreement, at the end of each quarter, less reserves established by our general partner's board of directors. We currently pay quarterly cash distributions of $0.695 per limited partner unit. In general, we intend to increase our cash distribution; however, we cannot guarantee that future distributions will increase or continue at current levels.

Unitholder Return Performance Presentation

The following graph compares the total unitholder return performance of our limited partner units with the performance of (i) the Standard & Poor's 500 Stock Index (“S&P 500”) and (ii) the Alerian MLP index, which is a composite of the 50 most prominent energy master limited partnerships that provides investors with a comprehensive benchmark for this asset class. The graph assumes that $100 was invested in our limited partner units and each comparison index beginning on December 31, 2009 and that all distributions or dividends were reinvested on a quarterly basis.



	12/31/2009	12/31/2010	12/31/2011	12/31/2012	12/31/2013	12/31/2014
Magellan Midstream Partners, L.P.	$100	$139	$178	$234	$356	$480
Alerian MLP Index	$100	$136	$155	$162	$207	$217
S&P 500	$100	$115	$117	$136	$180	$205

The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Exchange Act.


Item 6.	Selected Financial Data

We have derived the summary selected historical financial data from our current and historical audited consolidated financial statements and related notes. Information concerning significant trends in our financial condition and results of operations is contained in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data included herein not to be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates and how these estimates could impact our future financial condition and results of operations is included in Management's Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this report. In addition, a discussion of the risk factors that could affect our business and future financial condition and results of operations is included under Item 1A, Risk Factors of this report. Additionally, Note 2 – Summary of Significant Accounting Policies under Item 8, Financial Statements and Supplementary Data of this report provides descriptions of areas where estimates and judgments could result in different amounts being recognized in our accompanying consolidated financial statements.

In the following tables, we present the financial measure of distributable cash flow ("DCF"), which is not a generally accepted accounting principles ("GAAP") measure. Our partnership agreement requires that all of our available cash, less amounts reserved by our general partner's board of directors, be distributed to our limited partners. Management uses DCF to determine the amount of cash that our operations generated that is available for distribution to our limited partners and for recommending to our general partner's board of directors the amount of cash distributions to be paid each period. We also use DCF as the basis for calculating our equity-based incentive pay. A reconciliation of DCF to net income, the nearest comparable GAAP measure, is included in the following tables.

In addition to DCF, the non-GAAP measures of operating margin (in the aggregate and by segment) and Adjusted EBITDA are presented in the following tables. We compute the components of operating margin and Adjusted EBITDA using amounts that are determined in accordance with GAAP. A reconciliation of operating margin to operating profit and net income to Adjusted EBITDA, which are the nearest comparable GAAP financial measures, are included in the following tables. See Note 16 – Segment Disclosures in the accompanying consolidated financial statements for a reconciliation of segment operating margin to segment operating profit. Operating margin is an important measure of the economic performance of our core operations, and we believe that investors benefit from having access to the same financial measures utilized by management. Operating profit, alternatively, includes depreciation and amortization expense and general and administrative (“G&A”) expense that management does not consider when evaluating the core profitability of an operation. Adjusted EBITDA is an important measure utilized by management and the investment community to assess the financial results of an entity.

Since the non-GAAP measures presented here include adjustments specific to us, they may not be comparable to similarly-titled measures of other companies.



	Year Ended December 31,
	2010			2011			2012			2013			2014
	(in thousands, except per unit amounts)
Income Statement Data:
Transportation and terminals revenue	$	793,599		$	893,369		$	970,744		$	1,138,328		$	1,402,638
Product sales revenue	763,090			854,528			799,382			744,669			878,974
Affiliate management fee revenue	758			770			1,948			14,609			22,111
Total revenue	1,557,447			1,748,667			1,772,074			1,897,606			2,303,723
Operating expenses	282,212			306,415			328,454			346,070			444,272
Cost of product sales	668,585			706,270			657,108			578,029			594,585
Earnings of non-controlled entities	(5,732		)	(6,763		)	(2,961		)	(6,275		)	(19,394		)
Operating margin	612,382			742,745			789,473			979,782			1,284,260
Depreciation and amortization expense	108,668			121,179			128,012			142,230			161,741
G&A expense	95,316			98,669			109,403			132,496			148,288
Operating profit	408,398			522,897			552,058			705,056			974,231
Interest expense, net	93,296			105,634			111,679			115,782			119,186
Debt placement fee amortization	1,401			1,831			2,087			2,424			2,333
Other expense^(a)	750			—			—			—			8,573
Income before provision for income taxes	312,951			415,432			438,292			586,850			844,139
Provision for income taxes	1,371			1,866			2,622			4,613			4,620
Net income	$	311,580		$	413,566		$	435,670		$	582,237		$	839,519

Net income allocation:
Limited partner interests	$	311,977		$	413,629		$	435,670		$	582,237		$	839,519
Non-controlling owners' interest^(b)	(397		)	(63		)	—			—			—
Net income	$	311,580		$	413,566		$	435,670		$	582,237		$	839,519
Basic net income per limited partner unit	$	1.42		$	1.83		$	1.92		$	2.57		$	3.69
Diluted net income per limited partner unit	$	1.42		$	1.83		$	1.92		$	2.56		$	3.69
Balance Sheet Data:
Working capital (deficit)^(c)	$	109,536		$	301,135		$	307,658		$	(241,543	)	$	(133,488	)
Total assets	$	3,717,900		$	4,045,001		$	4,420,067		$	4,820,812		$	5,517,285
Long-term debt (excluding current portion)	$	1,906,148		$	2,151,775		$	2,393,408		$	2,435,316		$	2,982,895
Owners’ equity	$	1,469,571		$	1,463,403		$	1,515,702		$	1,647,442		$	1,868,233
Cash Distribution Data:
Cash distributions declared per unit^(d)	$	1.48		$	1.59		$	1.88		$	2.18		$	2.62
Cash distributions paid per unit^(d)	$	1.45		$	1.56		$	1.78		$	2.10		$	2.51



	Year Ended December 31,
	2010			2011			2012			2013			2014
	(in thousands, except operating statistics)
Other Data:
Operating margin:
Refined products	$	491,290		$	574,030		$	592,828		$	693,985		$	870,205
Crude oil	28,517			74,225			91,367			176,420			295,830
Marine storage	89,566			91,571			102,323			106,198			114,712
Allocated partnership depreciation costs^(e)	3,009			2,919			2,955			3,179			3,513
Operating margin	$	612,382		$	742,745		$	789,473		$	979,782		$	1,284,260

Adjusted EBITDA and distributable cash flow:
Net income	$	311,580		$	413,566		$	435,670		$	582,237		$	839,519
Interest expense, net, and provision for income taxes	94,667			107,500			114,301			120,395			123,806
Depreciation and amortization expense^(f)	110,069			123,010			130,099			144,654			164,074
Equity-based incentive compensation expense^(g)	15,499			10,243			8,038			11,823			12,471
Asset retirements and impairments	1,062			8,599			12,622			7,835			7,223
Commodity-related adjustments^(h)	7,751			(22,370		)	12,894			(339		)	(56,288		)
Other⁽ⁱ⁾	(1,582		)	(2,504		)	4,850			(409		)	(8,724		)
Adjusted EBITDA	539,046			638,044			718,474			866,196			1,082,081

Interest expense, net, and provision for income taxes	(94,667		)	(107,500		)	(114,301		)	(120,395		)	(123,806		)
Maintenance capital (net of reimbursements)	(44,620		)	(70,002		)	(64,396		)	(76,081		)	(77,806		)
Distributable cash flow	$	399,759		$	460,542		$	539,777		$	669,720		$	880,469

Operating Statistics:
Refined products:^(j)
Transportation revenue per barrel shipped	$	1.197		$	1.175		$	1.230		$	1.313		$	1.399
Volume shipped (million barrels):
Gasoline	194.3			208.9			223.7			239.7			256.1
Distillates	122.9			136.0			136.7			146.5			163.1
Aviation fuel	22.6			25.3			21.5			21.1			23.0
Liquefied petroleum gases	5.0			4.9			8.5			7.8			9.9
Total volume shipped	344.8			375.1			390.4			415.1			452.1
Crude oil:^(j)
Transportation revenue per barrel shipped	$	0.283		$	0.275		$	0.305		$	0.880		$	1.192
Volume shipped (million barrels)	14.7			43.2			72.0			113.2			185.5
Crude oil terminal average utilization (million barrels per month)	3.4			9.3			12.6			12.3			12.2
Marine storage:
Marine terminal average utilization (million barrels per month)	24.0			24.7			23.8			23.0			22.9


(a)	Other expense for 2014 was a non-cash charge for the change in the differential between the current spot price and forward price on fair value hedges associated with our tank bottoms and linefill assets.


(b)	Magellan Crude Oil, LLC ("MCO") was formed in 2010, and was partially owned by a private investment group. In February 2011, we acquired all of the non-controlling owners' interest in MCO. These amounts reflect the private investment group's proportional share of the losses of MCO for these periods.


(c)	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.


(d)	Cash distributions declared represent distributions declared associated with the distributable cash flow generated for 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.


(e)	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.


(f)	Includes debt placement fee amortization.


(g)	Excludes the tax withholdings on settlement of these equity-based incentive awards, which were paid in cash.


(h)	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.


(i)	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.

(j)

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

Introduction

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


•	our refined products segment, comprised of our 9,500-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 marine storage segment, consisting of marine terminals located along coastal waterways with an aggregate storage capacity of approximately 26 million barrels.

The following discussion provides an analysis of the results for each of our operating segments, an overview of our liquidity and capital resources and other items related to our partnership. The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this annual report on Form 10-K for the year ended December 31, 2014.

Recent Developments

BridgeTex Pipeline. BridgeTex pipeline began commercial service in September 2014, delivering crude oil from West Texas to the Houston Gulf Coast area. Crude deliveries on the BridgeTex pipeline during fourth quarter 2014 averaged nearly 200,000 barrels per day. Deliveries are expected to continue to ramp up over time, as the BridgeTex pipeline is capable of transporting up to 300,000 barrels per day of crude oil. We do not consolidate BridgeTex in our financial statements, but we recognize our 50% share of its profits in our consolidated statements of income as earnings of non-controlled entities. BridgeTex's net income for 2014 was $30.7 million (our 50% share was $15.3 million); however, we did not recognize any amounts from BridgeTex's earnings in our 2014 distributable cash flow as the cash distributions paid to us on these earnings will not be made until the first quarter of 2015.

In November 2014, in connection with Occidental Petroleum Corporation's ("Oxy") sale of its ownership interest in BridgeTex to a third party, we acquired Oxy's ownership interest in a 40-mile crude oil pipeline that extends from our East Houston, Texas terminal to Texas City, Texas, and 1.4 million barrels of crude oil tankage and related infrastructure at our East Houston, Texas terminal for $75.0 million. Concurrent with these transactions, BridgeTex entered into a long-term lease agreement for capacity on our Houston-area crude oil distribution system.

Cash Distribution. In January 2015, the board of directors of our general partner declared a quarterly cash distribution of $0.695 per unit for the period of October 1, 2014 through December 31, 2014. This quarterly cash distribution was paid on February 13, 2015 to unitholders of record on February 6, 2015. The total distribution paid on 227.4 million limited partner units outstanding was $158.1 million.

Impact of Commodity Prices. Our operating margin is generated primarily from fee-based services for the transportation, storage and distribution of refined petroleum products and crude oil. However, a portion of our operating margin is directly or indirectly impacted by commodity prices, including the product margin we earn from our butane blending activities and the value of product overages on our refined products and crude oil pipelines (which reduce operating expenses). In recent months, the prices of petroleum products, such as gasoline and crude oil, have declined considerably, which will result in lower profits from our commodity-related activities and product

overages. Further, although a significant portion of our crude oil pipeline volumes are supported by customer commitments, lower crude oil prices could result in lower demand for spot shipments, reducing the transportation revenues we generate. If commodity prices remain low throughout 2015, we expect to generate less net income and distributable cash flow than in 2014. Even at these current lower commodity levels, we expect to generate distributable cash flow more than sufficient to achieve our goal of 15% distribution growth to our investors for 2015.

Overview

Our pipelines and terminals generate the majority of our operating margin from the transportation and storage services we provide to our customers. The revenue generated from these activities is significantly influenced by demand for refined products and crude oil. In addition, we generate operating margin from commodity-related activities. Operating expenses are principally fixed costs related to routine maintenance and system integrity as well as field and support personnel. Other costs, including power, fluctuate with volumes transported on our pipelines and stored in our terminals.

Refined Products. Our common carrier pipeline system is comprised of 9,500 miles of pipeline and 53 terminals that provide transportation, storage and distribution services for refined products in a 15-state area across the central United States. Through direct refinery connections and interconnections with other interstate pipelines, our refined products pipeline can access approximately 48% of the U.S. refining capacity. In 2014, the refined products segment generated 69% of its revenue, excluding the sale of refined products, primarily through transportation tariffs for refined products shipped. These tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All interstate transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”). The pipeline also earns revenue from non-tariff based activities, including leasing pipeline and storage tank capacity to customers and by providing data services and product services such as ethanol and biodiesel unloading and loading, additive injection, terminalling, custom blending and laboratory testing. Substantially all of the shipments on our refined products pipeline are for third parties, and we do not take title to these products. We do take title to products related to our butane blending and fractionation activities and in connection with certain transactions involving the operation of our refined products pipeline and terminals.

Our blending activities involve purchasing liquefied petroleum gases and blending them into gasoline, which creates additional gasoline available for us to sell. Our fractionation activities include three 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 refined product pipelines. We also purchase transmix from third parties.

Our independent terminals consist of 27 refined products terminals that are part of a distribution network located principally throughout the southeastern U.S. that are connected to large, third-party interstate pipelines. We earn revenue at our independent terminals primarily from fees we charge based on the volumes of refined products distributed from these locations.

Our ammonia pipeline consists of 1,100 miles of pipeline that transports and distributes anhydrous 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.

Crude Oil. Our crude oil segment includes approximately 1,600 miles of pipeline and 12 million barrels of crude oil storage used for leased storage. Our 450-mile Longhorn pipeline, which began crude oil service operations in early 2013, originates in 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 pipelines. We also own approximately 300 miles of pipeline in Kansas and Oklahoma currently used for crude oil service. Revenues on our crude oil pipelines are generated primarily through transportation tariffs for crude oil shipped, as well as from leasing pipeline capacity to third parties.

Our terminal in Cushing, Oklahoma consists of approximately 10 million barrels of crude oil storage used for leased storage and is located in one of the largest crude oil trading hubs in the U.S. Our terminals at East Houston and Corpus Christi, Texas each include approximately one million barrels of crude oil storage used for leased storage. These facilities earn revenues primarily through leased storage and throughput fees.

Our crude oil segment also includes ownership interests in the following joint ventures:


•	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, Texas. Double Eagle is operated by an affiliate of the other joint venture member; and


•	a 50% interest in BridgeTex, which owns a 400-mile pipeline that transports crude oil to our East Houston terminal for further distribution to refineries in the Gulf Coast region. This pipeline began service in September 2014.

Marine Storage. Our marine storage segment consists of storage terminals, which store and distribute refined products. Our storage terminals are comprised of five facilities that have marine access in New Haven, Connecticut, Wilmington, Delaware, Marrero, Louisiana, and Corpus Christi and Galena Park, Texas that are located near major refining hubs along the U.S. Gulf and East Coasts. Our marine storage terminals have an aggregate storage capacity of approximately 25 million barrels of wholly-owned storage and approximately one million barrels of storage from our 50%-owned joint venture, Texas Frontera, LLC ("Texas Frontera"). Because the rates charged at these terminals are unregulated, the marketplace determines the prices we can charge for our services. We earn revenue through storage and ancillary fees, including product heating, blending, mixing and additive injection for refiners and other large end users of refined products.

Growth Projects

We remain focused on growth and have significantly increased our operations over the past several years through organic growth projects and acquisitions that expand or upgrade our existing facilities. During 2013 and 2014, we spent $772.7 million and $783.5 million, respectively, for expansion capital, acquisitions and investments in non-controlled entities on a combined basis, primarily related to the expansion and conversion of our Longhorn pipeline to crude oil service, construction of the BridgeTex pipeline and acquisition of 800 miles of refined products pipeline in the Rocky Mountains and New Mexico during 2013 and acquisition of 40 miles of crude oil pipeline in the Houston area during 2014.

Our current expansion plans include the following significant projects:

Condensate Splitter. In March 2014, we announced plans to construct a condensate splitter at our terminal in Corpus Christi, Texas under a fee-based, take-or-pay agreement with a third-party customer. The project also includes construction of more than one million barrels of storage, dock improvements and two additional truck rack bays at our terminal as well as pipeline connectivity between our terminal and a nearby third-party facility. The splitter will be capable of processing 50,000 barrels per day of condensate. We expect the condensate splitter and related infrastructure to cost approximately $250 million and to be operational during the second half of 2016, subject to receipt of necessary permits and authorizations.

Little Rock Pipeline. In May 2014, we announced plans to develop a pipeline system capable of transporting refined products from our Ft. Smith, Arkansas terminal to Little Rock, Arkansas. We have entered into an agreement with a third party to utilize an existing pipeline for a portion of the route, which we will extend to our Ft. Smith terminal and to the Little Rock market with approximately 50 miles of newly-constructed pipeline. We further plan to make enhancements to our pipeline system to accommodate additional volumes. The Little Rock pipeline project

is expected to cost approximately $150 million and to be operational in early 2016, subject to receipt of regulatory and other approvals.

Saddlehorn Pipeline. In October 2014, we announced plans to construct a pipeline to transport crude oil from the Niobrara play in northeast Colorado to our storage facilities in Cushing, Oklahoma. The Saddlehorn pipeline project includes construction of an approximate 600-mile pipeline capable of transporting up to 400,000 barrels per day of crude oil. We have received binding commitments from two entities for shipments on this pipeline. We are currently in the process of obtaining permits and rights-of-way and expect to complete the pipeline in mid-2016, subject to receipt of any necessary permits and regulatory approvals. The estimated construction cost of the pipeline, which considers recent cost revisions, is in the range of approximately $800 to $850 million, and we are currently in discussions with third parties regarding potential equity ownership in the project.

We currently expect to spend approximately $650 million in 2015 and $100 million in 2016 to complete the expansion construction projects currently underway. These expansion capital estimates exclude potential acquisitions, construction of the Saddlehorn pipeline (because the ownership structure is not yet known) or spending on more than $500 million of other potential growth projects in earlier stages of development.

Results of Operations

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

Year Ended December 31, 2013 Compared to Year Ended December 31, 2014



	Year Ended December 31,						Variance Favorable (Unfavorable)
	2013			2014			$ Change			% Change
Financial Highlights ($ in millions, except operating statistics)
Transportation and terminals revenue:
Refined products	$	801.1		$	921.8		$	120.7		15	%
Crude oil	178.4			310.1			131.7			74	%
Marine storage	158.8			170.7			11.9			7	%
Total transportation and terminals revenue	1,138.3			1,402.6			264.3			23	%
Affiliate management fee revenue	14.6			22.1			7.5			51	%
Operating expenses:
Refined products	270.7			331.2			(60.5		)	(22	)%
Crude oil	19.1			51.4			(32.3		)	(169	)%
Marine storage	59.4			65.2			(5.8		)	(10	)%
Intersegment eliminations	(3.1		)	(3.5		)	0.4			13	%
Total operating expenses	346.1			444.3			(98.2		)	(28	)%
Product margin:
Product sales	744.7			879.0			134.3			18	%
Cost of product sales	578.0			594.6			(16.6		)	(3	)%
Product margin ^(a)	166.7			284.4			117.7			71	%
Earnings of non-controlled entities	6.3			19.4			13.1			208	%
Operating margin	979.8			1,284.2			304.4			31	%
Depreciation and amortization expense	142.2			161.7			(19.5		)	(14	)%
G&A expense	132.6			148.3			(15.7		)	(12	)%
Operating profit	705.0			974.2			269.2			38	%
Interest expense (net of interest income and interest capitalized)	115.8			119.2			(3.4		)	(3	)%
Debt placement fee amortization	2.4			2.3			0.1			4	%
Other expense	—			8.6			(8.6		)	n/a
Income before provision for income taxes	586.8			844.1			257.3			44	%
Provision for income taxes	4.6			4.6			—			—	%
Net income	$	582.2		$	839.5		$	257.3		44	%

Operating Statistics
Refined products:
Transportation revenue per barrel shipped	$	1.313		$	1.399
Volume shipped (million barrels):
Gasoline	239.7			256.1
Distillates	146.5			163.1
Aviation fuel	21.1			23.0
Liquefied petroleum gases	7.8			9.9
Total volume shipped	415.1			452.1
Crude oil:
Transportation revenue per barrel shipped	$	0.880		$	1.192
Volumes shipped (million barrels)	113.2			185.5
Crude oil terminal average utilization (million barrels per month)	12.3			12.2
Marine storage:
Marine terminal average utilization (million barrels per month)	23.0			22.9


(a)	Product margin does not include depreciation or amortization expense.

Transportation and terminals revenue increased by $264.3 million, resulting from:

•

an increase in refined products revenue of $120.7 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products revenue increased $92.3 million primarily due to a 4% increase in transportation volumes, higher average rates and higher ancillary revenues associated with increased activity. Shipments were higher primarily due to increased demand for distillates and gasoline in the markets we serve. The average rate per barrel in the current period was impacted by the mid-year 2013 and 2014 tariff rate increases of 4.6% and 3.9%, respectively, and more long-haul shipments at higher rates;


•	an increase in crude oil revenue of $131.7 million primarily due to crude oil deliveries from our Longhorn pipeline, which represented approximately 90% of the increase. Our Longhorn pipeline averaged approximately 125,000 barrels per day during 2013 after its mid-April start date, while deliveries averaged approximately 230,000 barrels per day during 2014; and


•	an increase in marine storage revenue of $11.9 million primarily due to higher storage rates from contract renewals and annual escalations, a one-time adjustment associated with one of our storage contracts (which increased 2014 revenues) and the one-time benefit from a customer buying out of its remaining storage contract in 2014.

Affiliate management fee revenue increased $7.5 million, primarily resulting from an increase in management fees received from BridgeTex in 2014 to reimburse us for our costs of providing construction services to BridgeTex. We are now receiving operating management fees from BridgeTex as its operations began in late September 2014.

Operating expenses increased $98.2 million, resulting from:

•

an increase in refined products expenses of $60.5 million. Excluding the pipeline systems we acquired in the second half of 2013, refined products expenses increased $38.9 million primarily due to additional costs in the current year for property taxes, personnel, pipeline rental primarily related to a pipeline segment we began leasing in 2014, asset integrity and power costs, less favorable product overages (which reduce operating expenses), as well as a favorable adjustment in 2013 of an accrual for potential air emission fees at our East Houston facility;


•	an increase in crude oil expenses of $32.3 million primarily due to higher shipments on our Longhorn pipeline in 2014, including higher power expenses and pipeline rental fees, as well as higher personnel costs, asset integrity expense and property taxes now that we have more assets in crude oil service, partially offset by more favorable product overages (which reduce operating expenses); and


•	an increase in marine storage expenses of $5.8 million primarily due to a favorable adjustment in 2013 of an accrual for potential air emission fees at our Galena Park facility, partially offset by lower losses on asset retirements in the current year.

Product sales revenue primarily resulted from our butane blending activities, transmix fractionation and product gains from our independent terminals. We utilize New York Mercantile Exchange (“NYMEX”) contracts to hedge against changes in the price of petroleum products we expect to sell in the future. The period change in the mark-to-market value of these contracts that are not designated as hedges for accounting purposes, the effective portion of the change in value of matured NYMEX contracts that qualified as cash flow hedges and any ineffectiveness of NYMEX contracts that qualified as cash flow hedges are also included in product sales revenue. We use butane futures agreements to hedge against changes in the price of butane we expect to purchase in future periods. The period change in the mark-to-market value of these futures agreements, which were not designated as hedges, are included as adjustments to cost of product sales. Product margin increased $117.7 million primarily due to gains on NYMEX contracts in the current year versus losses in the prior year, and higher profits from our butane blending activities resulting from higher volumes sold and lower butane costs, partially offset by a $39.3 million lower-of-cost-or-market inventory adjustment to our fractionation and butane blending inventories in the current

year due to the significant decline in commodity prices at the end of 2014. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.

Earnings of non-controlled entities increased $13.1 million primarily due to contributions from BridgeTex, which began operations late in 2014.

Depreciation and amortization expense increased $19.5 million in 2014 primarily due to expansion capital projects placed into service and acquisitions. Additionally, based on an impairment analysis we performed, we accelerated the depreciation of a certain terminal and related assets for the year ended December 31, 2014 by $9.4 million.

G&A expense increased $15.7 million between periods primarily due to higher personnel costs resulting from an increase in employee headcount, higher pension and benefit costs and higher equity-based compensation costs primarily due to a higher price for our limited partner units.

Interest expense, net of interest income and interest capitalized, increased $3.4 million in 2014. Our average outstanding debt increased from $2.5 billion in 2013 to $2.9 billion in 2014 primarily due to borrowings for expansion capital expenditures, including $300.0 million of 5.15% senior notes issued in October 2013 and $250.0 million of 5.15% senior notes issued in March 2014. Our weighted-average interest rate decreased from 5.2% at December 31, 2013 to 4.9% at December 31, 2014.

Other expense for 2014 includes an $8.6 million non-cash charge for the change in the differential between the current spot price and forward price on fair value hedges associated with our crude oil tank bottoms and linefill assets.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2013



	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.

Transportation and terminals revenue increased by $167.6 million, resulting from:

•

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 from its mid-April start date through December 31, 2013. 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.

Affiliate management fee revenue increased $12.6 million, primarily resulting from a full year of construction management fees received from BridgeTex in 2013 to reimburse us for our costs of providing construction services to BridgeTex, compared to one month of fees received in 2012.

Operating expenses increased $17.6 million, resulting from:

•

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 and lower environmental accruals. The higher compensation costs were due to increased employee headcount and higher bonus accruals. The higher power costs primarily reflected the increase in product shipments over 2012 and the higher property taxes were the result of asset additions and improved profitability;

•

an increase in crude oil expenses of $13.9 million primarily due to costs related to the operation of our Longhorn pipeline, which we placed into crude oil service during 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 2013 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 and lower environmental accruals.

Product margin increased $24.4 million primarily due to lower unrealized losses on NYMEX contracts in 2013 and higher profits from our butane blending activities resulting from higher volumes sold and lower butane costs. See Other Items—Commodity Derivative Agreements—Impact of Commodity Derivatives on Results of Operations below for more information about our NYMEX contracts.

Earnings of non-controlled entities increased $3.3 million primarily due to earnings of Texas Frontera, which began operations late in 2012, and higher earnings from Osage.

Depreciation and amortization expense increased $14.2 million in 2013 primarily due to expansion capital projects and acquisitions placed into service over the previous two years.

G&A expense increased $23.2 million between periods primarily due to higher personnel costs resulting from an increase in employee headcount and an increase in the 2013 bonus accrual resulting from above-target payout estimates, higher equity-based compensation costs due to above-target payout estimates and a higher price for our limited partner units and higher legal costs related to acquisitions we closed in 2013.

Interest expense, net of interest income and interest capitalized, increased $4.1 million in 2013. Our average outstanding debt increased from $2.2 billion in 2012 to $2.5 billion in 2013 primarily due to borrowings for expansion capital expenditures, including $250.0 million of 4.20% senior notes issued in November 2012 and $300.0 million of 5.15% senior notes issued in October 2013. Our weighted-average interest rate decreased slightly from 5.3% at December 31, 2012 to 5.2% at December 31, 2013.

Distributable Cash Flow

Distributable cash flow ("DCF") and Adjusted EBITDA are non-GAAP measures. Management uses DCF as a basis for recommending to our general partner's board of directors the amount of cash distributions to be paid each period. Management also uses DCF to evaluate our ability to generate cash for distribution to our limited partners and as a basis for determining equity-based compensation. Adjusted EBITDA is an important measure that we and the investment community use to assess the financial results of an entity. We believe that investors benefit from having access to the same financial measures utilized by management for these evaluations. A reconciliation of DCF and Adjusted EBITDA for the years ended December 31, 2012, 2013 and 2014 to net income, which is the nearest comparable GAAP financial measure, is as follows (in millions):



	Year Ended December 31,
	2012			2013			2014
Net income	$	435.7		$	582.2		$	839.5
Interest expense, net, and provision for income taxes	114.3			120.4			123.8
Depreciation and amortization expense⁽¹⁾	130.1			144.7			164.1
Equity-based incentive compensation expense⁽²⁾	8.0			11.8			12.5
Loss on sale and retirement of assets	12.6			7.8			7.2
Commodity-related adjustments:
Derivative losses (gains) recognized in the period associated with future product transactions⁽³⁾	6.4			8.1			(87.5		)
Derivative (losses) gains recognized in previous periods associated with product sales completed in the period⁽⁴⁾	3.7			(6.4		)	(8.1		)
Lower-of-cost-or-market inventory adjustments	1.0			(2.0		)	39.3
Houston-to-El Paso cost of sales adjustments⁽⁵⁾	1.8			—			—
Total commodity-related adjustments	12.9			(0.3		)	(56.3		)
Earnings of non-controlled entities, net of distributions received	4.9			(0.4		)	(8.7		)
Adjusted EBITDA	718.5			866.2			1,082.1
Interest expense, net, and provision for income taxes	(114.3		)	(120.4		)	(123.8		)
Maintenance capital⁽⁶⁾	(64.4		)	(76.1		)	(77.8		)
DCF	$	539.8		$	669.7		$	880.5


(1)	Depreciation and amortization includes debt placement fee amortization. Based on an impairment analysis we performed in 2014, we accelerated the depreciation of a certain terminal and related assets for the year ended December 31, 2014 by $9.4 million.

(2)

Because 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 to net income to calculate DCF. Total equity-based incentive compensation expense for the years ended December 31, 2012, 2013 and 2014 was $21.0 million, $24.1 million and $27.3 million, respectively. However, the figures above include an adjustment for minimum statutory tax withholdings we

paid in 2012, 2013 and 2014 of $13.0 million, $12.3 million and $14.8 million, respectively, for equity-based incentive compensation units that vested at 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. In addition, we have designated certain derivatives we use to hedge our crude oil tank bottoms and linefill assets as fair value hedges and the change in the differential between the current spot price and forward price on these hedges is recognized currently in earnings. We exclude the net impact of both of these adjustments from our determination of DCF until the hedged products are physically sold.


(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 adjustments 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 performed this activity.


(6)	Maintenance capital expenditure projects maintain our existing assets and do not generate incremental DCF (i.e. incremental returns to our unitholders), while expansion capital projects are undertaken primarily to generate incremental DCF. For this reason, we deduct maintenance capital expenditures to determine DCF.

Liquidity and Capital Resources

Cash Flows and Capital Expenditures

Operating Activities. Cash provided by operations is net income adjusted for certain non-cash items and changes in certain assets and liabilities.