Edgar Filing: SUNOCO LOGISTICS PARTNERS L.P.

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Non-accelerated filer

Smaller reporting company

Sunoco Logistics Partners LP--Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

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

For the transition period from to

Commission file number 1-31219

SUNOCO LOGISTICS PARTNERS L.P.

(Exact name of registrant as specified in its charter)


Delaware		23-3096839
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1818 Market Street, Suite 1500, Philadelphia, PA		19103
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (866) 248-4344

Former name, former address and formal fiscal year, if changed since last report: Not Applicable

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 ¨

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

At September 30, 2012, the number of the registrant’s Common Units outstanding were 103,562,297.

SUNOCO LOGISTICS PARTNERS L.P.

INDEX


		Page Number
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2012 and 2011 (unaudited)		2

	Condensed Consolidated Balance Sheets at September 30, 2012 (unaudited) and December 31, 2011		3

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011 (unaudited)		4

	Condensed Consolidated Statements of Equity for the Nine Months Ended September 30, 2012 and 2011 (unaudited)		5

	Notes to Condensed Consolidated Financial Statements (unaudited)		6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		38

Item 4.	Controls and Procedures		40

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		41

Item 1A.	Risk Factors		41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		51

Item 3.	Defaults Upon Senior Securities		51

Item 4.	Mine Safety Disclosures		51

Item 5.	Other Information		51

Item 6.	Exhibits		52

SIGNATURE			53

PART I

FINANCIAL INFORMATION

Item 1.

Financial Statements

SUNOCO LOGISTICS PARTNERS L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)

(in millions, except per unit amounts)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	3,066		$	2,808		$	9,460		$	7,148
Affiliates (Note 3)		141			39			461			381
Other income		11			3			18			9
Gain on divestment and related matters (Note 2)		—			—			11			—

Total Revenues		3,218			2,850			9,950			7,538

Costs and Expenses
Cost of products sold and operating expenses		2,997			2,675			9,311			7,086
Depreciation and amortization expense		26			24			76			61
Impairment charge and related matters		—			—			(1	)		—
Selling, general and administrative expenses		30			23			86			67

Total Costs and Expenses		3,053			2,722			9,472			7,214

Operating Income		165			128			478			324
Interest cost and debt expense, net		24			26			73			68
Capitalized interest		(4	)		(2	)		(8	)		(5	)

Income Before Provision for Income Taxes		145			104			413			261
Provision for income taxes (Note 6)		8			7			24			18

Net Income		137			97			389			243
Less: Net income attributable to noncontrolling interests		3			2			8			6

Net Income Attributable to Partners		134			95			381			237
Less: General Partner’s interest		(21	)		(14	)		(55	)		(40	)

Limited Partners’ interest⁽¹⁾	$	113		$	81		$	326		$	197

Net Income Attributable to Partners per Limited Partner unit (Note 4):
Basic	$	1.09		$	0.78		$	3.15		$	1.96
Diluted	$	1.09		$	0.78		$	3.14		$	1.95

Weighted average Limited Partners' units outstanding:
Basic		103.6			103.3			103.5			100.7
Diluted		103.9			103.7			103.9			101.1

Comprehensive Income	$	120		$	108		$	368		$	255
Less: Comprehensive income attributable to noncontrolling interests		3			2			8			6

Comprehensive Income Attributable to Partners	$	117		$	106		$	360		$	249

⁽¹⁾	Includes interest in net income attributable to Class A units, which were converted to common units in July 2012.

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	September 30,			December 31,
	2012			2011
	(UNAUDITED)
Assets

Cash and cash equivalents	$	2		$	5
Advances to affiliated companies (Note 3)		38			107
Accounts receivable, affiliated companies (Note 3)		1			—
Accounts receivable, net		1,998			2,188
Inventories (Note 5)		250			206

Total Current Assets		2,289			2,506

Properties, plants and equipment		3,446			3,234
Less accumulated depreciation and amortization		(768	)		(712	)

Properties, plants and equipment, net		2,678			2,522

Investment in affiliates (Note 7)		82			73
Goodwill		77			77
Intangible assets, net		258			277
Other assets		36			22

Total Assets	$	5,420		$	5,477

Liabilities and Equity
Accounts payable	$	1,980		$	2,111
Current portion of long-term debt (Note 8)		—			250
Accrued liabilities		96			112
Accrued taxes payable (Note 6)		56			62

Total Current Liabilities		2,132			2,535

Long-term debt (Note 8)		1,627			1,448
Other deferred credits and liabilities		61			78
Deferred income taxes (Note 6)		221			222
Commitments and contingent liabilities (Note 9)

Total Liabilities		4,041			4,283

Total Equity		1,379			1,194

Total Liabilities and Equity	$	5,420		$	5,477

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in millions)


	Nine Months Ended
	September 30,
	2012			2011
Cash Flows from Operating Activities:
Net Income	$	389		$	243
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		76			61
Claim for recovery of environmental liability		(14	)		—
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies		(1	)		154
Accounts receivable, net		190			(555	)
Inventories		(44	)		(249	)
Accounts payable and accrued liabilities		(174	)		551
Accrued taxes payable		(6	)		10
Other		(5	)		—

Net cash provided by operating activities		411			215

Cash Flows from Investing Activities:
Capital expenditures		(235	)		(122	)
Acquisitions		—			(396	)
Proceeds from divestments and related matters		11			—

Net cash used in investing activities		(224	)		(518	)

Cash Flows from Financing Activities:
Distributions paid to limited and general partners		(178	)		(156	)
Distributions paid to noncontrolling interests		(5	)		(3	)
Contributions from general partner		—			2
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		(5	)		(3	)
Repayments under credit facilities		(322	)		(561	)
Borrowings under credit facilities		501			529
Net proceeds from issuance of long-term debt		—			595
Repayments of senior notes		(250	)		—
Advances to affiliated companies, net		69			(94	)

Net cash (used in) provided by financing activities		(190	)		309

Net change in cash and cash equivalents		(3	)		6
Cash and cash equivalents at beginning of year		5			2

Cash and cash equivalents at end of period	$	2		$	8

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

(in millions)


	Limited Partners					General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Common			Class A
Balance at January 1, 2011	$	940		$	—	$	28		$	(3	)	$	77		$	1,042

Comprehensive Income:
Net Income		196			1		40			—			6			243
Change in cash flow hedges		—			—		—			12			—			12

Total comprehensive income		196			1		40			12			6			255
Issuance of Class A Units to Sunoco, Inc.		—			20		2			—			—			22
Expense on units issued under incentive plans		5			—		—			—			—			5
Distribution equivalent rights		(1	)		—		—			—			—			(1	)
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		(3	)		—		—			—			—			(3	)
Noncontrolling equity in joint venture acquisitions		—			—		—			—			20			20
Distributions		(119	)		—		(37	)		—			(3	)		(159	)
Other		—			—		—			—			1			1

Balance at September 30, 2011	$	1,018		$	21	$	33		$	9		$	101		$	1,182


	Limited Partners						General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Common			Class A
Balance at January 1, 2012	$	1,039		$	22		$	34		$	1		$	98		$	1,194

Comprehensive Income:
Net Income		324			2			55			—			8			389
Change in cash flow hedges		—			—			—			(21	)		—			(21	)

Total comprehensive income		324			2			55			(21	)		8			368
Expense on units issued under incentive plans		6			—			—			—			—			6
Distribution equivalent rights		(1	)		—			—			—			—			(1	)
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		(5	)		—			—			—			—			(5	)
Conversion of Class A Units to Common Units		24			(24	)		—			—			—			—
Distributions		(133	)		—			(45	)		—			(5	)		(183	)

Balance at September 30, 2012	$	1,254		$	—		$	44		$	(20	)	$	101		$	1,379

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Basis of Presentation

Sunoco Logistics Partners L.P. (“the Partnership”) is a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products and crude oil pipelines, terminalling and storage assets, and refined products and crude oil acquisition and marketing assets. The Partnership is principally engaged in the transport, terminalling and storage of refined products and crude oil and the purchase and sale of crude oil in approximately 30 states located throughout the United States. Sunoco, Inc. and its wholly-owned subsidiaries, including Sunoco, Inc. (R&M), are collectively referred to as “Sunoco.”

On October 5, 2012, Sunoco was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco through its wholly-owned subsidiary Sunoco Partners LLC served as the Partnership’s general partner and owned a two percent general partner interest, all of the incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. As a result, the Partnership’s assets and liabilities are required to be adjusted to fair value on the closing date by application of “push-down” accounting. The new basis of accounting will be reflected in the Partnership’s financial statements beginning in the fourth quarter 2012.

The condensed consolidated financial statements reflect the results of Sunoco Logistics Partners L.P. and its wholly-owned subsidiaries, including Sunoco Logistics Partners Operations L.P., and include the accounts of entities in which the Partnership has a controlling financial interest. A controlling financial interest is evidenced by either a voting interest greater than 50 percent or a risk and rewards model that identifies the Partnership or one of its subsidiaries as the primary beneficiary of a variable interest entity. The Partnership holds a controlling financial interest in Inland Corporation (“Inland”), Mid-Valley Pipeline Company (“Mid-Valley”) and West Texas Gulf Pipe Line Company (“West Texas Gulf”), and as such, these joint ventures are reflected as consolidated subsidiaries of the Partnership from the respective dates of acquisition. All significant intercompany accounts and transactions are eliminated in consolidation and noncontrolling interests in equity and net income are shown separately in the condensed consolidated balance sheets and statements of comprehensive income. Equity ownership interests in corporate joint ventures in which the Partnership does not have a controlling financial interest are accounted for under the equity method of accounting.

In June 2011, the Financial Accounting Standards Board (“FASB”) codified guidance related to the presentation of comprehensive income. The guidance requires entities to present net income and other comprehensive income in a single continuous statement of comprehensive income or in two separate, but consecutive, statements. For the three and nine months ended September 30, 2012 and 2011, the Partnership presents the components of net income and total comprehensive income in its condensed consolidated statements of comprehensive income. The new guidance does not change the components that are recognized in net income and the components that are recognized in other comprehensive income. The revised presentation has been retroactively applied to all periods presented.

The accompanying condensed consolidated financial statements are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States for interim financial reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the results of operations, financial position and cash flows for the periods shown have been made. All such adjustments are of a normal recurring nature. Results for the three and nine months ended September 30, 2012 are not necessarily indicative of results for the full year 2012.

2. Change in Business and Other Matters

In February 2012, the Partnership sold its refined products terminal and pipeline assets in Big Sandy, Texas for $11 million. The buyer also assumed a $1 million environmental liability associated with the assets. The net book value of the assets sold and liability transferred approximated the sale price. In connection with the sale, the Partnership also agreed to cancel existing throughput and deficiency agreements in exchange for cash payments of $11 million. During the first quarter 2012, the Partnership recognized a total gain of $11 million, which primarily related to the contract settlement. The gain was recorded as $5 and $6 million within the Refined Products Pipelines and Terminal Facilities segments, respectively.

Management has continued to assess the impact that Sunoco’s decision to exit its refining business in the northeast will have on the Partnership’s assets that have historically served the refineries and determined that the Partnership’s refined products pipeline and terminal assets continue to have expected future cash flows that support their carrying values. However, the Partnership recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would be negatively impacted if the Philadelphia refinery was permanently idled. This included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if the assets were permanently idled.

In September 2012, Sunoco completed the formation of Philadelphia Energy Solutions (“PES”), a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. The Carlyle Group will hold the controlling interest and oversee day-to-day operations of the joint venture and the refinery. Sunoco retained a non-operating minority interest of approximately 33 percent. During the second quarter 2012, the Partnership reversed $10 million of regulatory obligations which were no longer expected to be incurred.

3. Related Party Transactions

Acquisition of Sunoco

The general and limited partner interests that were previously owned by Sunoco were contributed to ETP in connection with the acquisition of Sunoco by ETP. As a result of these transactions, both the Partnership and Sunoco became consolidated subsidiaries of ETP. The Partnership has various operating and administrative agreements with Sunoco, including the agreements described below. Sunoco continues to operate its retail marketing network and is expected to continue utilizing the Partnership’s pipeline and tank assets. Sunoco continues to perform the administrative functions defined in such agreements on the Partnership’s behalf. The Partnership continues to work with ETP in determining how the acquisition will impact these agreements going forward.

Advances to/from Affiliate

The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco’s centralized cash management program. Under this program, all of the Partnership’s cash receipts and cash disbursements are processed, together with those of Sunoco and its other subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an intercompany account. The intercompany balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate of the Partnership’s third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate provided in the Operating Partnership’s $350 million Credit Facility (see Note 8).

Administrative Services

The Partnership has no employees, and reimburses Sunoco for certain costs and other direct expenses incurred on the Partnership’s behalf. These costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by the Partnership.

Under the Omnibus Agreement, the Partnership pays Sunoco an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform certain centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $13 million for the year ended December 31, 2011. The fee increased to $18 million for 2012 to cover additional consolidation of services provided by Sunoco that were previously provided by third parties and includes an allocation of certain senior management costs from Sunoco. This fee does not include the cost of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner or the cost of their employee benefits.

The Partnership’s share of allocated Sunoco employee benefit plan expenses, including noncontributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits are reflected in cost of products sold and operating expenses and selling, general and administrative expenses in the condensed consolidated statements of comprehensive income.

Affiliated Revenues and Accounts Receivable, Affiliated Companies

The Partnership is party to various agreements with Sunoco to supply refined products and to provide pipeline and terminalling services to Sunoco and PES. Affiliated revenues in the condensed consolidated statements of comprehensive income consist of sales of refined products and crude oil, as well as the related provision, and services including pipeline transportation, terminalling, and storage and blending for Sunoco. Affiliated revenues include sales of crude oil to Sunoco which were priced using market-based rates and sales of refined products which are priced using market-based rates under agreements that are negotiated annually. Service revenues are recognized based on published tariffs or negotiated rates.

Capital Contributions

In the first nine months of 2012 and 2011, the Partnership issued 0.3 and 0.2 million limited partnership units, respectively, to participants in the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) upon completion of award vesting requirements. As a result of these issuances of limited partnership units, the general partner contributed less than $1 million during the first nine months of 2012 and 2011 to maintain its 2 percent general partner interest. The Partnership recorded these amounts as capital contributions to Equity within its condensed consolidated balance sheets.

4. Net Income Attributable to Sunoco Logistics Partners L.P. Per Limited Partner Unit Data

The general partner’s interest in net income attributable to Sunoco Logistics Partners L.P. (“net income attributable to Partners”) consists of its 2 percent general partner interest and “incentive distributions,” which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.1667 per common unit (see Note 11). The general partner was allocated net income attributable to Partners of $21 and $14 million (representing 16 and 15 percent respectively of total net income attributable to Partners) for the three months ended September 30, 2012 and 2011, respectively, and $55 and $40 million (representing 14 and 17 percent respectively of total net income attributable to Partners) for the nine months ended September 30, 2012 and 2011, respectively. Diluted net income attributable to Partners per common unit is calculated by dividing net income attributable to Partners by the sum of the weighted average number of common and Class A units outstanding, prior to conversion to common units, and the dilutive effect of incentive unit awards (see Note 12).

In July 2011, the Partnership issued 3.9 million Class A units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets. These deferred distribution units represented a new class of units that were converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net income on a pro-rata basis with the common units.

The following table sets forth the reconciliation of the weighted average number of common and Class A units used to compute basic net income attributable to Partners per common unit to those used to compute diluted net income attributable to Partners per common unit for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
	(in millions)
Weighted average number of common units outstanding - basic		103.6		103.3		103.5		100.7
Add effect of dilutive incentive awards		0.3		0.4		0.4		0.4

Weighted average number of common units - diluted		103.9		103.7		103.9		101.1

5. Inventories

The components of inventories are as follows:


	September 30, 2012		December 31, 2011
	(in millions)
Crude oil	$	177	$	142
Refined products		60		55
Refined products additives		3		2
Materials, supplies and other		10		7

	$	250	$	206

6. Income Taxes

The Partnership is not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose income taxes. Rather, income taxes are generally assessed at the partner level. There are some states in which the Partnership operates where it is subject to state and local income taxes. Substantially all of the income tax reflected in the Partnership’s condensed consolidated financial statements is derived from the operations of Inland, Mid-Valley and West Texas Gulf, all of which are entities subject to income taxes for federal and state purposes at the corporate level. The effective tax rates for these entities approximate the federal statutory rate of 35 percent.

In taxable jurisdictions, the Partnership records deferred income taxes on all significant temporary differences between the book basis and the tax basis of assets and liabilities. The net deferred tax liabilities reflected on the condensed consolidated balance sheets are derived principally from the difference in the book and tax bases of properties, plants and equipment associated with the Inland, Mid-Valley and West Texas Gulf acquisitions.

7. Investment in Affiliates

The Partnership’s corporate joint ventures own refined products pipeline systems. The Partnership’s ownership percentages in corporate joint ventures as of September 30, 2012 and December 31, 2011 were as follows:


	Ownership Percentage
Explorer Pipeline Company		9.4	%
Yellowstone Pipe Line Company		14.0	%
West Shore Pipe Line Company		17.1	%
Wolverine Pipe Line Company		31.5	%

The following table provides summarized, unaudited income statement information on a 100 percent basis for the Partnership’s corporate joint ventures for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions)
Income Statement Data:
Total revenues	$	194	$	110	$	359	$	286
Income before income taxes	$	121	$	45	$	175	$	115
Net income	$	75	$	29	$	108	$	70

The following table provides summarized, unaudited balance sheet information on a 100 percent basis for the Partnership’s corporate joint ventures as of September 30, 2012 and December 31, 2011:


	September 30, 2012		December 31, 2011
	(in millions)
Balance Sheet Data:
Current assets	$	219	$	130
Non-current assets	$	635	$	648
Current liabilities	$	141	$	127
Non-current liabilities	$	528	$	549
Net equity	$	185	$	102

8. Debt

The components of the Partnership’s debt balances are as follows:


	September 30,			December 31,
	2012			2011
	(in millions)
Credit Facilities
$350 million Credit Facility, due August 2016	$	96		$	—
$200 million Credit Facility, due August 2013		74			—
$35 million Credit Facility, due April 2015 ⁽¹⁾		9			—

Senior Notes
Senior Notes - 7.25%, due February 2012 ⁽²⁾		—			250
Senior Notes - 8.75%, due February 2014		175			175
Senior Notes - 6.125%, due May 2016		175			175
Senior Notes - 5.50%, due February 2020		250			250
Senior Notes - 4.65%, due February 2022		300			300
Senior Notes - 6.85%, due February 2040		250			250
Senior Notes - 6.10%, due February 2042		300			300

Total debt		1,629			1,700
Less:
Unamortized bond discount		(2	)		(2	)
Current portion of long-term debt⁽³⁾		—			(250	)

Long-term debt, net of current portion	$	1,627		$	1,448

⁽¹⁾	The $35 million Credit Facility is held by West Texas Gulf.

⁽²⁾	The 7.25 percent Senior Notes matured and were repaid in February 2012.

⁽³⁾	Amounts outstanding under the Partnership’s credit facilities at September 30, 2012 have been classified as long-term debt as the Partnership has the intent and ability to refinance such borrowings on a long-term basis.

Credit Facilities

The Partnership maintains two credit facilities totaling $550 million to fund the Partnership’s working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under these credit facilities were $170 million at September 30, 2012. At December 31, 2011 there were no outstanding borrowings under these credit facilities.

The $350 and $200 million Credit Facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit the Partnership, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. The Partnership’s ratio of total debt to EBITDA was 2.3 to 1 at September 30, 2012, as calculated in accordance with the credit agreements.

In connection with the acquisition of Sunoco by ETP in October 2012, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. This would have represented an event of default under the Partnership’s credit facilities as the general partner interests would no longer be owned by Sunoco. During the third quarter 2012, the Partnership amended this provision of its credit facilities to avoid an event of default upon the transfer of the general partner interest to ETP.

In May 2012, West Texas Gulf entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. The credit facility also limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending September 30, 2012 shall not be less than 0.80 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 0.98 to 1 and 0.28 to 1, respectively, at September 30, 2012. Outstanding borrowings under this credit facility were $9 million at September 30, 2012.

9. Commitments and Contingent Liabilities

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations can result in liabilities and loss contingencies for remediation at the Partnership’s facilities and at third-party or formerly owned sites. At September 30, 2012 and December 31, 2011, there were accrued liabilities for environmental remediation in the condensed consolidated balance sheets of $4 million. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, since no unasserted claims are probable of settlement or reasonably estimable, nor have any expected recoveries from insurance been recognized in earnings. Charges against income for environmental remediation totaled $1 million for the three months ended September 30, 2012 and 2011, respectively, and $6 and $4 million for the nine months ended September 30, 2012 and 2011, respectively. The Partnership maintains insurance programs that cover certain of its existing or potential environmental liabilities. Claims for recovery of environmental liabilities and previous expenditures that are probable of realization totaled $14 million at September 30, 2012 and are included in other assets in the condensed consolidated balance sheets.

Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and needed to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership’s liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other parties.

Sunoco has indemnified the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed to the Partnership that arose from the operation of such assets prior to the closing of the February 2002 initial public offering (“IPO”). Sunoco has indemnified the Partnership for 100 percent of all losses asserted within the first 21 years of closing of the IPO. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent per year. For example, for a claim asserted during the twenty-third year after closing of the IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. The Partnership has agreed to indemnify Sunoco for events and conditions associated with the operation of the Partnership’s assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.

Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the results of operations, financial position or cash flows of the Partnership at September 30, 2012. There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the Partnership’s results of operations, financial position or cash flows at September 30, 2012.

10. Equity

The changes in the number of common units outstanding from January 1, 2011 through September 30, 2012 are as follows:


	Common Units		Class A Units			Total Units
	(in millions)
Balance at January 1, 2011		99.2		—			99.2
Units issued under incentive plans		0.2		—			0.2
Class A Units issued to Sunoco		—		3.9			3.9

Balance at December 31, 2011		99.4		3.9			103.3
Conversion of Class A Units		3.9		(3.9	)		—
Units issued under incentive plans		0.3		—			0.3

Balance at September 30, 2012		103.6		—			103.6

11. Cash Distributions

Within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner at its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after the establishment of cash reserves and the payment of fees and expenses, including payments to the general partner.

If cash distributions exceed $0.1667 per unit in a quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

The following table shows the target distribution levels and distribution “splits” between the general partner and the holders of the Partnership’s common units:


	Total Quarterly Distribution Target Amount	Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	General Partner			Unitholders
Minimum Quarterly Distribution	$0.1500		2	%		98	%
First Target Distribution	up to $0.1667		2	%		98	%
Second Target Distribution	above $0.1667
	up to $0.1917		15	%*		85	%
Third Target Distribution	above $0.1917
	up to $0.5275		37	%*		63	%
Thereafter	above $0.5275		50	%*		50	%

*	Includes 2 percent general partner interest.

The distributions paid by the Partnership for the period from January 1, 2011 through September 30, 2012 are summarized below:


Date Cash Distribution Paid	Cash Distribution per Limited Partner Unit		Total Cash Distribution to the Limited Partners		Total Cash Distribution to the General Partner
			(in millions)		(in millions)
August 14, 2012	$	0.4700	$	49	$	17
May 15, 2012	$	0.4275	$	43	$	14
February 14, 2012	$	0.4200	$	41	$	14
November 14, 2011	$	0.4133	$	41	$	13
August 12, 2011	$	0.4050	$	40	$	13
May 13, 2011	$	0.3983	$	40	$	12
February 14, 2011	$	0.3933	$	39	$	12

On November 7, 2012, Sunoco Partners LLC, the general partner of Sunoco Logistics Partners L.P., declared a cash distribution of $0.5175 per common unit ($2.07 annualized), representing the distribution for the third quarter 2012. The $74 million distribution, including $20 million to the general partner, will be paid on November 14, 2012 to common unitholders of record on November 8, 2012.

12. Management Incentive Plan

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan (“LTIP”) for directors, officers and employees of the general partner who perform services for the Partnership. The LTIP is administered by the independent directors of the Compensation Committee of the general partner’s board of directors with respect to employee and officer awards, and by the general partner’s board of directors with respect to awards granted to the independent members. The LTIP currently permits the grant of restricted units and unit options covering an additional 0.7 million common units. Restricted unit awards may also include tandem distribution equivalent rights (“DERs”) at the discretion of the Compensation Committee.

During the nine-month periods ended September 30, 2012 and 2011, the Partnership issued 0.3 and 0.2 million common units, respectively, under the LTIP. The Partnership recognized share-based compensation expense of $6 and $5 million for the nine months ended September 30, 2012 and 2011, respectively. Each of the restricted unit grants also have tandem DERs which are recognized as a reduction of equity when earned. There was no material impact to the Partnership’s compensation expense as a result of the change in control of the Partnership’s general partner.

13. Derivatives and Risk Management

The Partnership is exposed to various market risks, including volatility in crude oil and refined product prices, counterparty credit risk and interest rate risk. In order to manage such exposure, the Partnership’s policy is to (i) only purchase crude oil and refined products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Although the Partnership seeks to maintain a balanced inventory position within its commodity inventories, net unbalances may occur for short periods of time due to production, transportation and delivery variances. When temporary physical inventory builds or draws do occur, the Partnership continuously manages the variances to a balanced position over a period of time. Pursuant to the Partnership’s approved risk management policy, derivative contracts may be used to hedge or reduce exposure to price risk associated with acquired inventory or forecasted physical transactions.

Price Risk Management

The Partnership is exposed to risks associated with changes in the market price of crude oil and refined products as a result of the forecasted purchase or sale of these products. These risks are primarily associated with price volatility related to pre-existing or anticipated purchases, sales and storage. Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. The physical contracts related to the Partnership’s crude oil and refined products businesses that qualify as derivatives have been designated as normal purchases and sales and are accounted for using traditional accrual accounting. The Partnership accounts for derivatives that do not qualify as normal purchases and sales at fair value. The Partnership does utilize derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing the Partnership to transfer this price risk to counterparties who are able and willing to bear it.

While all derivative instruments utilized by the Partnership represent economic hedges, certain of these derivatives are not designated as hedges for accounting purposes. Such derivatives include certain contracts that were entered into and closed during the same accounting period and a limited number of contracts for which there is not sufficient correlation to the related items being economically hedged.

For refined product derivative contracts that are not designated as hedges for accounting purposes, all realized and unrealized gains and losses are recognized in the statement of comprehensive income during the current period. For refined product derivative contracts that are designated and qualify as cash flow hedges, the portion of the gain or loss on the derivative contract that is effective in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), is recognized in earnings during the current period. All realized gains and losses associated with refined product derivative contracts are recorded in earnings in the same line item as the forecasted transaction being hedged, either sales and other operating revenue or cost of products sold and operating expenses.

The Partnership had open derivative positions of approximately 3.9 and 1.5 million barrels of refined products at September 30, 2012 and December 31, 2011, respectively. The derivatives outstanding as of September 30, 2012 vary in duration but do not extend beyond one year. The Partnership records its derivatives at fair value based on observable market prices (levels 1 and 2). As of September 30, 2012 and December 31, 2011, the fair values of the Partnership’s derivative assets and liabilities were:


	September 30, 2012			December 31, 2011
	(in millions)
Derivative assets	$	5		$	6
Derivative liabilities		(28	)		(2	)

	$	(23	)	$	4

Derivative asset and liability balances are recorded in accounts receivable and accrued liabilities, respectively, in the condensed consolidated balance sheets.

The Partnership’s derivative positions are comprised primarily of commodity contracts. The following tables set forth the impact of derivatives on the Partnership’s financial performance for the three and nine months ended September 30, 2012 and 2011:


	Gains (Losses) Recognized in Other Comprehensive Income (Loss)			Gains (Losses) Recognized in Earnings			Location of Gains (Losses) Recognized in Earnings
	(in millions)
Three Months Ended September 30, 2012
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	(17	)	$	—		Sales and other operating revenue
Commodity contracts		—			—		Cost of products sold and operating expenses

	$	(17	)	$	—

Derivatives not designated as hedging instruments:
Commodity contracts				$	(10	)	Sales and other operating revenue
Commodity contracts					3		Cost of products sold and operating expenses

				$	(7	)

Three Months Ended September 30, 2011
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	11		$	—		Sales and other operating revenue
Commodity contracts		—			—		Cost of products sold and operating expenses

	$	11		$	—

Derivatives not designated as hedging instruments:
Commodity contracts				$	5		Sales and other operating revenue
Commodity contracts					1		Cost of products sold and operating expenses

				$	6


	Gains (Losses) Recognized in Other Comprehensive Income (Loss)			Gains (Losses) Recognized in Earnings			Location of Gains (Losses) Recognized in Earnings
	(in millions)
Nine Months Ended September 30, 2012
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	(21	)	$	(3	)	Sales and other operating revenue
Commodity contracts		—			1		Cost of products sold and operating expenses

	$	(21	)	$	(2	)

Derivatives not designated as hedging instruments:
Commodity contracts				$	(7	)	Sales and other operating revenue
Commodity contracts					(4	)	Cost of products sold and operating expenses

				$	(11	)

Nine Months Ended September 30, 2011
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	12		$	(4	)	Sales and other operating revenue
Commodity contracts		—			1		Cost of products sold and operating expenses

	$	12		$	(3	)

Derivatives not designated as hedging instruments:
Commodity contracts				$	7		Sales and other operating revenue
Commodity contracts					(1	)	Cost of products sold and operating expenses

				$	6

Credit Risk Management

The Partnership maintains credit policies with regard to its counterparties that management believes minimize the overall credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The credit positions of the Partnership’s customers’ are analyzed prior to the extension of credit and periodically after credit has been extended. At September 30, 2012 and December 31, 2011, the Partnership did not hold any over-the-counter derivatives.

Interest Rate Risk Management

The Partnership has interest rate risk exposure for changes in interest rates related to its outstanding borrowings. The Partnership manages its exposure to changes in interest rates through the use of a combination of fixed-rate and variable-rate debt. At September 30, 2012, the Partnership had $179 million of consolidated variable-rate borrowings under its revolving credit facilities.

14. Fair Value Measurements

The Partnership applies fair value accounting for all financial assets and liabilities that are required to be measured at fair value under current accounting rules, primarily derivatives. The assets and liabilities that are measured at fair value on a recurring basis are not material to the Partnership’s condensed consolidated balance sheets.

The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy established by the FASB. The Partnership generally applies a “market approach” to determine fair value. This method uses pricing and other information generated by market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.

The estimated fair value of financial instruments has been determined based on the Partnership’s assessment of available market information and appropriate valuation methodologies. The Partnership’s current assets (other than derivatives and inventories) and current liabilities are financial instruments and most of these items are recorded at cost in the condensed consolidated balance sheets. The estimated fair value of these financial instruments approximates their carrying value due to their short-term nature. The

Partnership’s derivatives are measured and recorded at fair value based on observable market prices (Note 13). The estimated fair values of the Senior Notes are determined using observable market prices, as these notes are actively traded. The estimated aggregate fair value of the Senior Notes at September 30, 2012 was $1.62 billion, compared to the carrying amount of $1.45 billion. The estimated aggregate fair value of the Senior Notes at December 31, 2011 was $1.91 billion, compared to the carrying amount of $1.70 billion.

In May 2011, the FASB issued a new accounting standard update which amended the fair value measurement guidance and includes some enhanced disclosure requirements. The most significant change in disclosures is an expansion of the information required for level 3 measurements based on unobservable inputs. The Partnership adopted the amended guidance on January 1, 2012. The adoption of the amended guidance did not have a material impact on the Partnership’s condensed consolidated financial statements and disclosures.

15. Business Segment Information

The following tables summarize condensed statement of comprehensive income information concerning the Partnership’s business segments and reconcile total segment operating income to net income attributable to Sunoco Logistics Partners L.P. for the three and nine months ended September 30, 2012 and 2011, respectively.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Sales and other operating revenue ⁽¹⁾
Crude Oil Pipelines	$	108		$	81		$	288		$	233
Crude Oil Acquisition and Marketing		3,010			2,671			9,258			7,028
Terminal Facilities		101			94			406			279
Refined Products Pipelines		33			37			96			93
Intersegment eliminations		(45	)		(36	)		(127	)		(104	)

Total sales and other operating revenue	$	3,207		$	2,847		$	9,921		$	7,529


Depreciation and amortization
Crude Oil Pipelines	$	6		$	7		$	19		$	19
Crude Oil Acquisition and Marketing		6			4			16			5
Terminal Facilities		10			8			28			24
Refined Products Pipelines		4			5			13			13

Total depreciation and amortization	$	26		$	24		$	76		$	61


Impairment charge and related matters ⁽²⁾⁽³⁾
Crude Oil Acquisition and Marketing	$	—		$	—		$	8		$	—
Terminal Facilities		—			—			(10	)		—
Refined Products Pipelines		—			—			1			—

Total impairment charge and related matters	$	—		$	—		$	(1	)	$	—


Operating income
Crude Oil Pipelines	$	67		$	43		$	183		$	129
Crude Oil Acquisition and Marketing		48			41			134			75
Terminal Facilities		39			33			137			96
Refined Products Pipelines		11			11			24			24

Total operating income		165			128			478			324

Net interest expense		20			24			65			63

Income before provision for income taxes		145			104			413			261
Provision for income taxes		8			7			24			18

Net Income		137			97			389			243
Less: Net Income attributable to noncontrolling interests		3			2			8			6

Net Income Attributable to Partners	$	134		$	95		$	381		$	237

⁽¹⁾	Sales and other operating revenue includes amounts from Sunoco for the three and nine months ended September 30, 2012 and 2011 of:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions)
Crude Oil Pipelines	$	—	$	—	$	—	$	6
Crude Oil Acquisition and Marketing		101		—		307		247
Terminal Facilities		28		23		118		81
Refined Products Pipelines		12		16		36		47

Total sales and other operating revenue from Sunoco	$	141	$	39	$	461	$	381

⁽²⁾

In the first quarter 2012, the Partnership recognized a non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas. The impairment was recorded as $8 and $1 million within the Crude Oil Acquisition and Marketing and Refined Products Pipelines segments, respectively.

⁽³⁾	In the second quarter 2012, the Partnership recognized a $10 million gain on the reversal of certain regulatory obligations. Such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco’s joint venture with The Carlyle Group.

The following table provides the identifiable assets for each segment as of September 30, 2012 and December 31, 2011:


	September 30, 2012		December 31, 2011
	(in millions)
Crude Oil Pipelines	$	1,097	$	1,055
Crude Oil Acquisition and Marketing		2,291		2,469
Terminal Facilities		1,184		1,053
Refined Products Pipelines		757		736
Corporate and other^(a)		91		164

Total identifiable assets	$	5,420	$	5,477

^(a)	Corporate and other assets consist primarily of cash and cash equivalents, advances to affiliates, deferred financing costs and properties, plants and equipment.

16. Supplemental Condensed Consolidating Financial Information

The Partnership serves as guarantor of the Senior Notes. These guarantees are full and unconditional. For purposes of the following condensed consolidating financial information, Sunoco Logistics Partners L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating financial information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting.

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended September 30, 2012

(in millions, unaudited)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	3,066	$	—		$	3,066
Affiliates		—		—			141		—			141
Other income		—		—			11		—			11
Equity in earnings of subsidiaries		134		153			—		(287	)		—

Total Revenues		134		153			3,218		(287	)		3,218

Costs and Expenses
Cost of products sold and operating expenses		—		—			2,997		—			2,997
Depreciation and amortization expense		—		—			26		—			26
Selling, general and administrative expenses		—		—			30		—			30

Total Costs and Expenses		—		—			3,053		—			3,053

Operating Income		134		153			165		(287	)		165
Interest cost and debt expense, net		—		23			1		—			24
Capitalized interest		—		(4	)		—		—			(4	)

Income Before Provision for Income Taxes		134		134			164		(287	)		145
Provision for income taxes		—		—			8		—			8

Net Income		134		134			156		(287	)		137
Less: Net income attributable to noncontrolling interests		—		—			3		—			3

Net Income Attributable to Partners	$	134	$	134		$	153	$	(287	)	$	134

Comprehensive Income	$	134	$	134		$	139	$	(287	)	$	120
Less: Comprehensive income attributable to noncontrolling interests		—		—			3		—			3

Comprehensive Income Attributable to Partners	$	134	$	134		$	136	$	(287	)	$	117

Condensed Consolidating Statement of Comprehensive Income

Three Months Ended September 30, 2011

(in millions, unaudited)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	2,808	$	—		$	2,808
Affiliates		—		—			39		—			39
Other income		—		—			3		—			3
Equity in earnings of subsidiaries		95		119			—		(214	)		—

Total Revenues		95		119			2,850		(214	)		2,850

Costs and Expenses
Cost of products sold and operating expenses		—		—			2,675		—			2,675
Depreciation and amortization expense		—		—			24		—			24
Selling, general and administrative expenses		—		—			23		—			23

Total Costs and Expenses		—		—			2,722		—			2,722

Operating Income		95		119			128		(214	)		128
Interest cost and debt expense, net		—		26			—		—			26
Capitalized interest		—		(2	)		—		—			(2	)

Income Before Provision for Income Taxes		95		95			128		(214	)		104
Provision for income taxes		—		—			7		—			7

Net Income		95		95			121		(214	)		97
Less: Net income attributable to noncontrolling interests		—		—			2		—			2

Net Income Attributable to Partners	$	95	$	95		$	119	$	(214	)	$	95

Comprehensive Income	$	95	$	95		$	132	$	(214	)	$	108
Less: Comprehensive income attributable to noncontrolling interests		—		—			2		—			2

Comprehensive Income Attributable to Partners	$	95	$	95		$	130	$	(214	)	$	106

Condensed Consolidating Statement of Comprehensive Income

Nine Months Ended September 30, 2012

(in millions, unaudited)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	9,460		$	—		$	9,460
Affiliates		—		—			461			—			461
Other income		—		—			18			—			18
Gain on divestment and related matters		—		—			11			—			11
Equity in earnings of subsidiaries		381		443			—			(824	)		—

Total Revenues		381		443			9,950			(824	)		9,950

Costs and Expenses
Cost of products sold and operating expenses		—		—			9,311			—			9,311
Depreciation and amortization expense		—		—			76			—			76
Impairment charge and related matters		—		—			(1	)		—			(1	)
Selling, general and administrative expenses		—		—			86			—			86

Total Costs and Expenses		—		—			9,472			—			9,472

Operating Income		381		443			478			(824	)		478
Interest cost and debt expense, net		—		70			3			—			73
Capitalized interest		—		(8	)		—			—			(8	)

Income Before Provision for Income Taxes		381		381			475			(824	)		413
Provision for income taxes		—		—			24			—			24

Net Income		381		381			451			(824	)		389
Less: Net income attributable to noncontrolling interests		—		—			8			—			8

Net Income Attributable to Partners	$	381	$	381		$	443		$	(824	)	$	381

Comprehensive Income	$	381	$	381		$	430		$	(824	)	$	368
Less: Comprehensive income attributable to noncontrolling interests		—		—			8			—			8

Comprehensive Income Attributable to Partners	$	381	$	381		$	422		$	(824	)	$	360

Condensed Consolidating Statement of Comprehensive Income

Nine Months Ended September 30, 2011

(in millions, unaudited)


	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	7,148	$	—		$	7,148
Affiliates		—		—			381		—			381
Other income		—		—			9		—			9
Equity in earnings of subsidiaries		237		298			—		(535	)		—

Total Revenues		237		298			7,538		(535	)		7,538

Costs and Expenses
Cost of products sold and operating expenses		—		—			7,086		—			7,086
Depreciation and amortization expense		—		—			61		—			61
Selling, general and administrative expenses		—		—			67		—			67

Total Costs and Expenses		—		—			7,214		—			7,214

Operating Income		237		298			324		(535	)		324
Interest cost and debt expense, net		—		66			2		—			68
Capitalized interest		—		(5	)		—		—			(5	)

Income Before Provision for Income Taxes		237		237			322		(535	)		261
Provision for income taxes		—		—			18		—			18

Net Income		237		237			304		(535	)		243
Less: Net income attributable to noncontrolling interests		—		—			6		—			6

Net Income Attributable to Partners	$	237	$	237		$	298	$	(535	)	$	237

Comprehensive Income	$	237	$	237		$	316	$	(535	)	$	255
Less: Comprehensive income attributable to noncontrolling interests		—		—			6		—			6

Comprehensive Income Attributable to Partners	$	237	$	237		$	310	$	(535	)	$	249

Condensed Consolidating Balance Sheet

September 30, 2012

(in millions, unaudited)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries		Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—		$	2		$	—	$	—		$	2
Advances to affiliated companies		(3	)		(26	)		67		—			38
Accounts receivable, affiliated companies		—			—			1		—			1
Accounts receivable, net		—			—			1,998		—			1,998
Inventories		—			—			250		—			250

Total Current Assets		(3	)		(24	)		2,316		—			2,289

Properties, plants and equipment, net		—			—			2,678		—			2,678
Investment in affiliates		1,281			2,851			82		(4,132	)		82
Goodwill		—			—			77		—			77
Intangible assets, net		—			—			258		—			258
Other assets		—			12			24		—			36

Total Assets	$	1,278		$	2,839		$	5,435	$	(4,132	)	$	5,420

Liabilities and Equity
Accounts payable	$	—		$	—		$	1,980	$	—		$	1,980
Accrued liabilities		—			14			82		—			96
Accrued taxes payable		—			—			56		—			56

Total Current Liabilities		—			14			2,118		—			2,132

Long-term debt		—			1,544			83		—			1,627
Other deferred credits and liabilities		—			—			61		—			61
Deferred income taxes		—			—			221		—			221

Total Liabilities		—			1,558			2,483		—			4,041

Total Equity		1,278			1,281			2,952		(4,132	)		1,379

Total Liabilities and Equity	$	1,278		$	2,839		$	5,435	$	(4,132	)	$	5,420

Condensed Consolidating Balance Sheet

December 31, 2011

(in millions)


	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	2	$	3		$	—		$	5
Advances to affiliated companies		90		48		(31	)		—			107
Accounts receivable, net		—		—		2,188			—			2,188
Inventories		—		—		206			—			206

Total Current Assets		90		50		2,366			—			2,506

Properties, plants and equipment, net		—		—		2,522			—			2,522
Investment in affiliates		1,007		2,680		73			(3,687	)		73
Goodwill		—		—		77			—			77
Intangible assets, net		—		—		277			—			277
Other assets		—		13		9			—			22

Total Assets	$	1,097	$	2,743	$	5,324		$	(3,687	)	$	5,477

Liabilities and Equity
Accounts payable	$	—	$	1	$	2,110		$	—		$	2,111
Current portion of long-term debt		—		250		—			—			250
Accrued liabilities		1		37		74			—			112
Accrued taxes payable		—		—		62			—			62

Total Current Liabilities		1		288		2,246			—			2,535

Long-term debt		—		1,448		—			—			1,448
Other deferred credits and liabilities		—		—		78			—			78
Deferred income taxes		—		—		222			—			222

Total Liabilities		1		1,736		2,546			—			4,283

Total Equity		1,096		1,007		2,778			(3,687	)		1,194

Total Liabilities and Equity	$	1,097	$	2,743	$	5,324		$	(3,687	)	$	5,477

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2012

(in millions, unaudited)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	381		$	359		$	495		$	(824	)	$	411

Cash Flows from Investing Activities:
Capital expenditures		—			—			(235	)		—			(235	)
Proceeds from divestments and related matters		—			—			11			—			11
Intercompany		(290	)		(279	)		(255	)		824			—

Net cash provided by (used in) investing activities		(290	)		(279	)		(479	)		824			(224	)

Cash Flows from Financing Activities:
Distributions paid to limited and general partners		(178	)		—			—			—			(178	)
Distributions paid to noncontrolling interests		(5	)		—			—			—			(5	)
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(5	)		—			(5	)
Repayments under credit facilities		—			(322	)		—			—			(322	)
Borrowings under credit facilities		—			418			83			—			501
Repayment of senior notes		—			(250	)		—			—			(250	)
Advances to affiliated companies, net		92			74			(97	)		—			69

Net cash used in financing activities		(91	)		(80	)		(19	)		—			(190	)

Net change in cash and cash equivalents		—			—			(3	)		—			(3	)
Cash and cash equivalents at beginning of year		—			2			3			—			5

Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2011

(in millions, unaudited)


	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	237		$	225		$	288		$	(535	)	$	215

Cash Flows from Investing Activities:
Capital expenditures		—			—			(122	)		—			(122	)
Acquisitions		—			—			(396	)		—			(396	)
Intercompany		(8	)		(788	)		261			535			—

Net cash provided by (used in) investing activities		(8	)		(788	)		(257	)		535			(518	)

Cash Flows from Financing Activities:
Distributions paid to limited and general partners		(156	)		—			—			—			(156	)
Distributions paid to noncontrolling interests		(3	)		—			—			—			(3	)
Contributions from general partner		2			—			—			—			2
Payments of statutory withholding on net issuance of limited partner units under restricted unit incentive plan		—			—			(3	)		—			(3	)
Repayments under credit facilities		—			(561	)		—			—			(561	)
Borrowings under credit facilities		—			529			—			—			529
Net proceeds from issuance of long-term debt		—			595			—			—			595
Advances to affiliated companies, net		(72	)		—			(22	)		—			(94	)

Net cash provided by (used in) financing activities		(229	)		563			(25	)		—			309

Net change in cash and cash equivalents		—			—			6			—			6
Cash and cash equivalents at beginning of year		—			2			—			—			2

Cash and cash equivalents at end of period	$	—		$	2		$	6		$	—		$	8

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Results of Operations

The following table presents our consolidated operating results for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
	(in millions)
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	3,066		$	2,808		$	9,460		$	7,148
Affiliates		141			39			461			381
Other income		11			3			18			9
Gain on divestment and related matters		—			—			11			—

Total Revenues		3,218			2,850			9,950			7,538

Costs and Expenses
Cost of products sold and operating expenses		2,997			2,675			9,311			7,086
Depreciation and amortization expense		26			24			76			61
Impairment charge and related matters		—			—			(1	)		—
Selling, general and administrative expenses		30			23			86			67

Total Costs and Expenses		3,053			2,722			9,472			7,214

Operating Income		165			128			478			324
Interest cost and debt expense, net		24			26			73			68
Capitalized interest		(4	)		(2	)		(8	)		(5	)

Income Before Provision for Income Taxes		145			104			413			261
Provision for income taxes		8			7			24			18

Net Income		137			97			389			243
Less: Net income attributable to noncontrolling interests		3			2			8			6

Net income Attributable to Partners	$	134		$	95		$	381		$	237

Net income Attributable to Partners per Limited Partner unit:
Basic	$	1.09		$	0.78		$	3.15		$	1.96
Diluted	$	1.09		$	0.78		$	3.14		$	1.95

Non-GAAP Financial Measures

To supplement our financial information presented in accordance with United States generally accepted accounting principles (“GAAP”), management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measures used by management are earnings before interest, taxes, depreciation and amortization expenses and other non-cash items (“Adjusted EBITDA”) and distributable cash flow (“DCF”).

Our management believes Adjusted EBITDA and distributable cash flow information enhances an investor’s understanding of a business’s ability to generate cash for payment of distributions and other purposes. In addition, EBITDA calculations are also defined and used as a measure in determining our compliance with certain revolving credit facility covenants. However, there may be contractual, legal, economic or other reasons which may prevent us from satisfying principal and interest obligations with respect to indebtedness and may require us to allocate funds for other purposes. Adjusted EBITDA and distributable cash flow do not represent and should not be considered alternatives to net income or cash flows from operating activities as determined under GAAP and may not be comparable to other similarly titled measures of other businesses.

The following table reconciles the differences between net income, as determined under GAAP, Adjusted EBITDA and distributable cash flow:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)

Net Income Attributable to Partners	$	134		$	95		$	381		$	237
Interest cost, net		20			24			65			63
Depreciation and amortization expense		26			24			76			61
Impairment charge⁽¹⁾		—			—			9			—
Provision for income taxes		8			7			24			18

Adjusted EBITDA ⁽²⁾	$	188		$	150		$	555		$	379
Interest cost, net		(20	)		(24	)		(65	)		(63	)
Maintenance capital expenditures		(11	)		(10	)		(29	)		(20	)
Provision for income taxes		(8	)		(7	)		(24	)		(18	)

Distributable cash flow	$	149		$	109		$	437		$	278

The following table reconciles the difference between net cash provided by operating activities and Adjusted EBITDA:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Net cash provided by operating activities	$	129		$	220		$	411		$	215
Interest cost, net		20			24			65			63
Claim for recovery of environmental liability		—			—			14			—
Gain on reversal of tank cleaning liability		—			—			10			—
Net working capital pertaining to operating activities		33			(105	)		35			89
Provision for income taxes		8			7			24			18
Net income attributable to noncontrolling interests		(3	)		(2	)		(8	)		(6	)
Other		1			6			4			—

Adjusted EBITDA ⁽²⁾	$	188		$	150		$	555		$	379

⁽¹⁾	In the first quarter 2012, the Partnership recognized a non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas.

⁽²⁾

In the second quarter 2012, the Partnership recognized a $10 million gain on the reversal of certain regulatory obligations. Such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco’s joint venture with The Carlyle Group. This gain was included in the Partnership’s Adjusted EBITDA, which is consistent with prior period presentation.

Analysis of Consolidated Operating Results

Net income attributable to partners was $134 and $95 million for the three months ended September 30, 2012 and 2011, respectively. Net income attributable to partners for the third quarter 2012 increased $39 million compared to the prior year period. This increase was due primarily to improved operating performance which benefited from strong demand for crude oil transportation services, contributions from our 2011 acquisitions and organic projects and lower interest expense attributable to the repayment of $250 million of Senior Notes and a $100 million promissory note to affiliate. These positive factors were partially offset by higher selling, general and administrative expenses attributable to increased employee costs related to growth in the business.

Net income attributable to partners was $381 and $237 million for the nine months ended September 30, 2012 and 2011, respectively. Net income attributable to partners for the nine months ended September 30, 2012 increased $144 million compared to the prior year period due primarily to improved operating performance which benefited from strong demand for crude oil transportation services and contributions from our 2011 acquisitions and organic projects. Included in current year results were gains of $25 million due to the reversal of regulatory obligations that were recorded in 2011, a contract settlement in connection with the sale of a refined products terminal and pipeline assets and an asset sale by one of the Partnership’s joint venture interests. These positive factors were partially offset by increased interest expense related primarily to the $600 million Senior Notes offering in July 2011 and higher selling, general and administrative expenses attributable to increased employee costs, incentive compensation and contract services associated with growth in the business.

Analysis of Segment Operating Income

We manage our operations through four operating segments: Crude Oil Pipelines, Crude Oil Acquisition and Marketing, Terminal Facilities and Refined Products Pipelines.

Crude Oil Pipelines

Our Crude Oil Pipelines consists of crude oil trunk and gathering pipelines in the southwest and midwest United States. Revenues are generated from tariffs and the associated fees paid by shippers utilizing our transportation services to deliver crude oil and other feedstocks to refineries within those regions. Rates for shipments on these pipelines are regulated by the FERC, Oklahoma Corporation Commission (“OCC”) and the Railroad Commission of Texas (“Texas R.R.C.”).

The following table presents the operating results and key operating measures for our Crude Oil Pipelines for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions, except for barrel amounts)
Sales and other operating revenue:
Unaffiliated customers	$	72	$	52	$	187	$	141
Affiliates		—		—		—		6
Intersegment revenue		36		29		101		86

Total sales and other operating revenue	$	108	$	81	$	288	$	233

Depreciation and amortization expense	$	6	$	7	$	19	$	19

Operating Income	$	67	$	43	$	183	$	129

Pipeline throughput (thousands of barrels per day ("bpd"))		1,601		1,637		1,546		1,591
Pipeline revenue per barrel (cents)		73.6		54.0		68.0		53.7

Operating income for the Crude Oil Pipelines increased $24 million to $67 million for the three months ended September 30, 2012, as compared to $43 million for the three months ended September 30, 2011. The increase in operating income was driven primarily by higher pipeline fees which benefited from tariff increases relative to the prior year period, organic growth projects and an improved mix of pipeline movements which benefited from the demand for West Texas crude oil ($29 million). Partially offsetting these improvements were overall volume reductions ($2 million) and increased selling, general and administrative expenses ($2 million).

Operating income for the Crude Oil Pipelines increased $54 million to $183 million for the nine months ended September 30, 2012, as compared to $129 million for the nine months ended September 30, 2011. The increase in operating income was driven primarily by higher pipeline fees which benefited from tariff increases relative to the prior year period, organic growth projects and an improved mix of pipeline movements which benefited from the demand for West Texas crude oil ($61 million). Partially offsetting these improvements were increased selling, general and administrative expenses ($7 million) and overall volume reductions ($6 million).

Crude Oil Acquisition and Marketing

Our Crude Oil Acquisition and Marketing segment reflects the sale of gathered and bulk purchased crude oil. The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold as a result of the significant volume of crude oil bought and sold. However, the absolute price levels of crude oil normally do not bear a relationship to gross margin, although the price levels significantly impact revenue and costs of products sold. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross margin for the Crude Oil Acquisition and Marketing segment. The operating results of the Crude Oil Acquisition and Marketing segment are affected by overall levels of supply and demand for crude oil and relative fluctuations in market related indices. Generally, we expect a base level of earnings from our Crude Oil Acquisition and Marketing segment that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials and/or a steep contango or backwardated structure. Our management believes gross margin, which is equal to sales and other operating revenue less cost of products sold, operating expenses and depreciation and amortization, is a key measure of financial performance for the Crude Oil Acquisition and Marketing segment. Although we employ risk management activities, these margins are not fixed and will vary from period-to-period.

The following table presents the operating results and key operating measures for our Crude Oil Acquisition and Marketing for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions, except for barrel amounts)
Sales and other operating revenue:
Unaffiliated customers	$	2,909	$	2,671	$	8,951	$	6,780
Affiliates		101		—		307		247
Intersegment revenue		—		—		—		1

Total sales and other operating revenue	$	3,010	$	2,671	$	9,258	$	7,028

Depreciation and amortization expense	$	6	$	4	$	16	$	5

Impairment charge	$	—	$	—	$	8	$	—

Operating Income⁽¹⁾	$	48	$	41	$	134	$	75

Crude oil purchases (thousands of bpd)		692		723		674		654
Gross margin per barrel purchased (cents)⁽¹⁾⁽²⁾		83.1		66.3		84.2		47.2
Average crude oil price (per barrel)	$	92.19	$	89.81	$	96.20	$	95.52

⁽¹⁾	In August 2011, the Partnership acquired a crude oil acquisition and marketing business from Texon L.P. Results from the acquisition are included from the acquisition date.

⁽²⁾	Represents total segment sales and other operating revenue less cost of products sold and operating expenses and depreciation and amortization, divided by crude oil purchases.

Operating income for the Crude Oil Acquisition and Marketing segment increased $7 million to $48 million for the three months ended September 30, 2012, as compared to $41 million for the three months ended September 30, 2011. The increase in operating income was driven primarily by expanded crude oil margins which were the result of expansion in our crude oil trucking fleet and market related opportunities in West Texas. Operating results also benefited from improved margins from the crude oil acquisition and marketing assets acquired from Texon L.P. in the third quarter 2011.

Operating income for the Crude Oil Acquisition and Marketing segment increased $59 million to $134 million for the nine months ended September 30, 2012, as compared to $75 million for the nine months ended September 30, 2011. The increase in operating income was driven primarily by expanded crude oil volumes and margins which were the result of expansion in our crude oil trucking fleet and market related opportunities in West Texas. Operating results were further improved by increased volumes and margins from the crude oil acquisition and marketing assets acquired from Texon L.P. in the third quarter 2011. Partially offsetting these improvements was an $8 million non-cash impairment charge related to a cancelled software project.

Terminal Facilities

Our Terminal Facilities segment consists primarily of crude oil and refined products terminals and a refined products acquisition and marketing business. The Terminal Facilities earn revenue by providing storage, terminalling, blending and other ancillary services to our customers, as well as through the sale of refined products.

The following table presents the operating results and key operating measures for our Terminal Facilities for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012			2011
	(in millions, except for barrel amounts)
Sales and other operating revenue:
Unaffiliated customers	$	65	$	65	$	264		$	181
Affiliates		28		23		118			81
Intersegment revenue		8		6		24			17

Total sales and other operating revenue	$	101	$	94	$	406		$	279

Depreciation and amortization expense	$	10	$	8	$	28		$	24

Impairment charge and other matters	$	—	$	—	$	(10	)	$	—

Operating Income⁽¹⁾	$	39	$	33	$	137		$	96

Terminal throughput (thousands of bpd):
Refined products terminals⁽¹⁾		495		497		499			485
Nederland terminal		721		869		703			779
Refinery terminals⁽¹⁾		381		483		369			422

⁽¹⁾	In July and August 2011, the Partnership acquired the Eagle Point tank farm and related assets and a refined products terminal located in East Boston, Massachusetts, respectively. Results from the acquisitions are included from their respective acquisition dates.

Operating income for the Terminal Facilities increased $6 million to $39 million for the three months ended September 30, 2012, as compared to $33 million for the three months ended September 30, 2011. The increase in operating income was due primarily to increased operating results from the Partnership’s refined products acquisition and marketing activities ($6 million) and contributions from the 2011 acquisitions of the Eagle Point tank farm and a refined products terminal in East Boston, Massachusetts ($5 million). These positive factors were partially offset by reduced volumes from the idling of the Marcus Hook refinery in the fourth quarter 2011 ($2 million) and higher selling, general and administrative expenses ($2 million).

Operating income for the Terminal Facilities increased $41 million to $137 million for the nine months ended September 30, 2012, as compared to $96 million for the nine months ended September 30, 2011. Operating income for 2012 included non-recurring gains related to the reversal of certain regulatory obligations that were recorded in 2011 ($10 million) and a contract settlement associated with the Partnership’s sale of the Big Sandy terminal and pipeline assets ($6 million). Excluding these items, operating income increased $25 million due to contributions from the 2011 acquisitions of the Eagle Point tank farm and a refined products terminal in East Boston, Massachusetts ($17 million), operating results from the Partnership’s refined products acquisition and marketing activities ($12 million) and improved results from the Partnership’s Nederland terminals ($5 million). Partially offsetting these increases were reduced volumes at the Partnership’s refinery terminals related to the idling of Sunoco’s Marcus Hook refinery in the fourth quarter 2011 ($4 million) and increased selling, general and administrative expenses ($5 million).

Refined Products Pipelines

Our Refined Products Pipelines segment consists of refined products pipelines, including a two-thirds undivided interest in the Harbor pipeline and joint venture interests in four refined products pipelines in selected areas of the United States. The Refined Products Pipelines earn revenues by transporting refined products from refineries in the northeast, midwest and southwest United States to markets in 6 states and Canada. Rates for shipments on these pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) and the Pennsylvania Public Utility Commission (“PA PUC”).

The following table presents the operating results and key operating measures for our Refined Products Pipelines for the three and nine months ended September 30, 2012 and 2011:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions, except for barrel amounts)
Sales and other operating revenue:
Unaffiliated customers	$	20	$	20	$	58	$	45
Affiliates		12		17		36		48
Intersegment revenue		1		—		2		—

Total sales and other operating revenue	$	33	$	37	$	96	$	93

Depreciation and amortization expense	$	4	$	5	$	13	$	13

Impairment charge	$	—	$	—	$	1	$	—

Operating Income⁽¹⁾	$	11	$	11	$	24	$	24

Pipeline throughput (thousands of bpd)⁽¹⁾⁽²⁾		576		605		565		496
Pipeline revenue per barrel (cents)⁽¹⁾⁽²⁾		62.2		66.2		62.2		68.6

⁽¹⁾	In May 2011, the Partnership acquired a controlling financial interest in the Inland refined products pipeline. As a result of the acquisition, the Partnership accounted for the entity as a consolidated subsidiary. Results from the acquisition are included from the acquisition date.

⁽²⁾	Excludes amounts attributable to equity interests which are not consolidated.

Operating income for the Refined Products Pipelines was consistent at $11 million for the three months ended September 30, 2012 and 2011, respectively. Increased equity income was related to the Partnership’s joint venture interest in Explorer Pipeline Company which recognized a non-recurring gain on an asset sale ($4 million). This increase was offset by lower pipeline volumes and fees driven primarily by the idling of Sunoco’s Marcus Hook refinery in the fourth quarter 2011 ($4 million).

Operating income for the Refined Products Pipelines was consistent at $24 million for the nine months ended September 30, 2012 and 2011, respectively. Operating income for 2012 includes non-recurring gains for a contract settlement associated with the Big Sandy refined products terminal and pipeline asset sale ($5 million) and the Explorer Pipeline Company asset sale discussed above ($4 million). Excluding these items, operating income for the Refined Products Pipelines decreased $9 million compared to the prior period. Increased contributions from the acquisition of the Inland refined products pipeline ($5 million) were offset by lower pipeline volumes and fees driven primarily by the idling of the Marcus Hook refinery ($9 million) and increased environmental remediation expenses associated with a pipeline release in the first quarter 2012 ($4 million).

Acquisition of Sunoco

On October 5, 2012, Sunoco was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco through its wholly-owned subsidiary Sunoco Partners LLC served as the Partnership’s general partner and owned a two percent general partner interest, all of the incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. Sunoco continues to operate its retail marketing network and is expected to continue utilizing the Partnership’s pipeline and tank assets.

The Partnership expects that the acquisition of Sunoco’s interests by ETP will result in the termination of Sunoco Logistics Partners L.P. for federal income tax purposes. The Partnership will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. In order to determine whether a sale or exchange of 50 percent or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including units which are actively traded in the public market and transfers of units by our affiliates. Generally, the information that we obtain prior to year end is not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50 percent or more of our capital and profits within the prior twelve-month period. However, given the level of Partnership interests acquired by ETP, it is likely that a termination of Sunoco Logistics Partners L.P. has occurred for federal income tax purposes.

The termination does not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. This termination will require us to close our taxable year, make new elections as to various tax matters and reset the depreciation schedule for our depreciable assets for federal income tax purposes. The resetting of our depreciation schedule will result in a deferral of the depreciation deductions allowable in computing taxable income to our unitholders.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under the $585 million of credit facilities are our primary sources of liquidity. At September 30, 2012, we had net working capital of $157 million and available borrowing capacity under credit facilities of $406 million. Our working capital position reflects crude oil and refined products inventories based on historical costs under the last-in, first-out (“LIFO”) method of accounting. If the inventories had been valued at their current replacement cost, we would have had working capital of $305 million at September 30, 2012. We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Credit Facilities

The Partnership maintains two credit facilities to fund the Partnership’s working capital requirements, finance acquisitions and capital projects and for general partnership purposes with total borrowing capacity of $550 million. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 (the “$350 million Credit Facility”) and a $200 million unsecured credit facility which expires in August 2013 (the “$200 million Credit Facility”). Outstanding borrowings under these credit facilities were $170 million at September 30, 2012. There were no borrowings outstanding at December 31, 2011.

The Partnership’s credit facilities contain various covenants limiting the Partnership’s ability to incur indebtedness; grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets, including the sale or transfer of interests in the Operating Partnership’s subsidiaries. The credit facilities also limit the Partnership, on a rolling four-quarter basis, to a maximum total consolidated debt to consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. The Partnership’s ratio of total debt to EBITDA was 2.3 to 1 at September 30, 2012, as calculated in accordance with the credit agreements.

In May 2012, West Texas Gulf Pipe Line Company, one of the Partnership’s consolidated joint ventures, entered into a $35 million revolving credit facility (the “$35 million Credit Facility”) which expires in May 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. The $35 million Credit Facility contains various covenants limiting West Texas Gulf’s ability to grant certain liens; make certain loans, acquisitions and investments; make any material change to the nature of its business; or enter into a merger or sale of assets. The credit facility also limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending September 30, 2012 shall not be less than 0.80 to 1. The minimum ratio fluctuates between 0.80 to 1 and 1.00 to 1 throughout the term of the revolver as specified in the credit agreement. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 0.98 to 1 and 0.28 to 1, respectively, at September 30, 2012. Outstanding borrowings under this credit facility were $9 million at September 30, 2012.

Cash Flows and Capital Expenditures

Net cash provided by operating activities for the nine months ended September 30, 2012 was $411 million compared with $215 million for the nine months ended September 30, 2011. Net cash provided by operating activities in 2012 related primarily to net income of $389 million and non-cash charges for depreciation and amortization of $76 million partially offset by $14 million in spending for environmental liabilities which are expected to be recovered under the Partnership’s insurance programs and a $35 million increase in working capital. Net cash provided by operating activities in 2011 related primarily to net income of $243 million and non-cash charges for depreciation and amortization of $61 million. These sources were partially offset by an $89 million increase in working capital which was primarily the result of the Partnership’s increased contango inventory positions.

Net cash used in investing activities for the nine months ended September 30, 2012 was $224 million compared with $518 million for the nine months ended September 30, 2011. Net cash used in investing activities in 2012 consisted primarily of expansion capital projects and maintenance capital on the Partnership’s existing assets, partially offset by $11 million of proceeds received for the sale of the Big Sandy terminal and pipeline assets and the settlement of related throughput and deficiency contracts. Net cash used in investing activities in 2011 consisted primarily of the significant acquisitions ($396 million), as well as expansion capital projects and maintenance capital on the Partnership’s existing assets.

Net cash used in financing activities for the nine months ended September 30, 2012 was $190 million compared with $309 million provided by financing activities for the nine months ended September 30, 2011. Net cash used in financing activities in 2012 resulted primarily from the $250 million repayment of 7.25% Senior Notes in February 2012 and $178 million in distributions paid to limited partners and the general partner. These uses of cash were partially offset by $179 million of net credit facility borrowings and a $69 million decrease in advances to affiliates. Net cash provided by financing activities for the nine months ended September 30, 2011 resulted from $595 million in net proceeds related to the August 2011 offering of the 2022 and 2042 Senior Notes. This source of cash was partially offset by $156 million in distributions paid to limited partners and the general partner, a $94 million increase in advances to affiliates and $32 million of net repayments under the Partnership’s previous credit facilities.

Capital Requirements

Our operations are capital intensive, requiring significant investment to maintain, upgrade and enhance existing assets and to meet environmental and operational regulations. The capital requirements have consisted, and are expected to continue to consist, primarily of:

•

Maintenance capital expenditures that extend the usefulness of existing assets, such as those required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations,

•

Expansion capital expenditures to acquire and integrate complementary assets to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume, and

•

Major acquisitions to acquire and integrate complementary assets to grow the business, to improve operational efficiencies or reduce costs.

The following table summarizes maintenance and expansion capital expenditures, including amounts paid for acquisitions, for the periods presented:


	Nine Months Ended
	September 30,
	2012		2011
	(in millions)
Maintenance	$	29	$	20
Expansion		206		102
Major Acquisitions⁽¹⁾		—		494

Total	$	235	$	616

⁽¹⁾	Includes $98 million of Class A units issued in connection with the purchase of the Eagle Point tank farm.

The Class A units converted to common units in July 2012.

Maintenance capital expenditures for both periods presented include recurring expenditures such as pipeline integrity costs, pipeline relocations, repair and upgrade of field instrumentation, including measurement devices, repair and replacement of tank floors and roofs, upgrades of cathodic protection systems, crude trucks and related equipment, and the upgrade of pump stations. The Partnership continues to estimate its maintenance capital spending to be approximately $50 million in 2012.

Expansion capital in 2012 included projects to expand upon the Partnership’s refined products acquisition and marketing services, upgrade the service capabilities at the Eagle Point terminal, invest in the Partnership’s crude oil infrastructure by increasing its pipeline capabilities through previously announced growth projects in West Texas and expanding the trucking fleet, increase service capabilities at the Partnership’s Nederland terminal and convert certain refined products pipelines as part of the Mariner West Project. The Partnership expects total expansion capital of approximately $350 million for 2012, and $700 million in expansion capital during 2013, excluding major acquisitions. Expansion capital in 2011 included projects to expand upon the Partnership’s existing butane blending business, increase the tankage at the Nederland facility and expand the Partnership’s refined products platform in the southwest United States.

Major acquisitions during the nine months ended September 30, 2011 include the East Boston terminal for $73 million including inventory, the Texon crude oil purchasing and marketing business for $222 million including inventory, the Eagle Point tank farm for $100 million, and an 83.8 percent equity interest in Inland Corporation for $99 million, which owns a refined products pipeline system in Ohio.

We expect to fund capital expenditures, including any additional acquisitions, from cash provided by operations and, to the extent necessary, from the proceeds of borrowings under our credit facilities, other borrowings and the issuance of additional common units.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including changing interest rates and volatility in crude oil and refined products commodity prices. To manage such exposure, interest rates, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management.

Interest Rate Risk

We have interest-rate risk exposure for changes in interest rates relating to our outstanding borrowings. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and variable-rate debt. At September 30, 2012, we had $179 million of variable-rate borrowings under the revolving credit facilities. Outstanding borrowings bear interest cost of LIBOR plus an applicable margin. Our weighted average interest rate on our variable-rate borrowings was approximately 1.5 percent at September 30, 2012. A one-percent change in the weighted average rate would have impacted annual interest expense by approximately $2 million.

At September 30, 2012, we had $1.45 billion of fixed-rate borrowings, which had an estimated fair value of $1.62 billion at September 30, 2012. A hypothetical one-percent decrease in interest rates would increase the fair value of our fixed-rate borrowings at September 30, 2012 by approximately $150 million.

Commodity Market Risk

We are exposed to volatility in crude oil and refined products commodity prices. To manage such exposures, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management and inventory carried. Our policy is to purchase only commodity products for which we have a market and to structure our sales contracts so that price fluctuations for those products do not materially affect the margin we receive. We also seek to maintain a position that is substantially balanced within our various commodity purchase and sale activities. We may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions. When unscheduled physical inventory builds or draws do occur, they are monitored and managed to a balanced position over a reasonable period of time.

We do not use futures or other derivative instruments to speculate on crude oil or refined products prices, as these activities could expose us to significant losses. We do use derivative contracts as economic hedges against price changes related to our forecasted refined products purchase and sale activities. These derivatives are intended to have equal and opposite effects of the purchase and sale activities. At September 30, 2012, the fair market value of our open derivative positions was a net liability of $23 million on 3.9 million barrels of refined products. These derivative positions vary in length but do not extend beyond one year.

For additional information concerning our commodity market risk activities, see Note 13 to the Condensed Consolidated Financial Statements.

Forward-Looking Statements

Some of the information included in this quarterly report on Form 10-Q contains “forward-looking” statements and information relating to Sunoco Logistics Partners L.P. that is based on the current beliefs of our management as well as assumptions made by, and information currently available to, our management.

Forward-looking statements discuss expected future results based on current and pending business operations, and may be identified by words such as “may,” “anticipates,” “believes,” “expects,” “estimates,” “planned,” “scheduled” or similar phrases or expressions. Although we believe these forward-looking statements are reasonable, they are based upon a number of assumptions, any or all of which may ultimately prove to be inaccurate. These statements are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results projected, forecasted, estimated or budgeted, including, but not limited to the following:

•

Our ability to successfully consummate announced acquisitions or expansions and integrate them into existing business operations;

•

Delays related to construction of, or work on, new or existing facilities and the issuance of applicable permits;

•

Changes in demand for, or supply of, crude oil and petroleum products that impact demand for our pipeline, terminalling and storage services;

•

Changes in the short-term and long-term demand for crude oil, refined petroleum products and natural gas liquids we buy and sell;

•

The loss of Sunoco as a customer or a significant reduction in its current level of throughput and storage with us;

•

An increase in the competition encountered by our terminals, pipelines and crude oil and refined products acquisition and marketing operations;

•

Changes in the financial condition or operating results of joint ventures or other holdings in which we have an equity ownership interest;

•

Changes in the general economic conditions in the United States;

•

Changes in laws and regulations to which we are subject, including federal, state, and local tax, safety, environmental and employment laws;

•

Changes in regulations governing composition of the products that we transport, terminal and store;

•

Improvements in energy efficiency and technology resulting in reduced demand for petroleum products;

•

Our ability to manage growth and/or control costs;

•

The ability of ETP to successfully integrate our operations and employees, and realize anticipated synergies;

•

The effect of changes in accounting principles and tax laws and interpretations of both;

•

Global and domestic economic repercussions, including disruptions in the crude oil and petroleum products markets, from terrorist activities, international hostilities and other events, and the government’s response thereto;

•

Changes in the level of operating expenses and hazards related to operating facilities (including equipment malfunction, explosions, fires, spills and the effects of severe weather conditions);

•

The occurrence of operational hazards or unforeseen interruptions for which we may not be adequately insured;

•

The age of, and changes in the reliability and efficiency of our operating facilities;

•

Changes in the expected level of capital, operating, or remediation spending related to environmental matters;

•

Changes in insurance markets resulting in increased costs and reductions in the level and types of coverage available;

•

Risks related to labor relations and workplace safety;

•

Non-performance by or disputes with major customers, suppliers or other business partners;

•

Changes in our tariff rates implemented by federal and/or state government regulators;

•

The amount of our debt, which could make us vulnerable to adverse general economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to competitors that have less debt, or have other adverse consequences;

•

Restrictive covenants in our credit agreements;

•

Changes in our or our general partner’s credit ratings, as assigned by rating agencies;

•

The condition of the debt capital markets and equity capital markets in the United States, and our ability to raise capital in a cost-effective way;

•

Performance of financial institutions impacting our liquidity, including those supporting our credit facilities;

•

The effectiveness of our risk management activities, including the use of derivative financial instruments to hedge commodity risks;

•

Changes in interest rates on our outstanding debt, which could increase the costs of borrowing; and

•

The costs and effects of legal and administrative claims and proceedings against us or any entity in which we have an ownership interest, and changes in the status of, or the initiation of new litigation, claims or proceedings, to which we, or any entity in which we have an ownership interest, are a party.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events.

Item 4.

Controls and Procedures

Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership’s reports under the Exchange Act is accumulated and communicated to management, including the President and Chief Executive Officer and Chief Financial Officer of Sunoco Partners LLC (the Partnership’s general partner), as appropriate, to allow timely decisions regarding required disclosure.

As of September 30, 2012, the Partnership carried out an evaluation, under the supervision and with the participation of the management of the general partner (including the President and Chief Executive Officer and the Chief Financial Officer), of the effectiveness of the design and operation of the Partnership’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner’s President and Chief Executive Officer, and its Chief Financial Officer, concluded that the Partnership’s disclosure controls and procedures are effective.

No change in the Partnership’s internal control over financial reporting has occurred during the fiscal quarter ended September 30, 2012 that has materially affected, or that is reasonably likely to materially affect, the Partnership’s internal control over financial reporting. The acquisition of Sunoco’s interest in the general partner by ETP did not materially affect the Partnership’s internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1.

Legal Proceedings

There are certain proceedings arising prior to the February 2002 initial public offering (“IPO”) pending against our Sunoco-affiliated predecessors and us (as successor to certain liabilities of those predecessors). Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them may be resolved unfavorably. Sunoco has agreed to indemnify the Partnership for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of February 8, 2002. There is no monetary cap on this indemnification from Sunoco. Sunoco’s share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the February 8, 2002 date. Any remediation liabilities not covered by this indemnity will be our responsibility. In addition, Sunoco is obligated to indemnify us under certain other agreements executed after the IPO.

The Partnership’s Sunoco Pipeline L.P. subsidiary operates the West Texas Gulf Pipeline on behalf of West Texas Gulf Pipe Line Company and its shareholders pursuant to an Operating Agreement. Sunoco Pipeline L.P. also has a 60.3 percent ownership interest in the Company. In March 2010, Sunoco Pipeline L.P. received a Notice of Probable Violation, Proposed Civil Penalty and proposed Compliance Order from the Pipeline Hazardous Material Safety Administration (“PHMSA”) with proposed civil penalties in connection with a crude oil release that occurred at the Colorado City, Texas station on the West Texas Gulf Pipeline in June 2009. PHMSA issued a final order in August 2012 finding the Partnership in violation of all items identified in the original notice. The Partnership paid $0.4 million during the third quarter 2012 but has requested a petition for reconsideration on certain of the violations. The Partnership is awaiting a response from PHMSA.

There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Our management believes that any liabilities that may arise from these legal proceedings will not be material to our results of operations, cash flows or financial position at September 30, 2012.

Item 1A.

Risk Factors

During 2011 and 2012, Sunoco, Inc. (“Sunoco”) executed a number of strategic transactions to facilitate its shift away from manufacturing. In addition to the sale of its Toledo, OH refinery in March 2011, Sunoco indefinitely idled the main processing units at the Marcus Hook, PA refinery in December 2011. Sunoco continues to pursue alternative strategic options for these assets. In September 2012, Sunoco completed the formation of Philadelphia Energy Solutions (“PES”), a joint venture with The Carlyle Group that will continue to operate the Philadelphia, PA refinery.

On October 5, 2012, Sunoco was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco, through its wholly owned subsidiary Sunoco Partners LLC, served as the Partnership’s general partner and owned a two percent general partner interest, all of the incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner, including the incentive distribution rights, and limited partnership were contributed to ETP. This resulted in a change in control of the general partner, and as a result, the Partnership became a consolidated subsidiary of ETP subsequent to these transactions.

The Partnership has updated its risk factor information below to reflect the impacts of these transactions, including the change in the general partner ownership, and the ongoing business implications. If any of the following risks actually were to occur, our business, results of operations, financial condition and cash flows as well as any related benefits of owning our securities, could be materially and adversely affected.

RISKS RELATED TO OUR BUSINESS

If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future, could be materially impaired.

Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and credit facilities, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income. Our ability to generate sufficient cash from operations is largely dependent on our ability to successfully manage our business which may also be affected by economic, financial, competitive, and regulatory factors that are beyond our control. To the extent we do not have adequate cash reserves, our ability to pay quarterly distributions to our common unitholders at current levels could be materially impaired.

We depend upon Sunoco for a substantial portion of the volumes transported on our refined products pipelines and handled at our terminals. If Sunoco were to significantly reduce these volumes, it could materially and adversely affect our results of operations, financial condition or cash flows.

Our refined products pipeline and terminal assets provide a cost effective and efficient outlet to supply Sunoco’s retail marketing network, and as such, we expect that Sunoco will continue to utilize our assets going forward. However, if Sunoco were to reduce its use of our facilities, it could adversely affect our results of operations, financial condition, or cash flows.

A sustained decrease in demand for refined products in the markets served by our pipelines and terminals could materially and adversely affect our results of operations, financial position, or cash flows.

The following are material factors that could lead to a sustained decrease in market demand for refined products:

•

a sustained recession or other adverse economic condition that results in lower purchases of refined petroleum products;

•

higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions, or other factors;

•

higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;

•

a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and

•

a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.

A material decrease in demand or distribution of crude oil available for transport through our pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.

The volume of crude oil transported through our crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by our assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to our customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in our crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position, or cash flows could be materially and adversely affected.

Any reduction in the capability of our shippers to utilize either our pipelines or interconnecting third-party pipelines could cause a reduction of volumes transported in our pipelines and through our terminals.

Users of our pipelines and terminals are dependent upon our pipelines, as well as connections to third-party pipelines, to receive and deliver crude oil and refined products. Any interruptions or reduction in the capabilities of our pipelines or these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in our pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.

If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our results of operations, financial condition, or cash flows could be affected materially and adversely.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:

•

denial or delay in issuing requisite regulatory approvals and/or permits;

•

unplanned increases in the cost of construction materials or labor;

•

disruptions in transportation of modular components and/or construction materials;

•

severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;

•

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

•

changes in market conditions impacting long lead-time projects;

•

market-related increases in a project’s debt or equity financing costs; and

•

nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

Our forecasted operating results also are based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative supplies of crude oil and refined products and overall customer demand.

Future acquisitions and expansions may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.

We evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly.

Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets, new geographic areas and the businesses associated with them. 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. In some cases, we have indemnified the previous owners and operators of acquired assets.

Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions. In addition, the terms of an acquisition may require us to assume certain prior known or unknown liabilities for which we may not be indemnified or have adequate insurance.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

Our operations and those of our customers and suppliers may be subject to operational hazards or unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. If one or more of the facilities that we own or any third-party facilities that we receive from or deliver to, are damaged by any disaster, accident, catastrophe or other event, our operations could be significantly interrupted. These interruptions might involve a loss of equipment or life, injury, extensive property damage, or maintenance and repair outages. The duration of the interruption will depend on the seriousness of the damages or required repairs. We may not be able to maintain or obtain insurance to cover these types of interruptions, or in coverage amounts desired, at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could materially and adversely affect our results of operations, financial position, or cash flows.

We are exposed to the credit and other counterparty risk of our customers in the ordinary course of our business.

We have various credit terms with virtually all of our customers, and our customers have varying degrees of creditworthiness. Although we evaluate the creditworthiness of each of our customers, we may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose us to an increased risk of nonpayment or other default under our contracts and other arrangements with them. In the event that a material customer or customers default on their payment obligations to us, this could materially adversely affect our results of operations, financial position, or cash flows.

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, or reduced crude oil marketing margins or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

Rate regulation or market conditions may not allow us to recover the full amount of increases in our costs. Additionally, a successful challenge to our rates could materially and adversely affect our results of operations, financial position, or cash flows.

The primary rate-making methodology of the Federal Energy Regulatory Commission (“FERC”) is price indexing. We use this methodology in many of our interstate markets. In an order issued in December 2010, the FERC announced that, effective July 1, 2011, the index would equal the change in the producer price index for finished goods plus 2.65 percent (previously, the index was equal to the change in the producer price index for finished goods plus 1.3 percent). This index is to be in effect through July 2016. If the

changes in the index are not large enough to fully reflect actual increases to our costs, our financial condition could be adversely affected. If the index results in a rate increase that is substantially in excess of the pipeline’s actual cost increases, or it results in a rate decrease that is substantially less than the pipeline’s actual cost decrease, the rates may be protested, and, if successful, result in the lowering of the pipeline’s rates. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.

Under the Energy Policy Act adopted in 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” On our FERC-regulated pipelines, most of our revenues are derived from such grandfathered rates. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. There is a risk that some rates could be found to be in excess of levels justified by our cost of service. In such event, the FERC would order us to reduce rates prospectively and could order us to pay reparations to shippers. Reparations could be required for a period of up two years prior to the date of filing the complaint in the case of rates that are not grandfathered and for the period starting with the filing of the complaint in the case of grandfathered rates.

In addition, a state commission could also investigate our intrastate rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates.

Potential changes to current rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future. In addition, if the FERC’s petroleum pipeline ratemaking methodology changes, the new methodology could materially and adversely affect our results of operations, financial position, or cash flows.

Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require substantial expenditures.

Our pipelines, gathering systems, and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of refined products and crude oil result in a risk that refined products, crude oil, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury, or property damage to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products and crude oil for many years. Many of these properties also have been previously owned or operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control, and for which, in some cases, we have indemnified the previous owners and operators.

Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. We may be unable to recover these costs through increased revenues.

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 and transport.

The 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 to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, the operations of our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending services licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate the butane blending acquisition.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our services.

The U.S. Senate has considered legislation to restrict U.S. emissions of carbon dioxide and other greenhouse gases (“GHG”) that may contribute to global warming and climate change. Many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce GHG emissions. The U.S. House of Representatives has previously approved legislation to establish a “cap-and-trade” program, whereby the U.S. Environmental Protection Agency (“EPA”) would issue a capped

and steadily declining number of tradable emissions allowances to certain major GHG emission sources so they could continue to emit GHGs into the atmosphere. The cost of such allowances would be expected to escalate significantly over time, making the combustion of carbon-based fuels (e.g., refined petroleum products, oil and natural gas) increasingly expensive. Beginning in 2011, EPA regulations required specified large domestic GHG sources to report emissions above a certain threshold occurring after January 1, 2010. Our facilities are not subject to this reporting requirement since our GHG emissions are below the applicable threshold. In addition, the EPA has proposed new regulations, under the federal Clean Air Act, that would require a reduction in GHG emissions from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. It is not possible at this time to predict how pending legislation or new regulations to address GHG emissions would impact our business. However, the adoption and implementation of federal, state, or local laws or regulations limiting GHG emissions in the U.S. could adversely affect the demand for our crude oil or refined products transportation and storage services, and result in increased compliance costs, reduced volumes or additional operating restrictions.

Terrorist attacks aimed at our facilities could adversely affect our business.

The U.S. government has issued warnings that energy assets, specifically the nation’s pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries, or terminals could materially and adversely affect our results of operations, financial position, or cash flows.

Our risk management policies cannot eliminate all commodity risk, and our use of hedging arrangements could result in financial losses or reduce our income. In addition, any non-compliance with our risk management policies could result in significant financial losses.

We follow risk management practices designed to minimize commodity risk, and engage in hedging arrangements to reduce our exposure to fluctuations in the prices of refined products. These hedging arrangements expose us to risk of financial loss in some circumstances, including when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for such refined products.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our condensed consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our condensed consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

We have adopted risk management policies designed to manage risks associated with our businesses. However, these policies cannot eliminate all price-related risks, and there is also the risk of non-compliance with such policies. We cannot make any assurances that we will detect and prevent all violations of our risk management practices and policies, particularly if deception or other intentional misconduct is involved. Any violations of our risk management practices or policies by our employees or agents could result in significant financial losses.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, and we are subject to the possibility of increased costs to retain necessary land use which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

Whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline (e.g., crude oil, or refined products) and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our results of operations and cash flows.

A portion of our general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

We utilize both Sunoco and third parties in the processing of our information and data. Breaches of our security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss or misuse of this information, result in litigation and potential liability for us, lead to reputational damage, increase our compliance costs, or otherwise harm our business. The Partnership continues to work with ETP in determining how the acquisition will impact these general and administrative functions going forward.

Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. 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. 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, and regulatory penalties, disrupt our operations, and damage our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

Our general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement provides that our general partner may reduce operating surplus by establishing cash reserves to provide funds for our future operating expenditures. In addition, the partnership agreement provides that our general partner may reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to our unitholders in any one or more of the next four quarters. These cash reserves will affect the amount of cash available for current distribution to our unitholders.

Even if unitholders are dissatisfied, they have limited rights under the Partnership agreement to remove our general partner without its consent, which could lower the trading price of the common units.

The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by ETP, the sole member of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner has the right to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of our general partner from transferring its ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of the general partner with its own appointees.

Conflicts of interest may arise between us and ETP, as the owner of our general partner which, due to limited fiduciary responsibilities, may permit ETP and its affiliates to favor their own interests to the detriment of our unitholders.

ETP owns and controls our two percent general partner interest and owns 32.4 percent of our limited partnership interests. Conflicts of interest may arise, from time to time, between ETP and its affiliates (including our general partner), on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates (including ETP) over the interests of our unitholders. These conflicts may include, among others, the following situations:

•

ETP and its affiliates may engage in competition with us. Neither our partnership agreement nor any other agreement requires ETP to pursue a business strategy that favors us or utilizes our assets, and our general partner may consider the interests of parties other than us, such as ETP, in resolving conflicts of interest;

•

under our partnership agreement, our general partner's fiduciary duties are restricted, and our unitholders have only limited remedies available in the event of conduct constituting a potential breach of fiduciary duty by our general partner;

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash available for distribution to our unitholders and the amount received by our general partner in respect of its incentive distribution rights (“IDRs”);

•

our general partner determines which costs incurred by ETP and its affiliates are reimbursable by us; and

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any additional contractual arrangements are fair and reasonable to us; and our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.

We are a holding company. We conduct our operations through our subsidiaries and depend on cash flow from our subsidiaries to pay distributions to our unitholders and service our debt obligations.

We are a holding company. We conduct our operations through our subsidiaries. As a result, our cash flow and ability to pay distributions to our unitholders and to service our debt is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory or contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our unitholders or pay interest or principal on our debt securities when due.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.

Our general partner is a wholly owned subsidiary of ETP, and ETP also owns 32.4 percent of our limited partnership interests and all of our IDRs. Our general partner may cause us to borrow funds from affiliates of ETP or from third parties in order to pay cash distributions to our unitholders and to our general partner, including distributions with respect to our general partner’s IDRs.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price, may not receive a return on the investment, and may incur a tax liability upon the sale.

We may issue additional common units without unitholder approval, which would dilute our unitholders’ ownership interests.

We may issue an unlimited number of common units or other limited partner interests, including limited partner interests that rank senior to our common units, without the approval of our unitholders. The issuance of additional common units, or other equity securities of equal or senior rank, will decrease the proportionate ownership interest of existing unitholders and reduce the amount of cash available for distribution to our common unitholders and may adversely affect the market price of our common units.

A unitholder may not have limited liability if a state or federal court finds that we are not in compliance with the applicable statutes or that unitholder action constitutes control of our business.

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 states. A unitholder could be held liable in some circumstances for our obligations to the same extent as a general partner if a state or federal court determined that:

•

we had been conducting business in any state without complying with the applicable limited partnership statute; or

•

the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted participation in the “control” of our business.

Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to our general partner.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

RISKS RELATED TO OUR DEBT

References under this heading to “we,” “us,” and “our” mean Sunoco Logistics Partners Operations L.P. or Sunoco Partners Marketing & Terminals L.P.

We may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs.

Global market and economic conditions have been, and continue to be volatile. The debt and equity capital markets have been impacted by, among other things, significant write-offs in the financial services sector and the re-pricing of credit risk in the broadly syndicated market.

As a result, the cost of raising money in the debt and equity capital markets could be higher and the availability of funds from those markets could be diminished if we seek access to those markets. Accordingly, we cannot be certain that additional funding will be available if needed and to the extent required, on acceptable terms. If additional funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Restrictions in our debt agreements may prevent us from engaging in some beneficial transactions or paying distributions to unitholders.

As of September 30, 2012, our total outstanding indebtedness was $1.63 billion. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facilities and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default, under any of our debt agreements. Our leverage and various limitations in our credit facilities and our senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current debt or any new debt could have similar or greater restrictions.

We could incur a substantial amount of debt in the future, which could prevent us from fulfilling our debt obligations.

We are permitted to incur additional debt, subject to certain limitations under our revolving credit facilities and, in the case of secured debt, under the indenture governing the notes. If we incur additional debt in the future, our increased leverage could, for example:

•

make it more difficult for us to satisfy our obligations under our debt securities or other indebtedness and, if we fail to comply with the requirements of the other indebtedness, could result in an event of default under our debt securities or such other indebtedness;

•

require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow from working capital, capital expenditures and other general corporate activities;

•

limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;

•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

detract from our ability to successfully withstand a downturn in our business or the economy generally; and

•

place us at a competitive disadvantage against less leveraged competitors.

Rising short-term interest rates could increase our financing costs and reduce the amount of cash we generate.

As of September 30, 2012, we had $179 million of floating-rate debt outstanding. Rising short-term rates could materially and adversely affect our results of operations, financial condition or cash flows.

Any reduction in our credit ratings or in ETP’s credit ratings could materially and adversely affect our business, results of operations, financial condition and liquidity.

We currently maintain an investment grade rating by Moody’s, S&P and Fitch Ratings. However, our current ratings may not remain in effect for any given period of time and a rating may be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. If Moody’s, S&P or Fitch Ratings were to downgrade our long-term rating, particularly below investment grade, our borrowing costs could significantly increase, which would adversely affect our financial results, and our potential pool of investors and funding sources could decrease. Further, due to our relationship with ETP, any down-grading in ETP’s credit ratings could also result in a down-grading in our credit ratings. Ratings from credit agencies are not recommendations to buy, sell or hold our securities and each rating should be evaluated independently of any other rating.

TAX RISKS TO OUR COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service (“IRS”) treats us as a corporation or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may impact adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions. Treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or to otherwise subject us to a material level of entity-level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material level of entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

The sale or exchange of 50 percent or more of our capital and profit interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.

The Partnership expects that the acquisition of Sunoco’s interests by ETP will result in the termination of Sunoco Logistics Partners L.P. for federal income tax purposes. Our Partnership will be considered to have terminated for federal tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. In order to determine whether a sale or exchange of 50 percent or more of capital and profits interests has occurred, we review information available to us regarding transactions involving transfers of our units, including units which are actively traded in the public market and transfers of units by our affiliates. Generally, the information that we obtain prior to year end is not sufficient to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50 percent or more of our capital and profits within the prior twelve-month period. However, given the level of partnership interests acquired by ETP, it is likely that a termination of Sunoco Logistics Partners L.P. has occurred for federal income tax purposes.

If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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 will 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 result 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 the unitholder was allocated for a unit, which decreased their tax basis in that 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 ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.

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.

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

Our unitholders will likely 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 will likely 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 do business or own property, even if they do not live in any of those jurisdictions. Our unitholders will likely 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 conduct our business and own assets in approximately 30 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. It is our unitholders’ responsibility to file all United States federal, state and local tax returns.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

None.

Item 5.

Other Information

None.

Item 6.

Exhibits


10.1:		$200,000,000 364-Day Revolving Credit Agreement dated as of August 14, 2012, among Sunoco Partners Marketing & Terminals L.P., as Borrower; Sunoco Logistics Partners Operations L.P. and Sunoco Logistics Partners L.P., as the Guarantors; Citibank, N.A., as Administrative Agent and as a Lender; Barclays Bank PLC, as a Lender; and the other Lenders Party Hereto

10.2:		First Amendment to the $350,000,000 Credit Agreement dated as of August 14, 2012, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; the Undersigned Lenders and Citibank, N.A., as Administrative Agent, as a L/C Issuer and as Swing Line Lender

10.3:		Letter Agreement with Michael J. Hennigan, President and Chief Executive Officer, dated October 4, 2012

10.4:		Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated effective October 24, 2012

12.1:		Statement of Computation of Ratio of Earnings to Fixed Charges

31.1:		Chief Executive Officer Certification of Periodic Report Pursuant to Exchange Act Rule 13a-14(a)

31.2:		Chief Financial Officer Certification of Periodic Report Pursuant to Exchange Act Rule 13a-14(a)

32.1:		Chief Executive Officer Certification of Periodic Report Pursuant to Exchange Act Rule 13a-14(b) and U.S.C. §1350

32.2:		Chief Financial Officer Certification of Periodic Report Pursuant to Exchange Act Rule 13a-14(b) and U.S.C. §1350

101.1:		The following financial statements from Sunoco Logistics Partners L.P.’s Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2012 formatted in XBRL (eXtensible Business Reporting Language): (i) the Condensed Consolidated Statements of Comprehensive Income; (ii) the Condensed Consolidated Balance Sheets; (iii) the Condensed Consolidated Statements of Cash Flows; (iv) the Condensed Consolidated Statements of Equity; and (v) the Notes to Condensed Consolidated Financial Statements.

We are pleased to furnish this Form 10-Q to unitholders who request it by writing to:

Sunoco Logistics Partners L.P.

Investor Relations

1818 Market Street

Suite 1500

Philadelphia, PA 19103

or through our website at www.sunocologistics.com.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


Sunoco Logistics Partners L.P.

By:		/S/ Martin Salinas, Jr.
		Martin Salinas, Jr.
		Chief Financial Officer Sunoco Partners LLC

Date: November 8, 2012