ENTERPRISE PRODUCTS PARTNERS L.P. - Annual Report: 2012 (Form 10-K)

DELAWARE		76-0568219
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)
	1100 LOUISIANA STREET, 10th FLOOR, HOUSTON, TEXAS 77002
	(Address of Principal Executive Offices) (Zip Code)
	(713) 381-6500
	(Registrant's Telephone Number, Including Area Code)

 

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ENTERPRISE PRODUCTS PARTNERS L.P.

		Page
		Number
PART I
Item 1 and 2.	Business and Properties.	2
Item 1A.	Risk Factors.	44
Item 1B.	Unresolved Staff Comments.	64
Item 3.	Legal Proceedings.	64
Item 4.	Mine Safety Disclosures.	65
PART II
Item 5.	Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.	65
Item 6.	Selected Financial Data.	67
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	68
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	101
Item 8.	Financial Statements and Supplementary Data.	105
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	105
Item 9A.	Controls and Procedures.	105
Item 9B.	Other Information.	108
PART III
Item 10.	Directors, Executive Officers and Partnership Governance.	108
Item 11.	Executive Compensation.	117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	128
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	131
Item 14.	Principal Accounting Fees and Services.	134
PART IV
Item 15.	Exhibits and Financial Statement Schedules.	135
Signatures		145

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KEY REFERENCES USED IN THIS REPORT

Unless the context requires otherwise, references to "we," "us," "our," "Enterprise" or "Enterprise Products Partners" are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.  References to "EPO" mean Enterprise Products Operating LLC, which is a wholly owned subsidiary of Enterprise, and its consolidated subsidiaries, through which Enterprise Products Partners L.P. conducts its business.  Enterprise is managed by its general partner, Enterprise Products Holdings LLC ("Enterprise GP"), which is a wholly owned subsidiary of Dan Duncan LLC, a Texas limited liability company.

The membership interests of Dan Duncan LLC are owned of record by a voting trust, the current trustees ("DD LLC Trustees") of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Enterprise GP; (ii) Dr. Ralph S. Cunningham, who is also a director of Enterprise GP; and (iii) Richard H. Bachmann, who is also a director of Enterprise GP.  Each of the DD LLC Trustees also currently serves as one of the three managers of Dan Duncan LLC.

References to "EPCO" mean Enterprise Products Company, a Texas corporation, and its privately held affiliates.  A majority of the outstanding voting capital stock of EPCO is owned of record by a voting trust, the current trustees ("EPCO Trustees") of which are:  (i) Ms. Williams, who also serves as Chairman of EPCO; (ii) Dr. Cunningham, who also serves as a Vice Chairman of EPCO; and (iii) Mr. Bachmann, who also serves as the President and Chief Executive Officer ("CEO") of EPCO.  Each of the EPCO Trustees is also a director of EPCO. 

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

/d		= per day	MMBbls		= million barrels
BBtus		= billion British thermal units	MMBPD		= million barrels per day
Bcf		= billion cubic feet	MMBtus		= million British thermal units
BPD		= barrels per day	MMcf		= million cubic feet
MBPD		= thousand barrels per day	TBtus		= trillion British thermal units

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2012 (our "annual report") contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.  When used in this document, words such as "anticipate," "project," "expect," "plan," "seek," "goal," "estimate," "forecast," "intend," "could," "should," "will," "believe," "may," "potential" and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements.  Although we and our general partner believe that our expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.  Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected.  You should not put undue reliance on any forward-looking statements.  The forward-looking statements in this annual report speak only as of the date hereof.  Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

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We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange ("NYSE") under the ticker symbol "EPD."  We were formed in April 1998 to own and operate certain natural gas liquids ("NGLs") related businesses of EPCO and are now a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. 

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States ("U.S."), Canada and the Gulf of Mexico with domestic consumers and international markets.  Our midstream energy operations include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage, and import and export terminals; crude oil gathering and transportation, storage and terminals; offshore production platforms; petrochemical and refined products transportation and services; and a marine transportation business that operates primarily on the U.S. inland and Intracoastal Waterway systems and in the Gulf of Mexico.  Our assets include approximately 50,000 miles of onshore and offshore pipelines; 200 MMBbls of storage capacity for NGLs, petrochemicals, refined products and crude oil; and 14 Bcf of natural gas storage capacity.  In addition, our asset portfolio includes 24 natural gas processing plants, 21 NGL and propylene fractionators, six offshore hub platforms located in the Gulf of Mexico, a butane isomerization complex, NGL import and export terminals, and octane enhancement and high-purity isobutylene production facilities.

We completed mergers with our affiliates Duncan Energy Partners L.P. ("Duncan Energy Partners") and Enterprise GP Holdings L.P. ("Holdings") in September 2011 and November 2010, respectively.  We believe these recent merger transactions streamlined and simplified our organizational structure to be more transparent to investors, removed potential conflicts of interest due to common control considerations and reduced public company overhead costs.  For additional information regarding these business combinations, see "Duncan and Holdings Mergers" within this Item 1 and 2 discussion.

We completed the merger of TEPPCO Partners, L.P. ("TEPPCO") and its general partner with our wholly-owned subsidiaries in October 2009.  TEPPCO was a publicly traded energy logistics company that owned and operated a network of midstream energy assets.  As a result of this merger, we acquired approximately 12,500 miles of pipelines that gather and transport refined petroleum products, crude oil, natural gas and NGLs.   In addition, we acquired our marine transportation business from TEPPCO.

Like many publicly traded partnerships, we have no employees.  All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers.  As of February 1, 2013, there were approximately 6,600 EPCO personnel who spend all or a portion of their time engaged in our business.  Approximately 6,400 of these individuals devote substantially all of their time to our affairs.  For additional information regarding the ASA, see "—EPCO Administrative Services Agreement" under Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Business Strategy

Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil in some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets.  Our business strategies are to:

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§

capitalize on expected increases in the production of natural gas, NGLs and crude oil from development activities in various producing basins including the Rocky Mountains, Midcontinent, Northeast and U.S. Gulf Coast regions, deepwater Gulf of Mexico and developing shale plays, including the Barnett, Eagle Ford, Haynesville, Marcellus, Mancos and Utica Shales;

§	capitalize on expected demand growth for natural gas, NGLs, crude oil and petrochemical and refined products;

§	maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary midstream energy assets;

§	enhance the stability of our cash flows by investing in pipelines and other fee-based businesses; and

§	share capital costs and risks through joint ventures or alliances with strategic partners, including those that will provide the raw materials for these growth capital projects or purchase the projects' end products.

As noted above, part of our business strategy involves expansion through growth capital projects.  We expect that these projects will enhance our existing asset base and provide us with additional growth opportunities in the future.

Major Customer

 

Our consolidated revenues are derived from a wide customer base.  Our largest non-affiliated customer for 2012 was BP p.l.c. and its affiliates ("collectively, "BP"), which accounted for 9.5% of our consolidated revenues for this period.  Our largest non-affiliated customer for 2011 and 2010 was Shell Oil Company and its affiliates, which accounted for 10.6% and 9.4% of our consolidated revenues during these years, respectively.  For information regarding our revenue recognition policies, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

 

Business Segments

The following sections provide an overview of our business segments, including information regarding principal products produced, services rendered, properties owned, seasonality and competition.  We have five reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Onshore Crude Oil Pipelines & Services; (iv) Offshore Pipelines & Services; and (v) Petrochemical & Refined Products Services.  Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

All activities included in our former sixth reportable business segment, Other Investments, ceased on January 18, 2012, which was the date we discontinued using the equity method to account for our previously held investment in Energy Transfer Equity, L.P. ("Energy Transfer Equity").  For information about our former investment in Energy Transfer Equity, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Each of our business segments benefits from the supporting role of our related marketing activities.  The main purpose of our marketing activities is to support the utilization of assets across our midstream energy network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment.  In performing these support roles, our marketing activities also seek to take advantage of supply and demand opportunities in order to maximize earnings for the partnership.  The financial results of our marketing efforts fluctuate period-to-period due to changes in volumes handled and overall market conditions, which may be influenced by current and forward market prices for the products bought and sold.

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For detailed financial information regarding our business segments (including our consolidated revenues by segment), see Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.  Such financial information is incorporated by reference into this Item 1 and 2 discussion.  In addition, we utilize derivative instruments in connection with certain of our operations.  For information regarding our use of derivative instruments, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our results of operations and financial condition are subject to certain significant risks.  For information regarding these risks, see Part I, Item 1A of this annual report.   In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters.   For a discussion of the principal effects of such laws and regulations on our business activities, see "Regulation" and "Environmental and Safety Matters" within this Item 1 and 2 discussion.

For management's discussion and analysis of our historical results of operations and a discussion of our liquidity and capital resources, see Part II, Item 7 of this annual report.

NGL Pipelines & Services

Our NGL Pipelines & Services business segment includes our natural gas processing plants and related NGL marketing activities; approximately 16,700 miles of NGL pipelines; NGL and related product storage facilities; and 14 NGL fractionators.  This segment also includes our NGL import and export terminal operations.

Purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as feedstocks by the petrochemical industry, as feedstocks by refineries in the production of motor gasoline and by industrial and residential consumers as fuel.  Ethane is primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products.  Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel.  Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to produce isobutane through isomerization.  Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives and in the production of propylene oxide.  Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock.

Natural gas processing plants and related NGL marketing activities.  At the core of our natural gas processing business are 24 processing plants located across Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming.

In its raw form, natural gas produced at the wellhead (especially in association with crude oil) contains varying amounts of mixed NGLs. Natural gas streams containing NGLs are usually not acceptable for transportation in natural gas pipelines or for commercial use as a fuel and must be sent to natural gas processing plants to remove the NGLs.   Once the natural gas is processed with NGLs and impurities removed, the natural gas will meet pipeline and commercial quality specifications.   On an energy equivalent basis, most NGLs generally have greater economic value as feedstock for petrochemical and motor gasoline production than their value as components of a natural gas stream.

Once the mixed component NGLs are extracted by a natural gas processing plant, they are typically transported to a centralized fractionation facility for separation into purity NGL products.  The NGL products that we obtain through our processing arrangements (i.e., our equity NGL production volumes) or purchase directly from third parties are used in our NGL marketing activities to meet contractual requirements or sold on spot and forward markets.  Also, we purchase raw natural gas streams from producers in connection with our natural gas processing activities.  Once processed, this natural gas is available for sale through our natural gas marketing activities.

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In our natural gas processing business, we utilize contracts that are either fee-based, commodity-based or a combination of the two.  When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer's natural gas has been processed and redelivered.  In recent years, our portfolio of natural gas processing contracts has become increasingly weighted towards those with fee-based terms as producers seek to maximize the value of their production by retaining all or a portion of the NGLs extracted from their natural gas stream.  We currently estimate that the terms of approximately 35% of our portfolio of natural gas processing contracts are entirely fee-based, with an additional 27% of this portfolio including a combination of fee-based and commodity-based terms.  The terms of the remaining 38% of our portfolio of natural gas processing contracts are entirely commodity-based.

Our commodity-based contracts include keepwhole and margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts and contracts featuring a combination of commodity and fee-based terms. Under keepwhole and margin-band contracts, we take ownership of mixed NGLs extracted from the producer's natural gas stream while replacing the equivalent quantity of energy on a natural gas basis to producers.  We recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.  Under percent-of-liquids contracts, we take ownership of a portion of the mixed NGLs extracted from the producer's natural gas stream (in lieu of a cash processing fee) and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts.  Under percent-of-proceeds contracts, we share in the proceeds generated from the sale of mixed NGLs we extract on the producer's behalf (in lieu of a cash processing fee).  In certain cases, we also utilize contracts that include a combination of commodity-based terms (such as those described above) and fee-based terms.

Generally, our natural gas processing agreements have terms ranging from month-to-month to life of the producing lease.  Intermediate terms of one to ten years are also common.

The value of natural gas lost as a result of NGL extraction (i.e., shrinkage) and consumed as plant fuel is referred to as plant thermal reduction ("PTR"), which is a significant cost of natural gas processing.  To the extent that we are obligated under keepwhole and margin-band contracts to compensate the producer for shrinkage and plant fuel, we are exposed to fluctuations in the price of natural gas; however, margin-band contracts typically contain terms that limit our exposure to such risks.  Under the terms of our other processing arrangements (i.e., those agreements with fee-based, percent-of-liquids and percent-of-proceeds terms), the producer typically bears the cost of PTR.

If the operating and extraction costs of natural gas processing plants are higher than the incremental value of the NGL products that would be extracted, then recovery levels of certain NGL products, principally ethane, may be purposefully reduced or eliminated.  This scenario is typically referred to as "ethane rejection" and leads to a reduction in NGL volumes available for subsequent transportation, fractionation, storage and marketing.  In general, contracts with keepwhole or percent-of-liquids terms provide us the right (but not the obligation) to process natural gas for a producer; thus, we are protected from processing natural gas at an economic loss during times when the sum of our costs exceeds the value of the equity NGL production we would obtain as consideration for processing services.

Our NGL marketing activities generate revenues from the sale and delivery of NGLs we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and contract purchases. The results of operations from our NGL marketing activities are primarily dependent upon the difference, or spread, between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets.  In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for such factors as delivery location or NGL product quality. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control.  Periodically, we attempt to mitigate these price risks through the use of commodity derivative instruments.

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The following table presents selected information regarding our natural gas processing facilities at February 1, 2013:

				Net Gas	Total Gas
			Our	Processing	Processing
			Ownership	Capacity	Capacity
Description of Asset		Location(s)	Interest	(Bcf/d) (1)	(Bcf/d)
Natural gas processing facilities:
	Meeker	Colorado	100.0%	1.70	1.70
	Pioneer (two facilities)	Wyoming	100.0%	1.35	1.35
	Yoakum	Texas	100.0%	0.70	0.70
	Toca	Louisiana	68.0%   (2)	0.66	1.10
	Chaco	New Mexico	100.0%	0.60	0.60
	North Terrebonne	Louisiana	60.0%   (2)	0.57	0.95
	Neptune	Louisiana	66.0%   (2)	0.43	0.65
	Pascagoula	Mississippi	40.0%   (2)	0.40	1.50
	Thompsonville	Texas	100.0%	0.33	0.33
	Shoup	Texas	100.0%	0.29	0.29
	Sea Robin	Louisiana	40.0%   (2)	0.28	0.65
	Gilmore	Texas	100.0%	0.25	0.25
	Armstrong	Texas	100.0%	0.25	0.25
	San Martin	Texas	100.0%	0.20	0.20
	Delmita	Texas	100.0%	0.15	0.15
	Carlsbad	New Mexico	100.0%	0.13	0.13
	Sonora	Texas	100.0%	0.12	0.12
	Shilling	Texas	100.0%	0.11	0.11
	Venice	Louisiana	13.1%   (3)	0.10	0.75
	Indian Springs	Texas	75.0%   (2)	0.09	0.12
	Burns Point	Louisiana	50.0%   (2)	0.08	0.16
	Indian Basin	New Mexico	42.4%   (2)	0.08	0.18
	Chaparral	New Mexico	100.0%	0.04	0.04
	Total processing capacities			8.91	12.28
(1)   The approximate net gas processing capacity does not necessarily correspond to our ownership interest in each facility.  It is based on a variety of factors such as the level of volumes an owner processes at the facility and its ownership interest in the facility. (2)   We proportionately consolidate our undivided interest in these operating assets. (3)   Our ownership in the Venice plant is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C. ("VESCO").

Our natural gas processing facilities can be characterized as two distinct types: (i) straddle plants situated on mainline natural gas pipelines owned either by us or by third parties or (ii) field plants that process natural gas from gathering pipelines.  We operate all of our natural gas processing facilities except for the Pascagoula, Venice and Indian Basin plants.  On a weighted-average basis, utilization rates for our natural gas processing plants were 55.9%, 56.1% and 51.2% during the years ended December 31, 2012, 2011 and 2010, respectively.

In May 2012, we announced that the first phase (or "train") of our new cryogenic natural gas processing plant at Yoakum, Texas commenced operations.   The second train commenced operations in late August 2012.   In the aggregate, these two processing trains are processing up to a combined 700 MMcf/d of natural gas and extracting over 90 MBPD of NGLs.  The third and final train at the Yoakum facility, which is the same size as each of the first two trains, is currently undergoing commissioning operations and is expected to be fully operational in March 2013.  The Yoakum facility processes natural gas produced primarily from the Eagle Ford Shale formation.  In April 2012, we completed a 65-mile residue natural gas pipeline linking the Yoakum plant to our Wilson natural gas storage facility and numerous third party markets.  In addition, we completed construction of 168 miles of pipelines that are part of our South Texas NGL Pipeline System that will transport mixed NGLs extracted at the Yoakum plant to our NGL fractionation and storage complex at Mont Belvieu, Texas.

Our NGL marketing activities utilize a fleet of approximately 670 railcars, the majority of which are leased from third parties.  These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada.  We have rail loading and unloading capabilities at certain of our terminal facilities in

 

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Arizona, California, Kansas, Louisiana, Minnesota, Mississippi, Nevada, New York, North Carolina and Texas.  These facilities service both our rail shipments and those of our customers.

			Our
			Ownership	Length
Description of Asset		Location(s)	Interest	(Miles)
NGL pipelines:
	Mid-America Pipeline System (1)	Midwest and Western U.S.	100.0%	7,840
	South Texas NGL Pipeline System	Texas	100.0%	1,598
	Seminole Pipeline (1)	Texas	100.0%	1,373
	Dixie Pipeline (1)	South and Southeastern U.S.	100.0%	1,306
	Chaparral NGL System (1)	Texas, New Mexico	100.0%	1,011
	Louisiana Pipeline System	Louisiana	100.0%	955
	Skelly-Belvieu Pipeline (3)	Texas	50.0%  (2)	572
	Promix NGL Gathering System	Louisiana	50.0%  (4)	360
	Houston Ship Channel	Texas	100.0%	300
	Rio Grande Pipeline (3)	Texas	70.0%  (5)	249
	Panola Pipeline	Texas	100.0%	223
	Lou-Tex NGL Pipeline (3)	Texas, Louisiana	100.0%	204
	South Dean Pipeline	Texas	100.0%	186
	Tri-States NGL Pipeline (3)	Alabama, Mississippi, Louisiana	83.3%  (6)	167
	Chunchula Pipeline (3)	Alabama, Mississippi	100.0%	144
	Others (five systems)  (7)	Various	Various  (8)	242
	Total miles			16,730
(1)   Interstate and intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies. (2)   Our ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C. ("Skelly-Belvieu"). (3)   Interstate transportation services provided by these liquids pipelines are regulated by governmental agencies. (4)   Our ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C. ("Promix"). (5)   We own a 70% consolidated interest in the Rio Grande Pipeline through our majority owned subsidiary, Rio Grande Pipeline Company. (6)   We own an 83.3% consolidated interest in the Tri-States NGL Pipeline through our majority owned subsidiary, Tri-States NGL Pipeline, L.L.C. (7)   Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana and Mississippi; our two Port Arthur pipelines located in southeast Texas; and our Meeker pipeline in Colorado. (8)   We own a 74.7% consolidated interest in the 30-mile Wilprise pipeline through our majority owned subsidiary, Wilprise Pipeline Company, LLC.  We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines.  The remainder of these NGL pipelines are wholly owned.

		Net Usable
		Storage
		Capacity
Storage Capacity by State		(MMBbls)
	Texas (1)	123.6
	Louisiana	12.9
	Kansas	8.6
	Mississippi	5.1
	Others (2)	8.9
	Total net usable storage capacity (3)	159.1
(1)   The amount shown for Texas includes 35 underground NGL, petrochemical and refined products storage caverns with an aggregate working capacity of approximately 100 MMBbls located in Mont Belvieu, Texas. (2)   Includes storage capacity at our facilities in Alabama, Arizona, California, Georgia, Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Nevada, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina and Wisconsin. (3)   Our underground storage caverns and above ground storage tanks have an aggregate 159.1 MMBbls of net usable storage capacity.  Our aggregate net usable storage capacity includes 21.3 MMBbls held under long-term operating leases at facilities located in Indiana, Kansas, Louisiana and Texas.  Approximately 1.5 MMBbls of our net usable storage capacity in Louisiana is held indirectly through our equity method investment in Promix.  The remainder of our NGL underground storage caverns and above ground storage tanks are wholly owned.

			Our	Net Plant	Total Plant
			Ownership	Capacity	Capacity
Description of Asset		Location	Interest	(MBPD) (1)	(MBPD)
NGL fractionation facilities:
	Mont Belvieu (six units) (2)	Texas	Various  (3)	433	485
	Shoup and Armstrong	Texas	100.0%	98	98
	Hobbs	Texas	100.0%	75	75
	Norco	Louisiana	100.0%	75	75
	Promix	Louisiana	50.0%  (4)	73	145
	BRF	Louisiana	32.2%  (5)	19	60
	Tebone	Louisiana	56.2%  (6)	17	30
	Todhunter	Ohio	100.0%	3	3
	Total plant fractionation capacities			793	971
(1)   The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility.  It is based on a variety of factors such as the level of volumes an owner processes at the facility and its ownership interest in the facility. (2)   There are six NGL fractionators located at our Mont Belvieu, Texas facility.  Our sixth NGL fractionator commenced commercial operations at this facility in November 2012. (3)   We proportionately consolidate our 75% undivided interest in four of the NGL fractionators located at our Mont Belvieu, Texas facility.  The remaining two units are wholly owned. (4)   Our ownership interest in the Promix fractionator is held indirectly through our equity method investment in Promix. (5)   Our ownership interest in the BRF fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC ("BRF"). (6)   We proportionately consolidate our undivided interest in the Tebone fractionator.

 

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					Approximate Net Capacity
			Our			Usable
			Ownership	Length	Pipelines	Storage
Description of Asset		Location(s)	Interest	(Miles)	(MMcf/d)	(Bcf)
Onshore natural gas pipelines and related storage assets:
	Texas Intrastate System  (1)	Texas	Various    (2)	8,459	6,640	12.9
	Acadian Gas System (1)	Louisiana	100.0%  (3)	1,323	3,100	1.3
	Jonah Gathering System	Wyoming	100.0%	924	2,550	--
	San Juan Gathering System	New Mexico, Colorado	100.0%	6,170	1,750	--
	Piceance Basin Gathering System	Colorado	100.0%	190	1,600	--
	White River Hub (4)	Colorado	50.0%  (5)	10	1,500	--
	Haynesville Gathering Systems	Louisiana, Texas	100.0%	314	1,300	--
	Fairplay Gathering System	Texas	100.0%	250	285	--
	Carlsbad Gathering System	Texas, New Mexico	100.0%	953	220	--
	Indian Springs Gathering System	Texas	80.0%  (6)	199	160	--
	Delmita Gathering System	Texas	100.0%	239	145	--
	South Texas Gathering System	Texas	100.0%	648	143	--
	Big Thicket Gathering System (7)	Texas	100.0%	253	60	--
Total				19,932		14.2
(1)   Intrastate and interstate-sourced volumes transported by these systems are regulated by governmental agencies. (2)   Of the 8,459 miles comprising the Texas Intrastate System, we lease 265 miles from a third party.  We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,262 miles of pipeline.  Our Wilson natural gas storage facility consists of five underground salt dome natural gas storage caverns with 12.9 Bcf of usable storage capacity, four of which (comprising 6.9 Bcf of usable capacity) are held under an operating lease that expires in January 2028.  The remainder of our Texas Intrastate System is wholly owned. (3)   The Acadian Gas System is wholly owned except for an underground salt dome natural gas storage facility that we hold under an operating lease that expires in December 2018. (4)   Interstate volumes at this facility are regulated by governmental agencies. (5)   Our ownership interest in the White River Hub facility is held indirectly through our equity method investment in White River Hub, LLC ("White River Hub"). (6)   We proportionately consolidate our undivided interest in the Indian Springs Gathering System. (7)   Intrastate volumes transported by this pipeline are regulated by governmental agencies.

			Our	Pipeline
			Ownership	Length
Description of Asset		Location(s)	Interest	(Miles)
Crude oil pipelines:
	Seaway Pipeline (1)	Texas, Oklahoma	50.0%  (2)	567
	Red River System (1)	Texas, Oklahoma	100.0%	1,859
	South Texas Crude Oil Pipeline System (3)	Texas	100.0%	1,119
	West Texas System (1)	Texas, New Mexico	100.0%	772
	Basin Pipeline (1)	Texas, New Mexico, Oklahoma	13.0%  (4)	519
	Other (three systems) (5)	Texas, New Mexico	100.0%	230
	Total miles			5,066
(1)   Interstate and intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies. (2)   Our ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Pipeline Company LLC ("Seaway"). (3)   Intrastate transportation services provided by these liquids pipelines are regulated by governmental agencies. (4)   We proportionately consolidate our undivided interest in the Basin Pipeline. (5)   Includes our Azelea and Sharon Ridge crude oil gathering systems located in Texas and Mesquite pipeline in New Mexico.

				Net Usable
			Our	Storage
			Ownership	Capacity
Description of Asset		Location(s)	Interest	(MMBbls)
Crude oil terminals:
	ECHO terminal	Texas	100.0%	0.5
	Cushing terminal	Oklahoma	100.0%	3.1
	Midland terminal	Texas	100.0%	1.5
	Total capacity			5.1

		Our	Pipeline	Approximate
		Ownership	Length	Net Capacity
Description of Asset		Interest	(Miles)	(MMcf/d) (1)
Offshore natural gas pipelines:
	Independence Trail	100.0%	135	1,000
	Viosca Knoll Gathering System	100.0%	137	600
	High Island Offshore System	100.0%	287	500
	Falcon Natural Gas Pipeline	100.0%	14	400
	Green Canyon Laterals	Various  (2)	54	343
	Anaconda Gathering System	100.0%	183	300
	Manta Ray Offshore Gathering System	25.7%  (3)	220	205
	Nautilus System	25.7%  (3)	101	154
	Nemo Gathering System	33.9%  (4)	24	102
	VESCO Gathering System	13.1%  (5)	125	60
Total miles			1,280
(1)   Amounts presented are net to our ownership interest. (2)   We proportionately consolidate our undivided interests, which range from 2.7% to 33.3%, in 47 miles of the Green Canyon Lateral pipelines.  The remainder of the laterals are wholly owned. (3)   Our ownership interests in the Manta Ray Offshore Gathering System and the Nautilus System are held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C. ("Neptune"). (4)   Our ownership interest in the Nemo Gathering System is held indirectly through our cost method investment in Nemo Gathering Company, LLC ("Nemo"). (5)   Our ownership interest in the VESCO Gathering System is held indirectly through our equity method investment in VESCO.  This system is important to our natural gas processing operations; therefore, our equity method investment in VESCO is accounted for under our NGL Pipelines & Services business segment.

		Our		Approximate
		Ownership	Length	Net Capacity
Description of Asset		Interest	(Miles)	(MBPD) (1)
Offshore crude oil pipelines:
	Cameron Highway Oil Pipeline	50.0%  (2)	374	250
	Shenzi Oil Pipeline	100.0%	83	230
	Poseidon Oil Pipeline System	36.0%  (3)	367	155
	Allegheny Oil Pipeline	100.0%	40	140
	Marco Polo Oil Pipeline	100.0%	37	120
	Constitution Oil Pipeline	100.0%	67	80
	Typhoon Oil Pipeline	100.0%	17	80
	Tarantula Oil Pipeline	100.0%	4	30
Total miles			989
(1)   Amounts presented are net to our ownership interest. (2)   Our ownership interest in the Cameron Highway Oil Pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company ("Cameron Highway"). (3)   Our ownership interest in the Poseidon Oil Pipeline System is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, L.L.C. ("Poseidon").

		Our	Water	Approximate Net Capacity (1)
		Ownership	Depth	Natural Gas	Crude Oil
Description of Asset		Interest	(Feet)	(MMcf/d)	(MBPD)
Offshore hub platforms:
	Independence Hub	80.0%  (2)	8,000	800	N/A
	Marco Polo	50.0%  (3)	4,300	150	60
	Viosca Knoll 817	100.0%	671	145	5
	Garden Banks 72	50.0%  (4)	518	113	18
	East Cameron 373	100.0%	441	195	3
	Falcon Nest	100.0%	389	400	3
(1)   Amounts presented are net to our ownership interest. (2)   We own an 80% consolidated interest in the Independence Hub platform through our majority owned subsidiary, Independence Hub, LLC. (3)   Our ownership interest in the Marco Polo platform is held indirectly through our equity method investment in Deepwater Gateway, L.L.C. ("Deepwater Gateway"). (4)   We proportionately consolidate our undivided interest in the Garden Banks 72 platform.

			Our	Net Plant	Total Plant
			Ownership	Capacity	Capacity
Description of Asset		Location(s)	Interest	(MBPD)	(MBPD)
Propylene fractionation facilities:
	Mont Belvieu (six units)	Texas	Various   (1)	73	87
	BRPC (one unit)	Louisiana	30.0%  (2)	7	23
	Total capacity			80	110
(1)   We proportionately consolidate our 66.7% undivided interest in three of the Mont Belvieu propylene fractionators, which have an aggregate 41 MBPD of total plant capacity.  The remaining three propylene fractionators at our Mont Belvieu facility are wholly owned. (2)   Our ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC ("BRPC").

			Ownership	Length
Description of Asset		Location(s)	Interest	(Miles)
Petrochemical pipelines:
	Lou-Tex and Sabine Propylene	Texas, Louisiana	100.0%	287
	Texas City RGP Gathering System	Texas	100.0%	164
	North Dean Pipeline System	Texas	100.0%	149
	Propylene Splitter PGP Distribution System	Texas	100.0%	33
	Lake Charles PGP Pipeline	Louisiana	50.0%  (1)	26
	La Porte PGP Pipeline	Texas	50.0%  (2)	17
	Total miles			676
(1)   We proportionately consolidate our undivided interest in the Lake Charles PGP Pipeline. (2)   Our ownership interest in the La Porte PGP Pipeline is held indirectly through our equity method investments in La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.

					Net Usable
			Our		Storage
			Ownership	Length	Capacity
Description of Asset		Location(s)	Interest	(Miles)	(MMBbls)
Refined products pipelines and terminals:
	TE Products Pipeline (1,2)	Texas to Midwest and Northeast U.S.	100.0%	4,381	18.4
	Centennial Pipeline (2)	Texas to central Illinois	50.0% (3)	795	1.2
	Other terminals (4)	Alabama, Mississippi, Texas	100.0%	n/a	1.2
	Total			5,176	20.8
(1)   In addition to 18.4 MMBbls of refined products usable storage capacity, we have 4.9 MMBbls of NGL usable storage capacity that is used to support operations on our TE Products Pipeline.  Our NGL storage and terminal assets are accounted for under our NGL Pipelines & Services business segment. (2)   Interstate and intrastate transportation services provided by the TE Products Pipeline and interstate transportation services provided by the Centennial Pipeline are regulated by governmental agencies. (3)   Our ownership interest in the Centennial Pipeline is held indirectly through our equity method investment in Centennial. (4)   Includes product distribution and marketing terminals located in Aberdeen, Mississippi and Boligee, Alabama having a usable storage capacity of 0.1 MMBbls and 0.5 MMBbls, respectively, and a storage terminal located in Pasadena, Texas having a usable storage capacity of 0.6 MMBbls.

		For Year Ended December 31,
		2012				2011				2010
Refined products transportation (MBPD)			383				429				511
Petrochemical transportation (MBPD)			101				121				122
NGL transportation (MBPD)			66				92				101

Class of Equipment	Number in Class	Capacity/ Horsepower (as indicated by sign) (1)
Inland marine transportation assets:
Barges	19	< 25,000 bbls
Barges	104	> 25,000 bbls
Tow boats	37	< 2,000 hp
Tow boats	21	≥ 2,000 hp
Offshore marine transportation assets:
Ocean-certified tank barges	8	≥ 20,000 bbls
Tow boats	3	< 2,000 hp
Tow boats	3	> 2,000 hp
(1)    As used in this table, references to "bbls" means barrels and "hp" means horsepower.

  Tax gains or losses on the disposition of our common units could be different than expected.   Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.      

										Cash Distribution History
		Price Ranges								Per			Record	Payment
		High				Low				Unit			Date	Date
2011
1st Quarter		$	44.35			$	27.85			$	0.5975		April 29, 2011	May 6, 2011
2nd Quarter		$	43.95			$	38.67			$	0.6050		July 29, 2011	August 10, 2011
3rd Quarter		$	43.95			$	36.36			$	0.6125		October 31, 2011	November 9, 2011
4th Quarter		$	46.70			$	38.01			$	0.6200		January 31, 2012	February 9, 2012
2012
1st Quarter		$	52.95			$	45.78			$	0.6275		April 30, 2012	May 9, 2012
2nd Quarter		$	52.94			$	45.67			$	0.6350		July 31, 2012	August 8, 2012
3rd Quarter		$	54.98			$	50.78			$	0.6500		October 31, 2012	November 8, 2012
4th Quarter		$	55.38			$	48.52			$	0.6600		January 31, 2013	February 7, 2013

														Maximum
										Total Number of				Number of Units
						Average				Units Purchased				That May Yet
		Total Number of				Price Paid				as Part of Publicly				Be Purchased
Period		Units Purchased				per Unit				Announced Plans				Under the Plans
February 2012 (1)			187,343			$	51.54				--				--
May 2012 (2)			186,048			$	49.82				--				--
August 2012 (3)			7,942			$	53.12				--				--
September 2012 (4)			1,087			$	54.24				--				--
November 2012 (5)			24,236			$	52.47				--				--
December 2012 (6)			1,585			$	50.05				--				--
(1)   Of the 632,298 restricted common units that vested in February 2012 and converted to common units, 187,343 units were sold back to us by employees to cover related withholding tax requirements. (2)   Of the 604,054 restricted common units that vested in May 2012 and converted to common units, 186,048 units were sold back to us by employees to cover related withholding tax requirements. (3)   Of the 28,131 restricted common units that vested in August 2012 and converted to common units, 7,942 units were sold back to us by employees to cover related withholding tax requirements. (4)   Of the 4,100 equity-based awards that vested in September 2012 and converted to common units, 1,087 units were sold back to us by employees to cover related withholding tax requirements. (5)   Of the 82,621 equity-based awards that vested in November 2012 and converted to common units, 24,236 units were sold back to us by employees to cover related withholding tax requirements. (6)   Of the 5,000 equity-based awards that vested in December 2012 and converted to common units, 1,585 units were sold back to us by employees to cover related withholding tax requirements.

		For Year Ended December 31,
		2012				2011				2010				2009				2008
Results of operations data: (1)
Revenues		$	42,583.1			$	44,313.0			$	33,739.3			$	25,510.9			$	35,469.6
Income from continuing operations		$	2,428.0			$	2,088.3			$	1,383.7			$	1,140.3			$	1,145.1
Net income		$	2,428.0			$	2,088.3			$	1,383.7			$	1,140.3			$	1,145.1
Net income attributable to limited partners		$	2,419.9			$	2,046.9			$	320.8			$	204.1			$	164.0
Earnings per unit: (2)
Basic		$	2.81			$	2.48			$	1.17			$	0.99			$	0.89
Diluted		$	2.71			$	2.38			$	1.15			$	0.99			$	0.89
Other financial data:
Cash distributions per unit (3)		$	2.57			$	2.44			$	2.27			$	2.03			$	1.79
		As of December 31,
		2012				2011				2010				2009				2008
Financial position data: (1)
Consolidated assets		$	35,934.4			$	34,125.1			$	31,360.8			$	27,686.3			$	25,780.4
Consolidated debt (4)		$	16,201.8			$	14,529.4			$	13,563.5			$	12,427.9			$	12,714.9
Equity (5)		$	13,296.0			$	12,219.3			$	11,900.8			$	10,473.1			$	9,759.4
Total limited partner units outstanding (6)			898.8				881.6				843.7				208.8				184.8
(1)   In general, our consolidated results of operations and financial position have been impacted by our capital spending program. For information regarding our capital spending program, see "Liquidity and Capital Resources – Capital Spending" under Part II, Item 7 of this annual report. (2)   Earnings per unit amounts for periods prior to the Holdings Merger in November 2010 have been retroactively presented to reflect the 1.5 to one unit-for-unit exchange that occurred under the Holdings Merger. For information regarding our earnings per unit amounts, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (3)   Cash distributions per unit presented for 2009 and 2008 reflect those declared and paid by Holdings. Cash distributions per unit presented for 2010 represent the sum of cash distributions declared and paid by Holdings with respect to the first, second and third quarters of 2010 and the cash distribution declared and paid by Enterprise with respect to the fourth quarter of 2010. Cash distributions per unit for 2012 and 2011 represent those declared and paid by Enterprise with respect to those years. For information regarding our cash distributions, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (4)   Consolidated debt has increased over time as a result of our capital spending program. For information regarding our consolidated debt obligations, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (5)   Consolidated equity has increased over time primarily due to the issuance of limited partner units by Enterprise in connection with acquisitions and its capital spending program. For information regarding our consolidated equity, see Note 13 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. (6)   Total units outstanding increased in 2010 in part due to the Holdings Merger in November 2010 and reflects, following the Holdings Merger, the number of Enterprise limited partner common units outstanding. Total units outstanding increased in 2011 in part due to the Duncan Merger in September 2011 and reflects, following the Duncan Merger, the number of Enterprise common units outstanding. Total units outstanding at December 31, 2012, 2011 and 2010 includes the Designated Units issued in connection with the Holdings Merger, which are owned by a privately held affiliate of EPCO that agreed to temporarily waive regular quarterly cash distributions over a five-year period on such units. For information regarding the Designated Units, see Note 1 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Total units outstanding at December 31, 2012, 2011 and 2010 exclude 4.5 million Class B units of Enterprise.

/d		= per day	MMBbls		= million barrels
BBtus		= billion British thermal units	MMBPD		= million barrels per day
Bcf		= billion cubic feet	MMBtus		= million British thermal units
BPD		= barrels per day	MMcf		= million cubic feet
MBPD		= thousand barrels per day	TBtus		= trillion British thermal units

		For Year Ended December 31,
		2012				2011				2010
Revenues		$	42,583.1			$	44,313.0			$	33,739.3
Costs and expenses:
Operating costs and expenses:
Cost of sales			36,015.5				38,292.6				28,723.1
Other operating costs and expenses			2,244.9				2,195.4				1,825.9
Depreciation, amortization and accretion			1,061.7				958.7				936.3
Gains attributable to disposal of assets			(17.6	)			(156.0	)			(44.4	)
Non-cash asset impairment charges			63.4				27.8				8.4
Total operating costs and expenses			39,367.9				41,318.5				31,449.3
General and administrative costs			170.3				181.8				204.8
Total costs and expenses			39,538.2				41,500.3				31,654.1
Equity in income of unconsolidated affiliates			64.3				46.4				62.0
Operating income			3,109.2				2,859.1				2,147.2
Interest expense			(771.8	)			(744.1	)			(741.9	)
Other, net			73.4				0.5				4.5
Benefit from (provision for) income taxes			17.2				(27.2	)			(26.1	)
Net income			2,428.0				2,088.3				1,383.7
Net income attributable to noncontrolling interests			(8.1	)			(41.4	)			(1,062.9	)
Net income attributable to limited partners		$	2,419.9			$	2,046.9			$	320.8

		For Year Ended December 31,
		2012				2011				2010
NGL Pipelines & Services:
Sales of NGLs and related products		$	14,218.5			$	16,724.6			$	13,449.4
Midstream services			949.9				758.7				753.1
Total			15,168.4				17,483.3				14,202.5
Onshore Natural Gas Pipelines & Services:
Sales of natural gas			2,395.4				2,866.5				2,928.7
Midstream services			957.2				863.7				772.9
Total			3,352.6				3,730.2				3,701.6
Onshore Crude Oil Pipelines & Services:
Sales of crude oil			17,548.7				15,962.6				10,710.4
Midstream services			113.0				98.5				84.4
Total			17,661.7				16,061.1				10,794.8
Offshore Pipelines & Services:
Sales of natural gas			0.4				1.1				1.3
Sales of crude oil			3.3				9.4				9.5
Midstream services			187.8				245.5				299.9
Total			191.5				256.0				310.7
Petrochemical & Refined Products Services:
Sales of petrochemicals and refined products			5,470.9				6,000.6				4,009.1
Midstream services			738.0				781.8				720.6
Total			6,208.9				6,782.4				4,729.7
Total consolidated revenues		$	42,583.1			$	44,313.0			$	33,739.3

																										Polymer				Refinery
		Natural												Normal								Natural				Grade				Grade
		Gas,				Ethane,				Propane,				Butane,				Isobutane,				Gasoline,				Propylene,				Propylene,				Crude Oil,
		$/MMBtu				$/gallon				$/gallon				$/gallon				$/gallon				$/gallon				$/pound				$/pound				$/barrel
		(1)				(2)				(2)				(2)				(2)				(2)				(3)				(3)				(4)
2010 Averages		$	4.39			$	0.60			$	1.16			$	1.50			$	1.58			$	1.84			$	0.61			$	0.48			$	79.53
2011 by quarter:
1st Quarter		$	4.11			$	0.66			$	1.37			$	1.75			$	1.85			$	2.27			$	0.76			$	0.68			$	94.10
2nd Quarter		$	4.32			$	0.78			$	1.49			$	1.87			$	2.02			$	2.48			$	0.89			$	0.79			$	102.56
3rd Quarter		$	4.20			$	0.78			$	1.54			$	1.88			$	2.09			$	2.37			$	0.78			$	0.67			$	89.76
4th Quarter		$	3.54			$	0.86			$	1.44			$	1.89			$	2.26			$	2.24			$	0.59			$	0.44			$	94.06
2011 Averages		$	4.04			$	0.77			$	1.46			$	1.85			$	2.06			$	2.34			$	0.76			$	0.64			$	95.12
2012 by quarter:
1st Quarter		$	2.72			$	0.56			$	1.26			$	1.93			$	2.04			$	2.39			$	0.69			$	0.60			$	102.93
2nd Quarter		$	2.21			$	0.40			$	0.98			$	1.62			$	1.75			$	2.05			$	0.66			$	0.51			$	93.49
3rd Quarter		$	2.80			$	0.34			$	0.89			$	1.44			$	1.62			$	2.01			$	0.51			$	0.37			$	92.22
4th Quarter		$	3.41			$	0.28			$	0.88			$	1.64			$	1.82			$	2.15			$	0.56			$	0.48			$	88.18
2012 Averages		$	2.79			$	0.40			$	1.00			$	1.65			$	1.81			$	2.15			$	0.60			$	0.49			$	94.20
(1)   Natural gas prices are based on Henry-Hub I-FERC commercial index prices. (2)   NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service. (3)   Polymer-grade propylene prices represent average contract pricing for such product as reported by Chemical Market Associates, Inc. ("CMAI"). Refinery grade propylene prices represent weighted-average spot prices for such product as reported by CMAI. (4)   Crude oil prices are based on commercial index prices for West Texas Intermediate as measured on the New York Mercantile Exchange ("NYMEX").

		For Year Ended December 31,
		2012				2011				2010
Segment gross operating margin:
Natural gas processing and related NGL  marketing activities		$	1,443.0			$	1,324.4			$	989.9
NGL pipelines and related storage			740.7				638.4				604.8
NGL fractionation			284.8				221.4				137.9
Total		$	2,468.5			$	2,184.2			$	1,732.6
Selected volumetric data:
NGL transportation volumes (MBPD)			2,472				2,284				2,322
NGL fractionation volumes (MBPD)			659				575				485
Equity NGL production (MBPD) (1)			101				116				121
Fee-based natural gas processing (MMcf/d) (2)			4,382				3,820				2,932
(1)   Represents the NGL volumes we earn and take title to in connection with our processing activities. In general, equity NGL production decreased in 2012 compared to 2011 and 2010 due to reduced ethane recoveries associated with the weakness in natural gas processing margins resulting from lower NGL prices. (2)   Volumes reported correspond to the revenue streams earned by our gas plants. The increase in fee-based processing volumes in 2012 is primarily due to (i) the start-up of our Yoakum gas plant in May 2012 and (ii) changes in processing agreements whereby producers are electing to process more of their natural gas on a fee basis in order to retain NGLs extracted from their natural gas streams, which, in turn, also lowers our equity NGL production.