Edgar Filing: Spectra Energy Partners, LP

Form 10-Q for quarterly period ended June 30, 2009

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2009

¨	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 1-33556

SPECTRA ENERGY PARTNERS, LP

(Exact Name of Registrant as Specified in its Charter)


Delaware		41-2232463
(State or other jurisdiction of incorporation)		(IRS Employer Identification No.)

5400 Westheimer Court

Houston, Texas 77056

(Address of principal executive offices, including zip code)

713-627-5400

(Registrant’s telephone number, including area code)

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

There were 58,694,643 Common Units, 21,638,730 Subordinated Units and 1,639,117 General Partner Units outstanding as of July 31, 2009.

SPECTRA ENERGY PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2009

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	4

	Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	5

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008	7

	Condensed Consolidated Statements of Partners’ Capital / Predecessor Equity for the six months ended June 30, 2009 and 2008	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	33

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 4.	Submission of Matters to a Vote of Security Holders	35

Item 6.	Exhibits	36

	Signatures	37

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast, and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•

state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas industries;

•

outcomes of litigation and regulatory investigations, proceedings or inquiries;

•

weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms;

•

the timing and extent of changes in interest rates;

•

general economic conditions, which can affect the long-term demand for natural gas and related services;

•

potential effects arising from terrorist attacks and any consequential or other hostilities;

•

changes in environmental, safety and other laws and regulations;

•

results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general market and economic conditions;

•

increases in the cost of goods and services required to complete capital projects;

•

growth in opportunities, including the timing and success of efforts to develop domestic pipeline, storage, gathering and other infrastructure projects and the effects of competition;

•

the performance of natural gas transmission, storage and gathering facilities;

•

the extent of success in connecting natural gas supplies to transmission and gathering systems and in connecting to expanding gas markets;

•

the effects of accounting pronouncements issued periodically by accounting standard-setting bodies;

•

conditions of the capital markets during the periods covered by the forward-looking statements; and

•

the ability to successfully complete merger, acquisition or divestiture plans; regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Partners, LP has described. Spectra Energy Partners, LP undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In millions, except per-unit amounts)


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009		2008
Operating Revenues
Transportation of natural gas	$	35.3	$	25.8		$	65.7	$	53.0
Storage of natural gas and other		6.0		3.9			11.2		9.2

Total operating revenues		41.3		29.7			76.9		62.2

Operating Expenses
Operating, maintenance and other		11.7		8.4			22.5		18.4
Depreciation and amortization		7.1		6.5			13.8		13.1
Property and other taxes		1.8		1.8			3.9		2.0

Total operating expenses		20.6		16.7			40.2		33.5

Operating Income		20.7		13.0			36.7		28.7

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		17.6		15.0			34.4		27.6
Other income and expenses, net		0.1		0.3			0.1		0.4

Total other income and expenses		17.7		15.3			34.5		28.0

Interest Income		—		0.8			0.1		2.3
Interest Expense		4.6		3.8			8.6		8.8

Earnings Before Income Taxes		33.8		25.3			62.7		50.2
Income Tax Expense (Benefit)		0.2		(2.2	)		0.6		(1.4	)

Net Income	$	33.6	$	27.5		$	62.1	$	51.6

Calculation of Limited Partners’ Interest in Net Income:
Net income	$	33.6	$	27.5		$	62.1	$	51.6
Less:
Net income attributable to predecessor operations		—		—			—		1.6
General partner’s interest in net income		1.2		1.1			2.0		1.5

Limited partners’ interest in net income	$	32.4	$	26.4		$	60.1	$	48.5

Basic and diluted net income per limited partner unit	$	0.44	$	0.38		$	0.83	$	0.71
Weighted-average limited partner units outstanding—basic and diluted		74.1		70.4			72.3		68.3
Distributions paid per limited partner unit	$	0.37	$	0.33		$	0.73	$	0.65

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2009		December 31, 2008
ASSETS

Current Assets
Cash and cash equivalents	$	10.9	$	30.9
Receivables, net		24.5		16.9
Other		8.1		4.5

Total current assets		43.5		52.3

Investments and Other Assets
Investments in unconsolidated affiliates		522.6		573.3
Goodwill		261.9		118.3
Other investments		—		31.6

Total investments and other assets		784.5		723.2

Property, Plant and Equipment
Cost		1,119.9		969.6
Less accumulated depreciation and amortization		165.0		154.4

Net property, plant and equipment		954.9		815.2

Regulatory Assets and Deferred Debits		15.7		10.8

Total Assets	$	1,798.6	$	1,601.5

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)


	June 30, 2009			December 31, 2008
LIABILITIES AND PARTNERS’ CAPITAL

Current Liabilities
Accounts payable	$	7.7		$	12.0
Taxes accrued		3.9			2.4
Interest accrued		0.5			0.8
Note payable—affiliates		28.5			50.0
Other		8.5			10.7

Total current liabilities		49.1			75.9

Long-term Debt		390.0			390.0

Deferred Credits and Other Liabilities
Deferred income taxes		9.4			8.8
Other		10.2			8.4

Total deferred credits and other liabilities		19.6			17.2

Commitments and Contingencies

Partners’ Capital
Common units (58.7 million and 48.9 million units outstanding at June 30, 2009 and December 31, 2008, respectively)		1,010.2			794.5
Subordinated units (21.6 million units outstanding at June 30, 2009 and December 31, 2008, respectively)		307.5			304.7
General partner units (1.6 million and 1.4 million units outstanding at June 30, 2009 and December 31, 2008, respectively)		25.0			21.4
Accumulated other comprehensive loss		(2.8	)		(2.2	)

Total partners’ capital		1,339.9			1,118.4

Total Liabilities and Partners’ Capital	$	1,798.6		$	1,601.5

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)


	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	62.1		$	51.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		13.8			13.1
Deferred income tax expense (benefit)		0.5			(2.1	)
Equity in earnings of unconsolidated affiliates		(34.4	)		(27.6	)
Distributions received from unconsolidated affiliates		36.9			35.8
Other		(13.6	)		3.2

Net cash provided by operating activities		65.3			74.0


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(8.8	)		(18.0	)
Investment expenditures		(21.9	)		(39.3	)
Acquisitions, net of cash acquired		(294.5	)		(4.7	)
Distributions received from unconsolidated affiliates		70.5			—
Purchases of available-for-sale securities		—			(700.4	)
Proceeds from sales and maturities of available-for-sale securities		31.6			760.1

Net cash used in investing activities		(223.1	)		(2.3	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt under credit facilities		1,719.0			702.0
Payments for the redemption of debt under credit facilities		(1,719.0	)		(712.0	)
Proceeds from issuance of units		212.2			—
Proceeds from notes payable—affiliates		72.5			—
Payments on notes payable—affiliates		(94.0	)		—
Distributions to partners		(52.9	)		(45.4	)
Transfers to parent, net		—			(0.8	)

Net cash provided by (used in) financing activities		137.8			(56.2	)


Net increase (decrease) in cash and cash equivalents		(20.0	)		15.5
Cash and cash equivalents at beginning of period		30.9			14.9

Cash and cash equivalents at end of period	$	10.9		$	30.4

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/

PREDECESSOR EQUITY

(Unaudited)

(In millions)


	Predecessor Equity			Partners’ Capital									Accumulated Other Comprehensive Income (Loss)			Total
				Limited Partners						General Partner
				Common			Subordinated			General Partner
December 31, 2008	$	—		$	794.5		$	304.7		$	21.4		$	(2.2	)	$	1,118.4
Net income		—			43.1			18.3			0.7			—			62.1
Unrealized mark-to-market loss on hedges		—			—			—			—			(2.9	)		(2.9	)
Reclassification of cash flow hedges into earnings		—			—			—			—			2.3			2.3
Issuance of units		—			207.8			—			4.4			—			212.2
Attributed deferred tax benefit		—			0.1			0.1			—			—			0.2
Distributions to partners		—			(35.6	)		(15.8	)		(1.5	)		—			(52.9	)
Other, net		—			0.3			0.2			—			—			0.5

June 30, 2009	$	—		$	1,010.2		$	307.5		$	25.0		$	(2.8	)	$	1,339.9


December 31, 2007	$	98.4		$	699.3		$	303.5		$	19.0		$	3.5		$	1,123.7
Net income		1.6			33.2			15.3			1.5			—			51.6
Net change in parent advances		(0.8	)		—			—			—			—			(0.8	)
Acquisition of Saltville and P-25 pipeline		(99.2	)		—			—			—			—			(99.2	)
Excess purchase price over net acquired assets		—			(7.6	)		—			(0.2	)		—			(7.8	)
Issuance of units		—			100.2			—			2.1			—			102.3
Attributed deferred tax expense		—			(0.3	)		—			—			—			(0.3	)
Unrealized mark-to-market gain on hedges		—			—			—			—			0.4			0.4
Reclassification of cash flow hedges into earnings		—			—			—			—			(0.2	)		(0.2	)
Distributions to partners		—			(30.4	)		(14.1	)		(0.9	)		—			(45.4	)

June 30, 2008	$	—		$	794.4		$	304.7		$	21.5		$	3.7		$	1,124.3

See Notes to Condensed Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

The terms “we,” “our,” “us” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.

Nature of Operations. Spectra Energy Partners, LP, through its subsidiaries and equity affiliates are engaged in the transportation and gathering of natural gas through interstate pipeline systems that are located in the southeastern United States, Oklahoma, Arkansas and Missouri, and the storage of natural gas in underground facilities that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership (MLP) formed on March 19, 2007.

Acquisitions. On May 4, 2009, we acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $294.5 million. NOARK’s assets consist of 100% ownership interest of Ozark Gas Transmission, L.L.C. and Ozark Gas Gathering, L.L.C. (collectively, hereafter referred to as “Ozark”). The acquisition of these assets expands our asset base into the Fayetteville Shale and the Arkoma Basin supply regions. See Note 2 for further information on this acquisition.

On April 4, 2008, we completed the acquisition of the equity interests of Saltville Gas Storage Company L.L.C. (Saltville) and the P-25 pipeline from a wholly owned subsidiary of Spectra Energy Corp (Spectra Energy) (collectively, hereafter referred to as the “Saltville acquisition”). The Saltville acquisition represented a transfer of entities under common control. Accordingly, the Condensed Consolidated Financial Statements and related information presented herein have been recast to include the historical results of Saltville and the P-25 pipeline for all periods presented.

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements include our accounts, our majority-owned subsidiaries where we have control and those variable interest entities, if any, where we are the primary beneficiary. The historical data for periods prior to the Saltville acquisition may not necessarily be indicative of the actual results of operations had those entities been operated separately during those periods. Because a direct ownership relationship did not exist among the entities comprising our partnership prior to the Saltville acquisition on April 4, 2008, the net investment in our partnership is shown as Predecessor Equity in the applicable Condensed Consolidated Financial Statements.

We generally account for investments in 20% to 50%-owned affiliates, and investments in less than 20%-owned affiliates where we have the ability to exercise significant influence, under the equity method. Accordingly, the consolidated historical financial statements for our partnership reflect the consolidation of East Tennessee Natural Gas, LLC (East Tennessee), Saltville, and the Ozark assets in which we own 100%, our 50% investment in Market Hub Partners Holding (Market Hub) and our 24.5% investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream) using the equity method of accounting. Intercompany balances and transactions have been eliminated in consolidation.

These interim financial statements should be read in conjunction with the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008 and reflect all normal recurring adjustments that are, in our opinion, necessary to fairly present our results of operations and financial position. Amounts reported in the Condensed Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods.

Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.

Change in Accounting Policy. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Since the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets,” we have performed the annual impairment testing of goodwill using August 31 as the measurement date. Our financial and strategic planning process, including the preparation of long-term cash flow projections, commences in October and typically concludes in January of the following year. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. This planning cycle has created significant constraints in the availability of both information and human resources needed to provide the appropriate projections to be used in the goodwill impairment test using the August 31 test date. Accordingly, effective with our 2009 annual impairment test, we have changed our goodwill impairment test date from August 31 to April 1. We believe that using the April 1 date will alleviate the information and resource constraints that historically existed during the third quarter and will better coincide with the completion of our long-term financial projections. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances and does not result in the delay, acceleration or avoidance of an impairment charge. We have determined that this change in accounting principle does not result in adjustments to our financial statements when applied retrospectively under the requirements of SFAS No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3,” as we did not record any goodwill impairment charges in any of the prior periods presented.

We completed our goodwill impairment test as of April 1, 2009 and no impairments were identified. See Note 8 for further discussion.

2. Acquisitions

NOARK. On May 4, 2009, we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. NOARK’s assets consist of 100% ownership interests in Ozark Gas Transmission, L.L.C., a 565-mile Federal Energy Regulatory Commission (FERC) regulated interstate natural gas transmission system and Ozark Gas Gathering, L.L.C., a 365-mile, fee-based, state regulated natural gas gathering system. The transaction was initially funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was partially refinanced through the issuance of 9.8 million limited partner units and 0.2 million general partner units in the second quarter of 2009. See Note 9 for further discussion related to the debt and Note 13 for a discussion of the sale of common units.

The following pro forma information for the three and six-month periods ended June 30, 2009 and 2008 has been prepared as if the acquisition had occurred on January 1, 2009 and January 1, 2008, respectively.


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions, except per-unit amounts)
Revenues	$	45.9	$	45.7	$	97.5	$	94.5
Net income	$	38.1	$	35.4	$	76.4	$	68.9
Basic and diluted net income per limited partner unit	$	0.46	$	0.43	$	0.94	$	0.86

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of May 4, 2009. Subsequent adjustments may be recorded upon the completion of the valuation, primarily regarding property, plant and equipment fair values, and the final determination of the purchase price allocation.


	Purchase Price Allocation
	(In millions)
Purchase price	$	294.5

Accounts receivable		4.8
Other current assets		0.5
Property, plant and equipment, net		144.9
Regulatory assets and deferred debits		5.3
Current liabilities		(3.2	)
Deferred credits and other liabilities		(1.4	)

Total assets acquired/liabilities assumed	$	150.9

Goodwill	$	143.6

The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The purchase price reflects our plans for increased optimization of the assets through higher utilization and new or expanded services to be provided, as well as increased operating efficiencies that we expect to create as a result of our operational experience associated with our existing assets. All of the goodwill is recorded in the Gas Transportation and Storage segment.

3. Business Segments

Gas Transportation and Storage includes East Tennessee, Saltville and the Ozark assets. This segment provides interstate transportation of natural gas, the storage and redelivery of liquefied natural gas (LNG) and natural gas gathering services for customers in the southeastern United States, Oklahoma, Arkansas and Missouri. These operations are primarily subject to the FERC and the Department of Transportation’s (DOT) rules and regulations.

The remainder of our operations is presented as “Other.” While it is not considered a business segment, Other primarily includes our equity investments in Gulfstream and Market Hub, other investments and certain unallocated corporate costs.

Gulfstream provides interstate natural gas pipeline transportation for customers in central and southern Florida. Gulfstream’s operations are subject to the rules and regulations of the FERC and DOT.

Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan, which are located in southeast Texas and south central Louisiana, respectively. Market Hub’s operations are subject to the rules and regulations of DOT. Moss Bluff is also subject to the rules and regulations of the Texas Railroad Commission. Egan is also subject to the rules and regulations of the FERC.

Management evaluates segment performance based on earnings before interest and taxes from continuing operations (EBIT). On a segment basis, EBIT represents all profits from continuing operations (both operating and non-operating) before deducting interest and income taxes.

Business Segment Data


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Operating revenues
Gas Transportation and Storage	$	41.3	$	29.7	$	76.9	$	62.2
Other		—		—		—		—

Total operating revenues	$	41.3	$	29.7	$	76.9	$	62.2

Segment EBIT
Gas Transportation and Storage	$	23.8	$	15.2	$	43.7	$	32.8
Other		14.6		13.1		27.5		23.9

Total EBIT		38.4		28.3		71.2		56.7
Interest income		—		0.8		0.1		2.3
Interest expense		4.6		3.8		8.6		8.8

Earnings before income taxes	$	33.8	$	25.3	$	62.7	$	50.2


	June 30, 2009		December 31, 2008
	(In millions)
Segment Assets
Gas Transportation and Storage	$	1,273.3	$	977.7
Other		525.3		623.8

Total Assets	$	1,798.6	$	1,601.5

4. Income Taxes

As a result of our MLP structure, we are not subject to federal income taxes, but are still subject to Tennessee state income tax. Market Hub and Gulfstream are not subject to federal income tax, but rather the taxable income or loss of these entities is reported on the income tax returns of the respective members. Market Hub is subject to Texas income (margin) tax under a tax sharing agreement with Spectra Energy.

5. Comprehensive Income

Components of comprehensive income are as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009			2008
	(In millions)
Net income	$	33.6	$	27.5		$	62.1		$	51.6
Unrealized mark-to-market gain (loss) on hedges		0.3		0.4			(2.9	)		0.4
Reclassification of cash flow hedges into earnings		1.2		(0.1	)		2.3			(0.2	)

Total comprehensive income	$	35.1	$	27.8		$	61.5		$	51.8

6. Net Income Per Limited Partner Unit and Cash Distributions

We calculate net income per limited partner unit in accordance with Emerging Issues Task Force (EITF) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.” EITF 07-4 establishes, among other things, that the calculation of earnings per limited partner unit

should not reflect an allocation of undistributed earnings to the incentive distribution right (IDR) holders beyond amounts distributable to IDR holders under the terms of the partnership agreement. Under the “two class” method of computing earnings per share previously described by SFAS No. 128, “Earnings Per Share,” we calculated earnings per limited partner unit as if all the earnings for the period had been distributed, which resulted in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeded the actual incentive distribution. Following the adoption of the guidance in EITF 07-4, we no longer calculate assumed incentive distributions. We adopted EITF 07-4 in January 2009, and have retrospectively applied it to all periods presented. The retrospective application of EITF 07-4 did not result in a material change in earnings per limited partner unit for the three and six months ended June 30, 2008.

The following table presents our net income per limited partner unit calculations.


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions, except per-unit amounts)
Net income	$	33.6	$	27.5	$	62.1	$	51.6
Less:
Net income attributable to predecessor operations		—		—		—		1.6
General partner’s interest in net income—2%		0.7		0.6		1.2		1.0
General partner’s interest in net income attributable to incentive distribution rights		0.5		0.5		0.8		0.5

Limited partners’ interest in net income	$	32.4	$	26.4	$	60.1	$	48.5

Weighted-average limited partner units outstanding—basic and diluted		74.1		70.4		72.3		68.3
Net income per limited partner unit—basic and diluted	$	0.44	$	0.38	$	0.83	$	0.71

The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.

Available Cash. Available Cash, for any quarter, consists of all cash on hand at the end of that quarter:

•

less the amount of cash reserves established by the general partner to:

•

provide for the proper conduct of business,

•

comply with applicable law, any debt instrument or other agreement, or

•

provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters,

•

plus, if the general partner so determines, all or a portion of cash on hand on the date of determination of Available Cash for the quarter.

Subordinated Units. All of the subordinated units are held by wholly owned subsidiaries of Spectra Energy. The partnership agreement provides that, during the subordination period, the common unitholders have the right to receive distributions of Available Cash each quarter in an amount equal to $0.30 per common unit (the Minimum Quarterly Distribution), plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. It is currently estimated that the subordination period will not end during 2009.

Incentive Distribution Rights. The general partner holds incentive distribution rights in accordance with the partnership agreement as follows:


	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Per-Unit Amount	Common and Subordinated Unitholders		General Partner
Minimum Quarterly Distribution	$0.30	98	%	2	%
First Target Distribution	up to $0.345	98	%	2	%
Second Target Distribution	above $0.345 up to $0.375	85	%	15	%
Third Target Distribution	above $0.375 up to $0.45	75	%	25	%
Thereafter	above $0.45	50	%	50	%

To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common and subordinated units.

7. Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consist of a 24.5% interest in Gulfstream and a 50% interest in Market Hub.

For the six months ended June 30, 2009, we received distributions of $89.8 million from Gulfstream. Of these distributions, $19.3 million were included in Cash Flows from Operating Activities—Distributions Received From Unconsolidated Affiliates and $70.5 million were included in Cash Flows from Investing Activities—Distributions Received From Unconsolidated Affiliates on the Condensed Consolidated Statements of Cash Flows. For the six months ended June 30, 2008, we received distributions of $14.3 million, which were included in Cash Flows from Operating Activities—Distributions Received From Unconsolidated Affiliates on the Condensed Consolidated Statements of Cash Flows.

On May 27, 2009, Gulfstream issued $300.0 million aggregate principal amount of 6.95% Senior Notes due 2016. The proceeds, net of transaction costs, of $296.6 million were distributed to the partners based upon their ownership percentages, which resulted in the distribution of $72.7 million of which $70.5 million was included in Cash Flows from Investing Activities—Distributions Received From Unconsolidated Affiliates on the Condensed Consolidated Statements of Cash Flows.

We received distributions from Market Hub of $17.6 million in the six months ended June 30, 2009 and $21.5 million during the same period in 2008, which were included in Cash Flows from Operating Activities—Distributions Received From Unconsolidated Affiliates on the Condensed Consolidated Statements of Cash Flows.

Investments in Unconsolidated Affiliates


	June 30, 2009		December 31, 2008
	(In millions)
Gulfstream	$	184.2	$	253.3
Market Hub		338.4		320.0

Total	$	522.6	$	573.3

Equity in Earnings of Unconsolidated Affiliates


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Gulfstream	$	6.8	$	7.0	$	13.7	$	11.8
Market Hub		10.8		8.0		20.7		15.8

Total	$	17.6	$	15.0	$	34.4	$	27.6

Summarized Financial Information of Unconsolidated Affiliates (Presented at 100%)


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Gulfstream
Operating revenues	$	60.9	$	51.6	$	117.1	$	92.4
Operating expenses		19.1		15.8		35.2		29.7
Operating income		41.8		35.8		81.9		62.7
Net income		27.9		27.3		55.9		46.2

Market Hub
Operating revenues	$	29.9	$	25.2	$	57.8	$	47.1
Operating expenses		8.4		8.8		16.3		15.6
Operating income		21.5		16.4		41.5		31.5
Net income		21.6		16.8		41.5		32.5

8. Goodwill

We completed our annual goodwill impairment test as of April 1, 2009 and no impairments were identified. We primarily use a discounted cash flow analysis to determine fair value for each reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.

The long-term growth rates used for our reporting units reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas and, notwithstanding the current economic downturn, increasing demand for capacity on our pipeline systems. However, even if we assumed a zero growth rate for any reporting unit, there would be no impairment of goodwill.

We continue to monitor the effects of the economic downturn that global economies are currently facing on the long-term cost of capital utilized to calculate our reporting unit fair values. However, a 1% increase in the weighted-average cost of capital assumption for any of our reporting units would not result in an impairment of goodwill.

All of our goodwill is in our Gas Transportation and Storage segment. Changes in the balance of goodwill since December 31, 2008 follow (in millions):


Balance at December 31, 2008	$	118.3
Increase due to the acquisition of NOARK (a)		143.6

Balance at June 30, 2009	$	261.9

(a)

See Note 2 for further discussion.

9. Debt and Credit Facility


				Outstanding as of June 30, 2009
Credit Facility Summary	Expiration Date	Credit Facility Capacity		Revolving Loan		Total
	(In millions)
Spectra Energy Partners, LP	2012	$	500.0	$	240.0	$	240.0

We had no outstanding term loan balance and no investments in marketable securities pledged as collateral at June 30, 2009 and $31.6 million of investments pledged at December 31, 2008. These investments are classified as Investments and Other Assets—Other Investments on the Condensed Consolidated Balance Sheet.

The credit facility prohibits us from making distributions of Available Cash to unitholders if any default or event of default, as defined, exists. In addition, the credit facility contains covenants, among others, limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests, and is also subject to certain financial covenants. These financial covenants include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less. The terms of the credit agreement also require us to maintain a ratio of Adjusted EBITDA, as defined in the credit agreement, to interest expense of 2.5 or greater. As of June 30, 2009, we were in compliance with those covenants. The credit facility does not contain material adverse change clauses.

On May 4, 2009, as part of the NOARK acquisition, we borrowed $70.0 million under a credit facility with a subsidiary of Spectra Energy. These borrowings carried interest at an annual rate of 9.75%. We repaid the $70.0 million on May 27, 2009 with the proceeds of our sale of common units. See Note 13 for further discussion on the sale of common units.

Long-term debt includes East Tennessee’s 5.71% unsecured notes payable totaling $150.0 million as of June 30, 2009 and December 31, 2008. East Tennessee’s debt agreement contains financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital. Failure to maintain the covenants could require East Tennessee to immediately pay down the outstanding balance. As of June 30, 2009, East Tennessee was in compliance with those covenants. In addition, the debt agreement allows for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries, if any. The debt agreement does not contain material adverse change clauses.

In the second quarter of 2009, we repaid $21.5 million of the $50.0 million demand note payable with Market Hub.

10. Fair Value Measurements

The following table presents, for each of the fair value hierarchy levels, our assets and liabilities that are measured at fair value on a recurring basis:


		June 30, 2009
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(In millions)
Interest rate swap liabilities	Current liabilities—other	$	0.7	$	—	$	0.7	$	—
Interest rate swap liabilities	Deferred credits and other liabilities—other		5.5		—		5.5		—

Total Liabilities		$	6.2	$	—	$	6.2	$	—


		December 31, 2008
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(In millions)
Corporate debt securities	Other investments	$	24.7	$	—	$	24.7	$	—
Money market funds	Other investments		6.9		6.9		—		—

Total Assets		$	31.6	$	6.9	$	24.7	$	—

Interest rate swap liabilities	Deferred credits and other liabilities—other	$	5.6	$	—	$	5.6	$	—

Total Liabilities		$	5.6	$	—	$	5.6	$	—

Level 2 Valuation Techniques. Fair values of our financial instruments, primarily corporate debt securities that are actively traded in the secondary market, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.

Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of June 30, 2009 and December 31, 2008, are not necessarily indicative of the amounts we could have realized in current markets.


	June 30, 2009				December 31, 2008
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(In millions)
Long-term debt	$	390.0	$	394.9	$	390.0	$	381.9
Long-term SFAS No. 115 securities		—		—		31.6		31.6

The fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable—affiliates are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.

During 2009, there were no adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

11. Commitments and Contingencies

Environmental. We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We believe there are no matters outstanding that will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Litigation. We are involved in legal, tax and regulatory proceedings in various forums, including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

Interest Rate (Cash Flow) Hedges. Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt. We manage our interest rate exposure by limiting our variable-rate exposures and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure.

Derivative Portfolio Carrying Value as of June 30, 2009


Description	Maturity in 2009		Maturity in 2010		Maturity in 2011		Maturity in 2012 and Thereafter		Total Carrying Value
	(In millions)
Interest rate swap liabilities	$	—	$	0.7	$	5.4	$	0.1	$	6.2

The amounts in the table above represent the liabilities for unrealized gains and losses on mark-to-market and hedging transactions on our Condensed Consolidated Balance Sheets and do not include derivative positions of our equity investments.

In June 2008, we entered into a series of two and three-year interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates on $140 million of loans outstanding under the revolving credit facility. In February 2009, we entered into a series of three-year interest rate swap agreements with third parties to mitigate our exposure to variable interest rates on $40 million of loans outstanding under the revolving credit facility. As of June 30, 2009, the total notional amount of our interest rate swaps was $180.0 million. These interest rate swaps were designated as effective cash flow hedges. Through June 30, 2009, these hedges resulted in no ineffectiveness, and unrealized net losses on the agreements have been deferred in Accumulated Other Comprehensive Income (Loss) (AOCI) in the Condensed Consolidated Balance Sheets. It is estimated that $4.6 million of pretax losses reported in AOCI at June 30, 2009 will be reclassified into earnings during the next 12 months.

The following table represents the effective portion of unrealized gains and losses recorded in AOCI on the Condensed Consolidated Statement of Partners’ Capital:


Derivatives under SFAS No. 133 Cash Flow Hedging Relationships	Six Months Ended June 30,
	2009			2008
	(In millions)
Interest rate swaps	$	(2.9	)	$	0.4

The following table represents the effective portion of realized losses (gains), net of tax, that have been reclassified from AOCI and recognized in Interest Expense in the Condensed Consolidated Statements of Operations:


Loss (Gain) reclassified from AOCI into Income	Condensed Consolidated Statements of Operations Caption	Three Months Ended June 30,					Six Months Ended June 30,
		2009		2008			2009		2008
		(In millions)					(In millions)
Interest rate swaps	Interest expense	$	1.2	$	(0.1	)	$	2.3	$	(0.2	)

The following table represents the location and fair value of our derivative instruments in the Condensed Consolidated Balance Sheets.

Liability Derivatives


Derivatives designated as hedging instruments under SFAS No. 133	Condensed Consolidated Balance Sheets Caption	June 30, 2009		December 31, 2008
		(In millions)
Interest rate swaps	Current liabilities—other	$	0.7	$	—
Interest rate swaps	Deferred credits and other liabilities—other	$	5.5	$	5.6

Credit Risk. Our principal customers for natural gas transportation, storage and gathering services are local distribution companies, utilities, industrial end-users, marketers, and exploration and production companies, located primarily throughout the southern and southeastern United States. We have concentrations of receivables

from these industry sectors throughout these regions. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain cash, letters of credit or other acceptable forms of security from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

13. Sale of Common Units

In the second quarter of 2009, we issued approximately 9.8 million limited partner units and 0.2 million general partner units and received net proceeds of $212.2 million. As further discussed in Note 2 and Note 9, we used the net proceeds from the offering to repay $142.2 million drawn on our available bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy.

14. New Accounting Pronouncements

The following new accounting pronouncements were adopted during the six months ended June 30, 2009:

SFAS No. 157, “Fair Value Measurements.” In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of SFAS No. 157 for our goodwill impairment test did not have any impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of SFAS No. 141R effective January 1, 2009.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.” In March 2008, the FASB issued SFAS No. 161, which expands the disclosure requirements for SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” with the intent to provide users of financial statements an enhanced understanding of how and why derivative instruments are used, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of SFAS No. 161 effective January 1, 2009 as required. See Note 12 for the disclosures required by SFAS No. 161.

EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.” In March 2008, the FASB ratified a consensus reached by the EITF that addresses the application of the two-class method for MLPs when IDRs are present and entitle the IDR holder to a portion of distributions. The final consensus states that when earnings exceed distributions, the computation of earnings per unit (EPU) should be based on the terms of the partnership agreement. Accordingly, any contractual limitations on the

distributions to IDR holders (e.g., limitations that only entitle IDR holders to “available cash”) would need to be determined for each reporting period. The adoption of EITF 07-4 as of January 1, 2009 did not have a material impact on our computation of the net income per limited partner unit.

FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” In April 2008, the FASB issued FSP No. FAS 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of the provisions of FSP No. FAS 142-3 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 165, “Subsequent Events.” In May 2009, the FASB issued SFAS No. 165, which, absent related provisions contained in existing authoritative guidance, establishes general standards for the accounting for and disclosure of events that occur subsequent to the balance sheet date but before the financial statements of an entity are issued or are available to be issued. The adoption of the provisions of SFAS No. 165 by us effective June 30, 2009 did not have any impact on our consolidated results of operations, financial position or cash flows.

15. Subsequent Events

We have evaluated significant events and transactions that occurred from July 1, 2009 through the date of this report and have determined that there were no events or transactions other than those disclosed in this report, if any, that would require recognition or disclosure in our Condensed Consolidated Financial Statements for the quarterly period ended June 30, 2009.

Item 2.

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

INTRODUCTION

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Condensed Consolidated Financial Statements.

Executive Overview

For the three months ended June 30, 2009 and 2008, we reported net income of $33.6 million and $27.5 million, respectively. For the six months ended June 30, 2009 and 2008, we reported net income of $62.1 million and $51.6 million, respectively. The increases resulted from higher revenues due to the acquisition of the Ozark assets and the Greenway Nora and Glade Springs expansion projects at East Tennessee, as well as increased equity earnings from Market Hub largely due to increased revenues from expansion projects. These increases were partially offset by costs associated with the acquisition of NOARK.

We continue to deliver on our primary business objective of increasing cash distributions per limited partner unit. A cash distribution of $0.38 per limited partner unit was declared in July 2009, representing a 2.7% increase over the previous distribution of $0.37 per limited partner unit and the seventh consecutive quarterly increase. This cash distribution represents an 11.8% increase over the distribution of $0.34 per limited partner unit declared in July 2008.

During the second quarter of 2009, Gulfstream phased in additional contracts related to its recent expansion projects with new firm revenues contributing to the available cash to support our cash distributions.

Consistent with our strategy to pursue acquisitions, on May 4, 2009, we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. NOARK’s assets consist of 100% ownership interest in Ozark Gas Transmission, a 565-mile FERC-regulated interstate natural gas transmission system and Ozark Gas Gathering, a 365-mile, fee-based, state regulated natural gas gathering system. See Note 2 in the Notes to the Condensed Consolidated Financial Statements for further discussion.

RESULTS OF OPERATIONS


	Three Months Ended June 30,								Six Months Ended June 30,
	2009		2008			Increase (Decrease)			2009		2008			Increase (Decrease)
	(In millions)
Operating revenues	$	41.3	$	29.7		$	11.6		$	76.9	$	62.2		$	14.7
Operating, maintenance and other expense		13.5		10.2			3.3			26.4		20.4			6.0
Depreciation and amortization		7.1		6.5			0.6			13.8		13.1			0.7

Operating income		20.7		13.0			7.7			36.7		28.7			8.0
Equity in earnings of unconsolidated affiliates		17.6		15.0			2.6			34.4		27.6			6.8
Other income and expenses, net		0.1		0.3			(0.2	)		0.1		0.4			(0.3	)
Interest income		—		0.8			(0.8	)		0.1		2.3			(2.2	)
Interest expense		4.6		3.8			0.8			8.6		8.8			(0.2	)

Earnings before income taxes		33.8		25.3			8.5			62.7		50.2			12.5
Income tax expense (benefit)		0.2		(2.2	)		2.4			0.6		(1.4	)		2.0

Net income	$	33.6	$	27.5		$	6.1		$	62.1	$	51.6		$	10.5

Adjusted EBITDA (a)	$	27.8	$	19.5		$	8.3		$	50.5	$	41.8		$	8.7
Cash Available for Distribution (a)	$	33.5	$	20.8		$	12.7		$	78.9	$	57.5		$	21.4

(a)	See “Reconciliation of Non-GAAP Measures” for a reconciliation of this measure to the most directly comparable financial measures calculated and presented in accordance with GAAP.

Three Months Ended June 30, 2009 compared to same period in 2008

Operating Revenues. The $11.6 million increase was driven primarily by $9.3 million from the acquisition of the Ozark assets and $2.3 million from East Tennessee’s Greenway Nora and Glade Springs expansion projects.

Operating, Maintenance and Other Expense. The $3.3 million increase was driven primarily by:

•

a $3.9 million increase from the acquisition of NOARK, including approximately $1.7 million of transaction costs and

•

a $0.6 million increase related to the 2008 capitalization of previously expensed project development costs, partially offset by

•

a $0.7 million decrease related to 2008 expenses associated with the Saltville acquisition and

•

a $0.3 million decrease related to lower property tax rates in 2009.

Equity in Earnings of Unconsolidated Affiliates. The $2.6 million increase includes a $2.8 million increase in equity earnings from Market Hub, partially offset by a $0.2 million decrease in equity earnings from Gulfstream.

The following discussion explains the factors affecting the equity earnings of Gulfstream and Market Hub, each representing 100% of the earnings drivers of those entities.


	Three Months Ended June 30,
	2009		2008		Increase (Decrease)
	(In millions)
Gulfstream
Operating revenues	$	60.9	$	51.6	$	9.3
Operating, maintenance and other expense		10.5		8.5		2.0
Depreciation and amortization		8.6		7.3		1.3
Other income and expenses, net		0.2		2.7		(2.5	)
Interest expense		14.1		11.2		2.9

Net income	$	27.9	$	27.3	$	0.6

Spectra Energy Partners’ share	$	6.8	$	7.0	$	(0.2	)

Gulfstream—Owned 24.5%

Gulfstream’s net income increased $0.6 million to $27.9 million for the three-month period in 2009 compared to $27.3 million for the same period in 2008. The increase was driven primarily by:

•

a $9.3 million increase in revenues due primarily from the Phase III and Phase IV expansions placed in service in the third quarter of 2008, partially offset by

•

a $2.0 million increase in operating, maintenance and other expense due primarily to a $1.0 million in higher ad valorem tax expense resulting from Phase III and Phase IV expansion projects and $0.8 million in compressor overhaul expenses,

•

a $1.3 million increase in depreciation expense primarily due to the Phase III and Phase IV expansion projects,

•

a $2.5 million decrease in other income and expenses, primarily driven by a $2.0 million decrease in the equity portion of allowance for funds used during construction (AFUDC) due to higher capital expenditures in 2008 for the Phase III and Phase IV expansion projects, and a $0.3 million decrease in interest income due to lower rates, and

•

a $2.9 million increase in interest expense resulting from the May 2009 $300 million debt offering and lower interest costs capitalized due to higher 2008 capital expenditures for the Phase III and Phase IV expansion projects.


	Three Months Ended June 30,
	2009		2008		Increase (Decrease)
	(In millions)
Market Hub
Operating revenues	$	29.9	$	25.2	$	4.7
Operating, maintenance and other expense		5.6		6.2		(0.6	)
Depreciation and amortization		2.8		2.6		0.2
Interest income		0.1		0.7		(0.6	)
Interest expense		—		0.3		(0.3	)
Income tax expense		—		—		—

Net income	$	21.6	$	16.8	$	4.8

Spectra Energy Partners’ share	$	10.8	$	8.0	$	2.8

Market Hub—Owned 50%

Market Hub’s net income increased $4.8 million to $21.6 million for the three-month period in 2009 compared to $16.8 million for the same period in 2008. The increase was driven primarily by:

•

a $4.7 million increase in revenues including $3.4 million in firm storage revenues due to the phase in of the Egan storage facilities expansion beginning in 2009 and an additional $1.4 million in interruptible service revenues driven by market demand,

•

a $0.6 million decrease in operating, maintenance and other expense due primarily to lower maintenance costs and increased net fuel recovery and

•

a $0.3 million decrease in interest expense due to lower interest rates associated with collateral held from counterparties and affiliates and partial repayment to affiliates, partially offset by

•

a $0.2 million increase in depreciation expense primarily due to expansion activity, and

•

a $0.6 million decrease in interest income due to lower interest rates and repayments on notes receivable from affiliates.

Interest Income. The $0.8 million decrease was due to the sale of all remaining marketable securities held by us that were originally purchased with a portion of the Initial Public Offering (IPO) proceeds in July 2007. These securities were pledged as collateral to secure the term loan portion of our credit facility. As of June 30, 2009, there were no outstanding balances under the term loan and therefore no remaining marketable securities.

Interest Expense. The $0.8 million increase was primarily due to interest paid on borrowings associated with the acquisition of NOARK.

Income Tax Expense (Benefit). Our income tax expense for the three months ended June 30, 2009 was $0.2 million compared to an income tax benefit of $2.2 million in the same period in 2008 due to a change in tax status of certain businesses related to the Saltville acquisition.

Six Months Ended June 30, 2009 compared to same period in 2008

Operating Revenues. The $14.7 million increase was driven primarily by $9.3 million from the acquisition of the Ozark assets and $4.9 million from East Tennessee’s Greenway Nora and Glade Springs expansion projects.

Operating, Maintenance and Other Expense. The $6.0 million increase was driven primarily by:

•

a $4.9 million increase from the acquisition of NOARK, including approximately $2.7 million of transaction costs,

•

a $1.2 million increase from a favorable ad valorem tax adjustment recorded in 2008 and

•

a $0.6 million increase primarily related to the 2008 capitalization of previously expensed project development costs, partially offset by

•

a $1.2 million decrease primarily related to an increase in net fuel recoveries.

Equity in Earnings of Unconsolidated Affiliates. The $6.8 million increase includes a $4.9 million increase in equity earnings from Market Hub and a $1.9 million increase in equity earnings from Gulfstream.

The following discussion explains the factors affecting the equity earnings of Gulfstream and Market Hub, each representing 100% of the earnings drivers of those entities.


	Six Months Ended June 30,
	2009		2008		Increase (Decrease)
	(In millions)
Gulfstream
Operating revenues	$	117.1	$	92.4	$	24.7
Operating, maintenance and other expense		18.1		15.0		3.1
Depreciation and amortization		17.1		14.7		2.4
Other income and expenses, net		0.3		6.2		(5.9	)
Interest expense		26.3		22.7		3.6

Net income	$	55.9	$	46.2	$	9.7

Spectra Energy Partners’ share	$	13.7	$	11.8	$	1.9

Gulfstream—Owned 24.5%

Gulfstream’s net income increased $9.7 million to $55.9 million for the six-month period in 2009 compared to $46.2 million for the same period in 2008. The increase was driven primarily by:

•

a $24.7 million increase in revenues primarily from the Phase III and Phase IV expansions placed in service in the third quarter of 2008, partially offset by

•

a $3.1 million increase in operating, maintenance and other expense due to $2.1 million in higher ad valorem tax expense resulting from Phase III and Phase IV expansion projects and $1.0 million due to a compressor overhaul,

•

a $2.4 million increase in depreciation expense primarily due to the Phase III and Phase IV expansion projects,

•

a $5.9 million decrease in other income and expenses, primarily driven by a $3.3 million decrease in the equity portion of AFUDC due to higher capital expenditures in 2008 for the Phase III and Phase IV expansion projects, a $0.9 million favorable resolution of a sales and use tax matter in 2008, and a $0.9 million decrease in interest income due to lower rates on cash investments, and

•

a $3.6 million increase in interest expense resulting from the May 2009 $300 million debt offering and lower interest costs capitalized due to higher 2008 capital expenditures for the Phase III and Phase IV expansion projects.


	Six Months Ended June 30,
	2009		2008		Increase (Decrease)
	(In millions)
Market Hub
Operating revenues	$	57.8	$	47.1	$	10.7
Operating, maintenance and other expense		10.7		10.4		0.3
Depreciation and amortization		5.6		5.2		0.4
Interest income		0.2		1.7		(1.5	)
Interest expense		0.1		0.7		(0.6	)
Income tax expense		0.1		—		0.1

Net income	$	41.5	$	32.5	$	9.0

Spectra Energy Partners’ share	$	20.7	$	15.8	$	4.9

Market Hub—Owned 50%

Market Hub’s net income increased $9.0 million to $41.5 million for the six-month period in 2009 compared to $32.5 million for the same period in 2008. The increase was driven primarily by:

•

a $10.7 million increase in revenues including $7.5 million in firm storage revenues due to the phase in of the Egan storage facilities expansion beginning in 2009 and the phase in of the Egan Cavern 4 expansion in 2008 and an additional $3.2 million in interruptible service revenues driven by market demand, and

•

a $0.6 million decrease in interest expense due to lower interest rates associated with collateral held from counterparties and affiliates and partial repayment to affiliates, partially offset by

•

a $0.3 million increase in operating, maintenance and other expense due primarily to increased ad valorem taxes due to expansions and a favorable adjustment in 2008, higher benefit costs compared to 2008 and increased information technology costs, partially offset by increased capitalized overhead costs associated with expansion at Moss Bluff Cavern 4 and Egan Cavern 3 and an increase in net fuel recoveries,

•

a $0.4 million increase in depreciation expense primarily due to expansion activity, and

•

a $1.5 million decrease in interest income primarily due to lower interest rates and repayments on notes receivable from affiliates.

Interest Income. The $2.2 million decrease was due to the sale of marketable securities held by us that were originally purchased with a portion of the IPO proceeds in July 2007.

Interest Expense. The $0.2 million decrease was due to lower interest rates on term and revolver borrowings, partially offset by interest on borrowings associated with the acquisition of NOARK.

Income Tax Expense (Benefit). Our income tax expense for the six months ended June 30, 2009 was $0.6 million compared to an income tax benefit of $1.4 million in the same period in 2008 due to a change in tax status of certain businesses related to the Saltville acquisition.

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA

We define our Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) as Net Income plus Interest Expense, Income Taxes and Depreciation and Amortization less our Equity in Earnings of Gulfstream and Market Hub, Interest Income, and Other Income and Expenses, Net, which primarily consists of non-cash AFUDC. Our Adjusted EBITDA is not a presentation made in accordance with GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements to assess:

•

the financial performance of assets without regard to financing methods, capital structure or historical cost basis;

•

the ability to generate cash sufficient to pay interest on indebtedness and to make distributions to partners; and

•

operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to financing methods and capital structure.

Significant drivers of variances in Adjusted EBITDA between the periods presented are substantially the same as those previously discussed under Results of Operations.

Cash Available for Distribution

We define our Cash Available for Distribution as our Adjusted EBITDA plus Cash Available for Distribution from Gulfstream and Market Hub and net preliminary project costs, less net cash paid for interest expense, net cash paid for income tax expense, and maintenance capital expenditures. Cash Available for Distribution does not reflect changes in working capital balances. Gulfstream and Market Hub define Cash Available for Distribution on a consistent basis with us.

Effective January 1, 2009, we have revised the calculation of Cash Available for Distribution, within the definition contained in the partnership agreement. For our regulated entities that apply SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we expense preliminary project costs until such time that management determines that recovery of these costs is probable. At that time, we capitalize those costs, which reduces operating expenses in that period. The revised calculation for Cash Available for Distribution adds back preliminary project costs to EBITDA as those costs are initially incurred and deducts the expense reductions in the period the costs are capitalized. These project costs do not represent operating cash flow activity.

Information presented below for 2008 has been revised to reflect the new definition as follows:

Spectra Energy Partners


	Three Months Ended June 30, 2008			Six Months Ended June 30, 2008
	(In millions)
Cash Available for Distribution, as previously reported	$	21.8		$	58.3
Add:
Change in Cash Available for Distribution from Gulfstream (see below)		0.1			0.1
Preliminary project costs, net		(0.6	)		—
Less:
Cash paid for income tax expense, net		0.5			0.9

Cash Available for Distribution, as revised	$	20.8		$	57.5

Gulfstream


	Three Months Ended June 30, 2008		Six Months Ended June 30, 2008
	(In millions)
Cash Available for Distribution, as previously reported	$	18.1	$	52.0
Add:
Preliminary project costs, net		0.2		0.4

Cash Available for Distribution, as revised—100%	$	18.3	$	52.4

Cash Available for Distribution, as revised—24.5%	$	4.5	$	12.8

Cash Available for Distribution should not be viewed as indicative of the actual amount of cash available for distribution or that we plan to distribute for a given period.

Cash Available for Distribution should not be considered an alternative to Net Income, Operating Income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Cash Available for Distribution excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Cash Available for Distribution as presented may not be comparable to similarly titled measures of other companies.

Significant drivers of variances in Cash Available for Distribution between the periods presented are substantially the same as those previously discussed under Results of Operations. Other drivers include the timing of certain cash outflows, such as capital expenditures for maintenance and the scheduled payments of interest.

Spectra Energy Partners

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009		2008
	(In millions)
Net income	$	33.6		$	27.5		$	62.1	$	51.6
Add:
Interest expense		4.6			3.8			8.6		8.8
Income tax expense (benefit)		0.2			(2.2	)		0.6		(1.4	)
Depreciation and amortization		7.1			6.5			13.8		13.1
Less:
Equity in earnings of Gulfstream		6.8			7.0			13.7		11.8
Equity in earnings of Market Hub		10.8			8.0			20.7		15.8
Interest income		—			0.8			0.1		2.3
Other income and expenses, net		0.1			0.3			0.1		0.4

Adjusted EBITDA		27.8			19.5			50.5		41.8
Add:
Cash Available for Distribution from Gulfstream		6.3			4.5			18.2		12.8
Cash Available for Distribution from Market Hub		10.4			9.4			21.3		18.1
Preliminary project costs, net		—			(0.6	)		0.4		—
Less:
Cash paid for interest expense, net		5.5			5.5			6.3		7.2
Cash paid (received) for income tax expense, net		(0.3	)		0.5			0.1		0.9
Maintenance capital expenditures		5.8			6.0			5.1		7.1

Cash Available for Distribution	$	33.5		$	20.8		$	78.9	$	57.5

Spectra Energy Partners

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”


	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In millions)
Net cash provided by operating activities	$	36.2		$	36.0		$	65.3		$	74.0
Interest income		—			(0.8	)		(0.1	)		(2.3	)
Interest expense		4.6			3.8			8.6			8.8
Income tax expense—current		—			0.1			0.1			0.7
Distributions received from Gulfstream and Market Hub		(20.2	)		(15.2	)		(36.9	)		(35.8	)
Changes in operating working capital and other		7.2			(4.4	)		13.5			(3.6	)

Adjusted EBITDA		27.8			19.5			50.5			41.8
Add:
Cash Available for Distribution from Gulfstream		6.3			4.5			18.2			12.8
Cash Available for Distribution from Market Hub		10.4			9.4			21.3			18.1
Preliminary project costs, net		—			(0.6	)		0.4			—
Less:
Cash paid for interest expense, net		5.5			5.5			6.3			7.2
Cash paid (received) for income tax expense, net		(0.3	)		0.5			0.1			0.9
Maintenance capital expenditures		5.8			6.0			5.1			7.1

Cash Available for Distribution	$	33.5		$	20.8		$	78.9		$	57.5

Gulfstream

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Net income	$	27.9	$	27.3	$	55.9	$	46.2
Add:
Interest expense		14.1		11.2		26.3		22.7
Depreciation and amortization		8.6		7.3		17.1		14.7
Less:
Other income and expenses, net		0.2		2.7		0.3		6.2

Adjusted EBITDA—100%		50.4		43.1		99.0		77.4
Add:
Preliminary project costs, net		0.2		0.2		0.3		0.4
Less:
Cash paid for interest expense, net		24.7		24.7		24.7		24.7
Maintenance capital expenditures		0.3		0.3		0.5		0.7

Cash Available for Distribution—100%	$	25.6	$	18.3	$	74.1	$	52.4

Adjusted EBITDA—24.5%	$	12.4	$	10.6	$	24.3	$	19.0
Cash Available for Distribution—24.5%	$	6.3	$	4.5	$	18.2	$	12.8

Market Hub

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Net income	$	21.6	$	16.8	$	41.5	$	32.5
Add:
Interest expense		—		0.3		0.1		0.7
Income tax expense		—		—		0.1		—
Depreciation and amortization		2.8		2.6		5.6		5.2
Less:
Interest income		0.1		0.7		0.2		1.7
Other income and expenses, net		—		—		—		—

Adjusted EBITDA—100%		24.3		19.0		47.1		36.7
Less:
Cash paid for interest expense, net		3.5		—		3.5		—
Cash paid for income tax expense, net		—		—		—		—
Maintenance capital expenditures		0.1		0.2		1.1		0.5

Cash Available for Distribution—100%	$	20.7	$	18.8	$	42.5	$	36.2

Adjusted EBITDA—50%	$	12.2	$	9.5	$	23.6	$	18.4
Cash Available for Distribution—50%	$	10.4	$	9.4	$	21.3	$	18.1

CRITICAL ACCOUNTING POLICIES

Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2008 contained discussions of our critical accounting policies and estimates that require the use of significant estimates and judgment. See also Note 8 of Notes to Condensed Consolidated Financial Statements contained in this Report on Form 10-Q for the quarterly period ended June 30, 2009 for further discussion regarding significant estimates and judgment used in our annual goodwill impairment test as of April 1, 2009.

LIQUIDITY AND CAPITAL RESOURCES

We will rely primarily upon cash flows from operations, including cash distributions received from Gulfstream and Market Hub, and additional financing transactions to fund our liquidity and capital requirements for the next 12 months. As of June 30, 2009, we had negative net working capital of $5.6 million compared to negative $23.6 million as of December 31, 2008, of which the June 30, 2009 balance included $28.5 million and the December 31, 2008 balance included $50.0 million for the note payable on demand to Market Hub.

As a result of our ongoing strong earnings performance expected in existing operations, we expect to maintain a capital structure and liquidity profile that supports our strategic objectives and will continue to monitor market requirements and our liquidity and make adjustments to these plans as needed.

Operating Cash Flows

Cash flows provided by operating activities totaled $65.3 million in the six months of 2009 compared to $74.0 million during the same period in 2008. Higher earnings were offset by lower net fuel recoveries when comparing to prior periods and the timing of payments for services provided by our general partner.

Investing Cash Flows

Cash flows used in investing activities totaled $223.1 million in the first six months of 2009 compared to $2.3 million during the same period in 2008. This change was driven primarily by:

•

the $294.5 million acquisition of NOARK in 2009,

•

$31.6 million of proceeds in 2009 from the liquidation of available-for-sale securities as compared to $59.7 million of net proceeds from the liquidation of such securities in the 2008 period that were held as collateral for the term loan, partially offset by

•

a $70.5 million increase in distributions received from Gulfstream, as a result of their $300.0 million debt issuance in the 2009 period,

•

a $17.4 million decrease in investment expenditures representing capital contributions to Gulfstream and Market Hub in 2009 used to fund their expansion projects,

•

a $9.2 million decrease in capital expenditures, and

•

the $4.7 million cash portion of the Saltville acquisition in the 2008 period.

We estimate total 2009 capital and investment expenditures of approximately $74 million, excluding the NOARK acquisition, of which $60 million is expected to be used for expansion projects, primarily at Gulfstream and Market Hub, and $14 million for maintenance and other projects. We anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

We continue to evaluate customers’ needs for incremental expansion opportunities at East Tennessee, Gulfstream and Market Hub. In addition, we are assessing the needs of our Ozark customers for additional

transportation services. We expect that significant natural gas infrastructure, including both natural gas transportation and storage with links to growing gas supplies and markets, will be needed over time to serve growth in gas-fired power generation, oil-to-gas conversions, industrial development and attachments to new gas supply.

Our primary business objective is to grow our cash distributions over time. We intend to accomplish this objective through expansions of our existing asset base. In addition, we will continue to pursue strategic acquisitions of transportation and storage assets.

Financing Cash Flows

Net cash provided by financing activities totaled $137.8 million in the first six months of 2009 compared to $56.2 million cash used in the same prior-year period. This change was driven primarily by:

•

$212.2 million of net proceeds received in the issuance of units to the public in 2009,

•

$10.0 million net payments on long-term debt in 2008, and

•

a $0.8 million net transfer to parent in 2008, partially offset by

•

a $21.5 million net payment on debt payable to affiliates in the 2009 period, and

•

$7.5 million of increased distributions to partners in 2009 compared to 2008.

Available Credit Facility and Restrictive Debt Covenants. See Note 9 of Notes to Condensed Consolidated Financial Statements for a discussion of the available credit facility and related financial and other covenants. As previously discussed, on May 4, 2009 we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. The transaction was funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was refinanced in the second quarter of 2009 through the issuance of 9.8 million limited partner units and 0.2 million general partner units, resulting in net proceeds of $212.2 million that was used to repay $142.2 million drawn on our bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy. The bank credit facility was further paid down with the proceeds from the special distribution of $72.7 million received from Gulfstream in the second quarter of 2009.

Cash Distributions. As previously discussed, a cash distribution of $0.38 per limited partner unit was declared in July 2009, representing a 2.7% increase over the previous distribution of $0.37 per limited partner unit and the seventh consecutive quarterly increase. This cash distribution represents an 11.8% increase over the distribution of $0.34 per limited partner unit declared in July 2008.

Other Matters. We have an automatic shelf registration statement on file with the Securities and Exchange Commission to register the issuance of unspecified amounts of equity and debt securities up to $1.5 billion.

OTHER ISSUES

New Accounting Pronouncements

See Note 14 of Notes to Condensed Consolidated Financial Statements for discussion.

Item 3.

Quantitative and Qualitative Disclosures about Market Risk.

Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2008. We believe the exposure to market risk has not changed materially at June 30, 2009.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commissions’ rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of the management of Spectra Energy Partners (DE) GP, LP (our “General Partner”), including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2009, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of the management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended June 30, 2009 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

For information regarding material legal proceedings, see Note 11 of Notes to Condensed Consolidated Financial Statements.

Item 1A.

Risk Factors.

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our financial condition or future results. Other than the risk factors listed below related to the acquisition of NOARK, there were no changes to those risk factors at June 30, 2009.

The acquisition of NOARK could expose us to potential significant liabilities.

In connection with the acquisition of NOARK, we purchased all of the ownership interests of NOARK rather than just its assets. As a result, we purchased the liabilities of NOARK, including unknown and contingent liabilities, subject to certain exclusions in the purchase and sale agreement. We performed a certain level of due diligence in connection with the acquisition of NOARK and attempted to verify the representations of the sellers and of NOARK’s management, but there may be pending, threatened, contemplated or contingent claims against NOARK related to environmental, title, regulatory, litigation or other matters of which we are unaware. Although the sellers agreed to indemnify us on a limited basis against some of these liabilities, the sellers’ aggregate liability under the purchase and sale agreement is capped at $60.0 million (subject to certain adjustments). This limitation does not apply to liabilities arising from the sellers’ breach of certain fundamental representations. We

may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations of NOARK, which could materially adversely affect our operations and financial condition.

If the acquisition of NOARK is not as successful as we anticipate, it may reduce our cash from operations on a per unit basis.

If the acquisition of NOARK is not as successful as we anticipate, it may reduce our cash from operations on a per unit basis. The acquisition of NOARK involves potential risks, including, among other things:

•

a decrease in our liquidity as a result of our using a portion of our available borrowing capacity to finance the acquisition;

•

a reduction in volumes transported on Ozark Gas Transmission as a result of firm commitment contract expirations as described below;

•

competition from CenterPoint Energy Gas Transmission Company, Texas Gas Transmission, LLC and the proposed Fayetteville Express Pipeline LLC as described below;

•

an inability of NOARK to successfully complete expansion projects;

•

unforeseen difficulties in NOARK’s areas of operations; and

•

the loss of certain key customers.

The NOARK assets compete with CenterPoint Energy Gas Transmission Company, Texas Gas Transmission, LLC’s Fayetteville Lateral (Fayetteville Lateral) and the proposed Fayetteville Express Pipeline LLC (Fayetteville Express). The Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline originates in Conway County, Arkansas and proceeds southeast to an interconnection with Texas Gas Transmission, LLC’s mainline in Coahoma County, Mississippi. The Fayetteville Lateral is currently in service, with certain compression facilities, it is anticipated to reach 1.3 Bcf/d transmission capacity by late 2010. Fayetteville Express is an approximately 185-mile pipeline owned by a joint venture between Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., which will originate in Conway County, Arkansas and continue eastward to an interconnection with Trunkline Gas Company, LLC’s pipeline in Panola County, Mississippi. The Fayetteville Express will have an initial capacity of 2.0 Bcf/d and is expected to be placed into service in late 2010. These risks could inhibit the success of the acquisition of NOARK. As a result, the acquisition of NOARK may not achieve expected investment returns, which could adversely affect our consolidated results of operations, financial position or cash flows. If the acquisition of NOARK is not as successful as we anticipate, our ability to make distributions may be reduced.

We may not be able to maintain or replace expiring natural gas transportation contracts related to the NOARK System at favorable rates.

Our primary exposure to market risk occurs at the time existing transportation contracts expire and are subject to renegotiation and renewal. Firm commitment contracts representing 75% of the revenue generated by Ozark Gas Transmission will expire by December 31, 2011, with the majority of such expirations occurring in March of 2011. Upon expiration, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis. The extension or replacement of these contracts depends on a number of factors beyond our control, including:

•

the level of existing and new competition to deliver natural gas to Ozark Gas Transmission’s markets, including the Fayetteville Lateral and Fayetteville Express;

•

the growth in demand for natural gas in Ozark Gas Transmission’s markets;

•

whether the market will continue to support long-term contracts;

•

whether our business strategy continues to be successful; and

•

the effects of state regulation on customer contracting practices.

Any failure to extend or replace a significant portion of Ozark Gas Transmission’s existing contracts may have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

Ozark Gas Transmission depends on certain key customers for a significant portion of their revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions.

Ozark Gas Transmission depends on a limited number of customers for a significant portion of their revenues. Currently, Southwestern Energy Company, Arkansas Western Gas Company and BP Energy Company account for approximately 34%, 16% and 12%, respectively, of Ozark Gas Transmission’s revenues. While these customers are subject to long-term contracts, the loss of all or even a portion of the contracted volumes of these customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions, unless we are able to contract for comparable volumes from other customers at favorable rates.

Item 4.

Submission of Matters to a Vote of Security Holders.

None.

Item 6.

Exhibits.

The agreements included as exhibits to this Form 10-Q contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

•

should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•

have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•

may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and

•

were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. We acknowledge that, notwithstanding the inclusion of the foregoing cautionary statements, we are responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-Q not misleading.

(a)

Exhibits


Exhibit Number
2.1		Securities Purchase Agreement, dated as of April 7, 2009, among Spectra Energy Partners OLP, LP, Atlas Pipeline Mid-Continent LLC, Atlas Pipeline Partners, L.P, solely as guarantor of Atlas Pipeline Mid-Continent LLC, and Spectra Energy Partners, LP, solely as guarantor of Spectra Energy Partners OLP, LP (filed as Exhibit 10.1 to Spectra Energy Partners’ Form 8-K on April 8, 2009).

10.1		Credit Agreement, dated as of April 7, 2009, between Spectra Energy Partners OLP, LP, as borrower, and Spectra Energy Capital, LLC, as lender (filed as Exhibit 10.2 to Spectra Energy Partners’ Form 8-K on April 8, 2009).

*18.1		Accountants’ Preferability Letter Regarding Change in Accounting Principles.

*31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith

SIGNATURES

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.


	SPECTRA ENERGY PARTNERS, LP

	By:	Spectra Energy Partners (DE) GP, LP,
		its general partner

	By:	Spectra Energy Partners GP, LLC,
		its general partner

Date: August 7, 2009		/s/ GREGORY J. RIZZO
		Gregory J. Rizzo President and Chief Executive Officer Spectra Energy Partners GP, LLC

Date: August 7, 2009		/s/ LAURA BUSS SAYAVEDRA
		Laura Buss Sayavedra Vice President and Chief Financial Officer Spectra Energy Partners GP, LLC

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