Edgar Filing: Spectra Energy Partners, LP

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2018

¨ 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 ý 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 ý No ¨

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

Large accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨

Smaller reporting company ¨ Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

At July 31, 2018, there were 484,890,253 common units outstanding.

SPECTRA ENERGY PARTNERS, LP

FORM 10-Q FOR THE QUARTER ENDED

June 30, 2018

INDEX




PART I. FINANCIAL INFORMATION		Page

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017	4

	Condensed Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017	5

	Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	6

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017	7

	Condensed Consolidated Statements of Equity for the six months ended June 30, 2018 and 2017	8

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	30

Item 4.	Controls and Procedures	30

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

Item 6.	Exhibits	33

	Signatures	35

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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 represent management’s intentions, plans, expectations, assumptions and beliefs about future events. 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 are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:


•	state, provincial, federal and foreign 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 and oil 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 and foreign currency exchange rates;


•	general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and oil and related services;


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


•	interruption of our operations due to social, civil or political events or unrest;


•	changes in environmental, safety and other laws and regulations;


•	the development of alternative energy resources;


•	results and costs 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 U.S. and Canadian pipeline, storage, gathering and other related infrastructure projects and the effects of competition;


•	the performance of natural gas transmission, storage and gathering facilities, and crude oil transportation and storage;


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


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


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


•	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;


•	the negotiation and execution, and the terms and conditions, of a definitive agreement relating to the proposed transaction and the timing and ability of Enbridge Inc. or Spectra Energy Partners, LP to enter into or consummate such agreement; and


•	the focus of management time and attention on the proposed transaction and other disruptions arising from the proposed transaction.

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.

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PART I. FINANCIAL INFORMATION



Item 1.	Financial Statements (Unaudited).

SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited; in millions, except per-unit amounts)



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Operating revenues
Transportation of natural gas	$	575	$	538	$	1,189	$	1,076
Transportation of crude oil	97		100		195		201
Storage of natural gas and other	54		57		121		118
Total operating revenues	726		695		1,505		1,395
Operating expenses
Operating, maintenance and other	191		209		379		436
Depreciation and amortization	90		87		179		172
Property and other taxes	59		56		119		112
Total operating expenses	340		352		677		720
Operating income	386		343		828		675
Other income and expenses
Earnings from equity investments	71		40		129		78
Other income and expenses, net	26		49		34		94
Total other income and expenses	97		89		163		172
Interest expense	85		60		170		116
Earnings before income taxes	398		372		821		731
Income tax expense	7		5		12		10
Net income	391		367		809		721
Net income attributable to noncontrolling interests	10		39		21		76
Net income attributable to controlling interests	$	381	$	328	$	788	$	645

Net income attributable to controlling interests	$	381	$	328	$	788	$	645
Net income attributable to general partner	—		94		—		183
Net income attributable to limited partners	$	381	$	234	$	788	$	462
Weighted average limited partner units outstanding—basic and diluted	485		310		465		310
Net income per limited partner unit—basic and diluted	$	0.78	$	0.75	$	1.69	$	1.49
Distributions paid per limited partner unit	$	0.75125	$	0.70125	$	1.49000	$	1.39000

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited; in millions)



	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Net income	$	391		$	367	$	809		$	721
Other comprehensive income:
Foreign currency translation adjustments	(7		)	6		(14		)	7
General partner units restructuring	—			—		(3		)	—
Change in unrealized gain on cash flow hedges	9			—		35			—
Other comprehensive income	2			6		18			7
Comprehensive income	393			373		827			728
Comprehensive income attributable to noncontrolling interests	10			39		21			76
Comprehensive income attributable to controlling interests	$	383		$	334	$	806		$	652

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited; in millions)



	June 30, 2018			December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	96		$	107
Receivables (net of allowance for doubtful accounts of $13 million and $10 million at June 30, 2018 and December 31, 2017, respectively)	326			372
Inventory	62			40
Fuel Tracker	101			19
Other assets, net	36			23
Total current assets	621			561
Investments in and loans to unconsolidated affiliates	2,789			3,302
Goodwill	2,953			2,957
Property, plant and equipment, net	15,128			14,899
Regulatory and other assets	352			337
Total assets	$	21,843		$	22,056

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	286		$	259
Taxes payable	112			84
Interest payable	85			68
Current portion of long-term debt	500			500
Other	144			194
Total current liabilities	1,127			1,105
Long-term debt	7,651			7,963
Deferred income taxes	46			46
Regulatory and other liabilities	1,018			1,041
Total liabilities	9,842			10,155
Commitments and contingencies
Partners’ capital
Common units (484.9 and 312.4 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively)	11,655			11,183
General partner units (no units and 6.4 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively)	—			386
Accumulated other comprehensive loss	(15		)	(33		)
Total partners’ capital	11,640			11,536
Noncontrolling interests	361			365
Total equity	12,001			11,901
Total liabilities and equity	$	21,843		$	22,056

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited; in millions)



	Six Months Ended June 30,
	2018			2017

OPERATING ACTIVITIES
Net income	$	809		$	721
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	184			175
Deferred income tax expense	—			2
Earnings from equity investments	(129		)	(78		)
Distributions from equity investments	99			57
Regulatory liability - deferred income taxes	(25		)	—
Change in operating assets and liabilities	(55		)	(69		)
Net cash provided by operating activities	883			808
INVESTING ACTIVITIES
Capital expenditures	(385		)	(1,361		)
Investments in and loans to unconsolidated affiliates	(232		)	(158		)
Distributions from equity investments	36			21
Distribution from Sabal Trail debt proceeds	744			—
Other	—			2
Net cash provided by (used in) investing activities	163			(1,496		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	794			400
Payments for the redemption of long-term debt	—			(416		)
Net change in credit facility draws and commercial paper borrowings	(1,093		)	750
Distributions to noncontrolling interests	(28		)	(25		)
Contributions from noncontrolling interests	1			416
Proceeds from the issuances of units	—			87
Distributions to partners	(722		)	(597		)
Other	(11		)	(1		)
Net cash provided by (used in) financing activities	(1,059		)	614
Net decrease in Cash, cash equivalents and restricted cash	(13		)	(74		)
Cash, cash equivalents and restricted cash at beginning of period	114			233
Cash, cash equivalents and restricted cash at end of period	$	101		$	159

The accompanying notes are an integral part of these condensed consolidated financial statements.

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SPECTRA ENERGY PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(Unaudited; in millions)



	Partners’ Capital									Noncontrolling Interests			Total
	Common			General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
December 31, 2017	$	11,183		$	386		$	(33	)	$	365		$	11,901
Net income	788			—			—			21			809
General partner units restructuring	389			(386		)	(3		)	—			—
Other comprehensive income	—			—			21			—			21
Attributed deferred tax benefit	21			—			—			2			23
Incentive distribution rights restructuring legal fees	(4		)	—			—			—			(4		)
Distributions to partners	(722		)	—			—			—			(722		)
Contributions from noncontrolling interests	—			—			—			1			1
Distributions to noncontrolling interests	—			—			—			(28		)	(28		)
June 30, 2018	$	11,655		$	—		$	(15	)	$	361		$	12,001

December 31, 2016	$	11,650		$	452		$	(45	)	$	1,347		$	13,404
Net income	462			183			—			76			721
Other comprehensive income	—			—			7			—			7
Attributed deferred tax benefit	—			42			—			23			65
Issuances of units	85			2			—			—			87
Distributions to partners	(430		)	(167		)	—			—			(597		)
Contributions from noncontrolling interests	—			—			—			416			416
Distributions to noncontrolling interests	—			—			—			(25		)	(25		)
June 30, 2017	$	11,767		$	512		$	(38	)	$	1,837		$	14,078

The accompanying notes are an integral part of these condensed consolidated financial statements.

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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 (SEP) 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, through its subsidiaries and equity investments, is engaged in the transmission, storage and gathering of natural gas and the transportation and storage of crude oil through interstate pipeline systems. We are a Delaware master limited partnership (MLP). As of June 30, 2018, Enbridge Inc. (Enbridge) and its subsidiaries collectively owned 83% of us and the remaining 17% was publicly owned. Enbridge owns and controls our general partner, Spectra Energy Partners (DE) GP, LP (SEP GP), which owns a non-economic general partner interest in us. See Note 13 for additional information on our general partner interest.

We manage our business in two reportable segments: U.S. Transmission and Liquids. The U.S. Transmission segment provides interstate transmission, storage and gathering of natural gas. The Liquids segment provides transportation of crude oil and storage of natural gas.

Basis of Presentation. The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of management, the Condensed Consolidated Financial Statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These Condensed Consolidated Financial Statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017, except for the adoption of new standards. See Note 2 for additional information on the adoption of new standards.

2. New Accounting Pronouncements

Adoption of New Standards

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our Condensed Consolidated Financial Statements.

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Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the Condensed Consolidated Statements of Cash Flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within Cash and cash equivalents when reconciling the opening and closing period amounts shown on the Condensed Consolidated Statements of Cash Flows. For current and comparative periods, we amended the presentation in the Condensed Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with Cash and cash equivalents. The following table shows the changes in beginning and ending Cash, cash equivalents and restricted cash as a result of adopting ASU 2016-18:



		June 30, 2018		December 31, 2017		June 30, 2017		December 31, 2016
	(in millions)
Cash and cash equivalents		$	96	$	107	$	153	$	216
Restricted cash in Other assets, net		3		3		3		3
Restricted cash in Regulatory and other assets		2		4		3		14
Cash, cash equivalents and restricted cash		$	101	$	114	$	159	$	233

Simplifying Cash Flow Classification

Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Condensed Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and determined that the adoption of this ASU did not have a material impact on our Condensed Consolidated Financial Statements.

Recognition and Measurement of Financial Assets and Liabilities

Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale (AFS) securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our Condensed Consolidated Financial Statements.

Revenue from Contracts with Customers

Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not yet completed at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based, five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards. The adoption of this new standard did not have a material impact on our Condensed Consolidated Financial Statements. See Note 4 for additional information.

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Future Accounting Policy Changes

Improvements to Accounting for Hedging Activities

ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our Condensed Consolidated Financial Statements.

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our Condensed Consolidated Financial Statements.

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients permits entities not to reassess whether any expired or existing contracts contain leases, their lease classification, or any related initial direct costs.

Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.

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3. Segment Information

We manage our business in two reportable segments: U.S. Transmission and Liquids. The remainder of our business operations is presented as “Other”, and consists of certain corporate costs. Segment results are presented as earnings before interest, taxes, depreciation and amortization (EBITDA).



Condensed Consolidated Statements of Income	Total Operating Revenues		Depreciation and Amortization		Segment EBITDA/ Consolidated Earnings Before Income Taxes
	(in millions)
Three Months Ended June 30, 2018
U.S. Transmission	$	624	$	82	$	505
Liquids	102		8		67
Total reportable segments	726		90		572
Other	—		—		(2		)
Depreciation and amortization	—		—		90
Interest expense	—		—		85
Interest income and other	—		—		3
Total consolidated	$	726	$	90	$	398

Three Months Ended June 30, 2017
U.S. Transmission	$	592	$	79	$	480
Liquids	103		8		64
Total reportable segments	695		87		544
Other	—		—		(25		)
Depreciation and amortization	—		—		87
Interest expense	—		—		60
Interest income and other	—		—		—
Total consolidated	$	695	$	87	$	372

Six Months Ended June 30, 2018
U.S. Transmission	$	1,295	$	163	$	1,027
Liquids	210		16		142
Total reportable segments	1,505		179		1,169
Other	—		—		(3		)
Depreciation and amortization	—		—		179
Interest expense	—		—		170
Interest income and other	—		—		4
Total consolidated	$	1,505	$	179	$	821

Six Months Ended June 30, 2017
U.S. Transmission	$	1,188	$	156	$	959
Liquids	207		16		130
Total reportable segments	1,395		172		1,089
Other	—		—		(71		)
Depreciation and amortization	—		—		172
Interest expense	—		—		116
Interest income and other	—		—		1
Total consolidated	$	1,395	$	172	$	731

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4. Revenue from Contracts with Customers

Major Products and Services



		U.S. Transmission		Liquids		Consolidated
	(in millions)
Three Months Ended June 30, 2018
Transportation of natural gas		$	575	$	—	$	575
Transportation of crude oil		—		97		97
Storage of natural gas		47		5		52
Total revenue from contracts with customers		622		102		724
Other revenue		2		—		2
Intersegment revenue		—		—		—
Total revenue		$	624	$	102	$	726

Six Months Ended June 30, 2018
Transportation of natural gas		$	1,189	$	—	$	1,189
Transportation of crude oil		—		195		195
Storage of natural gas and other		102		15		117
Total revenue from contracts with customers		1,291		210		1,501
Other revenue		4		—		4
Intersegment revenue		—		—		—
Total revenue		$	1,295	$	210	$	1,505

We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.

Contract Balances



		Accounts Receivable		Contract Assets		Contract Liabilities
	(in millions)
Balance at adoption date		$	265	$	—	$	65
Balance at reporting date		248		—		65

Contract liabilities primarily relate to deferred revenue. There were no material changes in contract liabilities during the three and six months ended June 30, 2018.

Recognition and Measurement of Revenue



		U.S. Transmission		Liquids		Consolidated
Three months ended June 30, 2018	(in millions)
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage		$	622	$	102	$	724

Six months ended June 30, 2018
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage		$	1,291	$	210	$	1,501

Revenue to be Recognized from Unfulfilled Performance Obligations

Total revenue from performance obligations expected to be fulfilled in future periods is $22.0 billion, of which $1.3 billion and $2.4 billion is expected to be recognized during the remaining six months ending December 31, 2018 and year ending December 31, 2019, respectively. Revenues from contracts with customers which have an original expected duration of one year or less are excluded from these amounts.

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5. Net Income Per Limited Partner Unit and Cash Distributions

We determined basic and diluted net income per limited partner unit as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions, except per unit amounts)
Net income attributable to controlling interests	$	381	$	328	$	788	$	645
Less: Net income attributable to:
General partner’s interest in general partner units—2% (a)	—		7		—		13
General partner’s interest in incentive distribution rights (a)	—		87		—		170
Limited partners’ interest in net income attributable to common units	$	381	$	234	$	788	$	462
Weighted average limited partner units outstanding—basic and diluted	485		310		465		310
Net income per limited partner unit—basic and diluted	$	0.78	$	0.75	$	1.69	$	1.49

______________

(a) General partner units and incentive distribution rights (IDRs) were converted to common units of Spectra Energy Partners as a result of the Equity Restructuring Agreement dated January 21, 2018 (Equity Restructuring Agreement). See Note 13 for additional information.

Our partnership agreement requires that, within 60 days after the end of each quarter, we distribute all of our Available Cash, as defined below, to unitholders of record on the applicable record date.

Available Cash. Available Cash, for any quarter, consists of all cash and cash equivalents 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 for any one or more of the next four quarters,


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

•

provided, however, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of Available Cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that quarter if our general partner so determines.

6. Variable Interest Entities

Sabal Trail. We own a 50% interest in Sabal Trail Transmission, LLC (Sabal Trail), a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida.

On April 30, 2018, Sabal Trail issued $500 million in aggregate principal amount of 4.246% senior notes due in 2028, $600 million in aggregate principal amount of 4.682% senior notes due in 2038 and $400 million in aggregate principal amount of 4.832% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to its partners as a partial reimbursement of construction and development costs incurred by the partners. The net distribution made to us was $744 million and was used to pay down short-term borrowings.

As of June 30, 2018, Sabal Trail is no longer a variable interest entity (VIE) due to Sabal Trail having sufficient equity at risk to finance its activities based on reconsideration triggered by to Sabal Trail's debt issuance and the distributions made to its members in April 2018.

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NEXUS. We own a 50% interest in NEXUS Gas Transmission, LLC (NEXUS), a joint venture that is constructing a greenfield natural gas pipeline from Ohio to Michigan and leasing capacity on third party pipelines in order to provide transportation of Appalachian Basin natural gas to markets in Ohio, Michigan, and the Dawn Hub in Ontario, Canada through the Vector Pipeline. NEXUS is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of NEXUS that most significantly impact its economic performance is shared. We account for NEXUS under the equity method. Our maximum exposure to loss is $1.3 billion. We have an investment in NEXUS of $869 million and $640 million as of June 30, 2018 and December 31, 2017, respectively, classified as Investments in and loans to unconsolidated affiliates on our Condensed Consolidated Balance Sheets.

In 2016, we issued performance guarantees to a third party and an affiliate on behalf of NEXUS. See Note 12 for further discussion of the guarantee arrangement.

PennEast. In 2017, we purchased an additional 10% interest in PennEast Pipeline Company, LLC (PennEast) from PSEG Power Gas Holdings, LLC, increasing our ownership interest in PennEast to 20%. PennEast is a joint venture that is proposing to construct a natural gas pipeline originating in northeastern Pennsylvania, and ending near Pennington, Mercer County, New Jersey. PennEast is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of PennEast that most significantly impact its economic performance is shared. We account for PennEast under the equity method. Our maximum exposure to loss is $279 million. We have an investment in PennEast of $66 million and $55 million as of June 30, 2018 and December 31, 2017, respectively, classified as Investments in and loans to unconsolidated affiliates on our Condensed Consolidated Balance Sheets.

The maximum exposure to loss for these entities is limited to our current equity investment and the remaining expected contributions for each joint venture.

7. Marketable Securities and Restricted Funds

We routinely invest excess cash and various restricted balances in securities such as commercial paper, corporate debt securities, and other money market securities in the United States, as well as equity securities in Canada. We do not purchase marketable securities for speculative purposes, therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for the purposes of funding future capital expenditures and National Energy Board (NEB) regulatory requirements, so these investments are classified as AFS marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective type of securities (AFS marketable securities or held-to-maturity (HTM) marketable securities). Maturities of AFS securities are presented within Net cash used in investing activities within the Condensed Consolidated Statements of Cash Flows.

AFS Securities. We had $3 million of AFS securities classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017. At June 30, 2018 and December 31, 2017, these investments include $3 million of restricted funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB's regulatory requirements, as well as less than $1 million of restricted funds related to certain construction projects as of December 31, 2017.

At June 30, 2018, the weighted-average contractual maturity of outstanding AFS securities was less than one year.

There were no material gross unrecognized holding gains or losses associated with investments in AFS securities at June 30, 2018 or December 31, 2017.

HTM Securities. All of our HTM securities are restricted funds. We had $3 million money market securities classified as Other assets, net on the Condensed Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017. These securities are restricted pursuant to certain Express-Platte pipeline system debt agreements.

At June 30, 2018, the weighted-average contractual maturity of outstanding HTM securities was less than one year.

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There were no material gross unrecognized holding gains or losses associated with investments in HTM securities at June 30, 2018 or December 31, 2017.

Other Restricted Funds. In addition to the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling $2 million and $4 million classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017, respectively. These restricted funds are related to certain construction projects.

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. As a result, changes in restricted cash and restricted cash equivalents, which include HTM securities and other restricted funds discussed above, have been included within Cash and cash equivalents when reconciling the opening and closing period amounts shown on our Condensed Consolidated Statements of Cash Flows. Changes in restricted funds that are not restricted cash or restricted cash equivalents are presented within Net cash used in investing activities on our Condensed Consolidated Statements of Cash Flows. See Note 2 for additional information.

8. Debt

Credit Facility



	Maturity Date (a)	Total Facility		Draws (b)		Available
		(in millions)
Spectra Energy Partners, LP	2022	$	2,500	$	1,161	$	1,339

______________

(a) Includes $336 million of commitments that expire in 2021.

(b) Includes facility draws and commercial paper issuances that are back-stopped by the credit facility.

The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of June 30, 2018, there were no letters of credit issued or revolving borrowings outstanding under the credit facility.

Our commercial paper program provides for the issuance of up to an aggregate principal amount $2.5 billion of commercial paper and is supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt as of June 30, 2018 and December 31, 2017, respectively.

Our credit facility agreement and term debt indentures include common events of default and covenant provisions, including a financial covenant, whereby accelerated repayment and/or termination of the agreement may result if we were to default on payment or violate certain covenants. As of June 30, 2018, we were in compliance with those covenants.

Debt Issuances. On January 9, 2018, Texas Eastern Transmission, LP (Texas Eastern), an indirect subsidiary of Spectra Energy Partners, issued $400 million in aggregate principal amount of 3.50% senior notes due in 2028 and $400 million in aggregate principal amount of 4.15% senior notes due in 2048. Texas Eastern used a portion of the net proceeds from the offering to fund expansion projects and capital expenditures on the Texas Eastern pipeline system. In addition, Texas Eastern used a portion of the net proceeds from the offering to repay funds we advanced to Texas Eastern in September 2017, which Texas Eastern used to repay a $400 million debt maturity. We used the proceeds received to repay commercial paper and credit facility borrowings, which were incurred primarily to fund Texas Eastern’s capital expenditures, as well as those of our other subsidiaries.

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9. Fair Value Measurements

The following presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017:



Description	Condensed Consolidated Balance Sheet Caption	June 30, 2018
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Interest rate swaps	Other assets, net	22		$	—	$	22	$	—
Commodity swaps	Other assets, net	1		—		—		1
Canadian equity securities	Regulatory and other assets	3		3		—		—
Interest rate swaps	Regulatory and other assets	6		—		6		—
Commodity swaps	Regulatory and other assets	1		—		—		1
Total Assets		$	33	$	3	$	28	$	2

Interest rate swaps	Current liabilities — other	$	3	$	—	$	3	$	—
Interest rate swaps	Regulatory and other liabilities	7		—		7		—
Total Liabilities		$	10	$	—	$	10	$	—



Description	Condensed Consolidated Balance Sheet Caption	December 31, 2017
Description	Condensed Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Canadian equity securities	Regulatory and other assets	$	3	$	3	$	—	$	—
Interest rate swaps	Other assets, net	4		—		4		—
Commodity swaps	Other assets, net	2		—		—		2
Total Assets		$	9	$	3	$	4	$	2

Interest rate swaps	Current liabilities — other	$	3	$	—	$	3	$	—
Interest rate swaps	Regulatory and other liabilities	5		—		5		—
Total Liabilities		$	8	$	—	$	8	$	—

Level 1

Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.

Level 2

Fair values of our financial instruments that are actively traded in the secondary market, including our long-term debt, are determined based on market-based prices. These Level 2 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.

For interest rate swaps, we utilize data obtained from a third-party source for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps are discounted to present value.

Level 3

Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.

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Financial Instruments

The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.



	June 30, 2018				December 31, 2017
Condensed Consolidated Balance Sheets	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Note receivable, noncurrent (a)	$	71	$	71	$	71	$	71
Long-term debt, including current maturities (b)	6,650		6,639		5,850		6,211

______________

(a)Included within Investments in and loans to unconsolidated affiliates.

(b)Excludes variable rate debt, unamortized items and fair value hedge carrying value adjustments.

The fair value of our fixed-rate long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and is classified as Level 2.

The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, note receivable-noncurrent, accounts payable, short-term money market securities, commercial paper, credit facility borrowings and long-term variable-rate debt 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.

10. Risk Management and Hedging Activities

Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from the Canadian portion of the Express-Platte pipeline. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate exposures.

Total Interest Rate Derivative Instruments

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduces our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement in the event of these specific circumstances. All amounts are presented gross on the Condensed Consolidated Balance Sheets:



	June 30, 2018									December 31, 2017
	Gross Amounts Presented in the Condensed Consolidated Balance Sheet			Amounts Available for Offset			Net Amount			Gross Amounts Presented in the Condensed Consolidated Balance Sheet			Amounts Available for Offset			Net Amount
Description	(in millions)
Assets	$	28		$	(1	)	$	27		$	4		$	(1	)	$	3
Liabilities	(10		)	1			(9		)	(8		)	1			(7		)

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Fair Value Hedges

At June 30, 2018, we had “pay floating - receive fixed” interest rate swaps outstanding with a total notional amount of $900 million to hedge against changes in the fair value of our fixed-rate financial instruments that arise as a result of changes in market interest rates. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term debt securities from fixed-rate to variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt. Our "pay floating - received fixed" interest rate derivative instruments are designated and qualify as fair value hedges. The gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is recognized in the Condensed Consolidated Statements of Income. During the six months ended June 30, 2018, the amounts recognized were $8 million loss on the fair value hedges and offsetting $8 million gain on long-term debt.

Cash Flow Hedges

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. Since the third quarter of 2017, we have entered into pre-issuance interest rate swaps which are designated and qualified as cash flow hedges. The information of these cash flow swaps are presented as follows:



						Fair Value at
Date of Maturity & Contract Type	Accounting Treatment	Average Interest Rate		Notional Amount		June 30, 2018		December 31, 2017
				(in millions)
Contracts maturing in 2018	Cash Flow Hedge	2.51	%	$	560	$	22	$	1
Contracts maturing in 2020	Cash Flow Hedge	2.70	%	250		6		(3		)

We estimate that $2 million of Accumulated Other Comprehensive Income will be reclassified into net income in the next 12 months related to these swaps.

The effects of derivative instruments on the Condensed Consolidated Statements of Income and the Condensed Consolidated Statements of Comprehensive Income are shown as follows:



Amount of unrealized gain recognized in Other Comprehensive Income	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Cash flow hedges - interest rate swaps	$	9	$	—	$	35	$	—

Non-qualifying Hedges

Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets. In July 2017, we entered into a power swap to fix a portion of the variable price exposure for power costs from the Canadian portion of our Express-Platte pipeline system until 2020. As a result, we recognized an unrealized loss of $1 million and less than $1 million included in Operating, maintenance and other on the Condensed Consolidated Statements of Income during the three and six months ended June 30, 2018, respectively and hedge assets of $2 million included in Other assets, net and Regulatory and other assets on the Condensed Consolidated Balance Sheets at June 30, 2018.

11. Commitments and Contingencies

Environmental

We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.

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Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and we and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses.

Litigation

We are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our condensed consolidated financial position or results of operations.

12. Guarantees

We have various financial guarantees which are issued in the normal course of business. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Condensed Consolidated Balance Sheets. The possibility of having to perform under these guarantees is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.

In December 2016, we issued performance guarantees to a third party and an affiliate on behalf of an equity method investee. These guarantees were issued to enable the equity method investee to enter into long-term transportation contracts with the third party. While the likelihood is remote, the maximum potential amount of future payments we could have been required to make as of June 30, 2018 was $107 million. These performance guarantees expire in 2032.

As of June 30, 2018, the amounts recorded for the guarantees described above are not material, either individually or in the aggregate.

13. Issuances of Common Units

On January 21, 2018, we entered into the Equity Restructuring Agreement with SEP GP, our general partner pursuant to which the IDRs and the 2% general partner interest in us held by that entity were converted into 172,500,000 newly issued common units and a non-economic general partner interest in us.



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 accompanying Condensed Consolidated Financial Statements.

EXECUTIVE OVERVIEW

For the three months ended June 30, 2018 and 2017, we reported net income attributable to controlling interests of $381 million and $328 million, respectively. For the six months ended June 30, 2018 and 2017, we reported net income attributable to controlling interests of $788 million and $645 million, respectively. Key highlights for the six months ended June 30, 2018 include increased earnings driven by natural gas pipeline expansions, an adjustment to the established regulatory liability resulting from the 2017 U.S. tax reform legislation, increased natural gas transportation revenues, and a decrease in merger-related severance costs, partially offset by lower allowance for funds used during construction (AFUDC) due to Sabal Trail being placed into service.

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For the three months ended June 30, 2018 and 2017, Distributable Cash Flow was $398 million and $341 million, respectively. For the six months ended June 30, 2018 and 2017, Distributable Cash Flow was $851 million and $697 million, respectively. A cash distribution of $0.76375 per limited partner unit was declared on August 2, 2018 and is payable on August 29, 2018. We intend to increase our quarterly distribution by one and a quarter cents per unit each quarter through 2018. The declaration and payment of distributions, however, is subject to the sole discretion of our Board of Directors and depends upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints, our partnership agreement and other factors deemed relevant by our Board of Directors.

For the six months ended June 30, 2018, we had $617 million of capital and investment expenditures. We currently project $1.8 billion of capital and investment expenditures for the full year of 2018, including expansion capital expenditures of $1.6 billion.

We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing growth activities will continue to be based on our strong and growing fee-based earnings and cash flows and the issuances of debt and equity securities. As of June 30, 2018, we had access to approximately $1.3 billion in borrowing capacity under our $2.5 billion revolving credit facility which is used principally as a back-stop for our commercial paper program.

Enbridge offer to acquire publicly owned common units

On May 18, 2018, we announced that we received a non-binding offer from Enbridge and Enbridge (U.S.) Inc. to acquire all of our outstanding common units not currently beneficially owned by Enbridge (the Proposal). Under the terms of the Proposal, our common unitholders would receive 1.0123 common shares of Enbridge per common unit.

The board of directors of SEP GP has established a conflicts committee of independent directors to review and consider the Proposal. Any definitive agreement is subject to approval of a majority of the outstanding common units, and is expected to contain customary closing conditions, including standard regulatory notifications and approvals.

The Proposal is part of Enbridge's sponsored vehicle restructuring initiative to simplify its corporate structure. On May 17, 2018, Enbridge announced separate all-share proposals to the respective boards of directors of Enbridge's other sponsored vehicles, including Enbridge Energy Management, L.L.C., Enbridge Energy Partners, L.P., and Enbridge Income Fund Holdings Inc. to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by Enbridge.

United States tax reform update

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (TCJA). The most significant change included in the TCJA is the reduction in the corporate federal income tax rate from 35% to 21% (U.S. Tax Reform). As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the U.S. Securities and Exchange Commission (SEC) on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the U.S. Tax Reform for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of the U.S Tax Reform, we continue to refine our estimates. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the U.S. Tax Reform. This resulted in a reduction of the $860 million overall regulatory liability by $25 million.

Revised Federal Energy Regulatory Commission (FERC) policy on the treatment of income taxes

On March 15, 2018, the FERC changed its long-standing policy on the treatment of income tax amounts included in the rates of pipelines and other entities subject to cost of service rate regulation within a MLP. In its order, the FERC revised a policy in place since 2005 to no longer permit entities organized as MLPs to recover an income tax allowance in their cost of service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking (NOPR) proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each pipeline; and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. These FERC announcements have negatively affected MLPs generally.

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We filed comments to request clarification, reconsideration and rehearing of this policy change at the FERC. We also responded to the NOPR in April and filed comments in response to the Notice of Inquiry. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing.

On July 18, 2018, the FERC issued an Order that: (1) dismissed all requests for rehearing of its March 15, 2018 revised policy statement and explained that its revised policy statement does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (2) provides guidance that if an MLP or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC’s Revised Policy Statement, then Accumulated Deferred Income Taxes (ADIT) will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT instead of flowing ADIT balances back to ratepayers. As a statement of general policy, the FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.

While many uncertainties remain with regards to the implementation of the FERC actions, if implemented as announced, and combined with the impact of the U.S. Tax Reform, we estimate the impact to revenue and cash flow to be immaterial. The benefit from the changes related to ADIT offset the discontinuance of recovering an income tax allowance in cost of service rates. Any future direct impacts would only take effect upon the execution and settlement of a rate case where the outcome could be different.

In a companion rulemaking proceeding, the FERC also codified the final rules for certain natural gas pipeline compliance filings known as Form 501-G. This new filing is expected, in most circumstances, to be a one-time filing. In this filing a FERC regulated natural gas pipeline specifies how it intends to adjust (or not) its rates due to the collective impacts of reductions in the US income tax rates and, in the case of MLP’s and certain other pass through entities, the impacts of FERC’s revised tax allowance policy. Under the new rulemaking, a number of our natural gas pipelines will need to file under this new rule by the end of 2018. Pending greater clarification from the FERC on the application of its new policy, assessing the near-term and long-term implications of the policy is challenging.

RESULTS OF OPERATIONS



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)
Operating revenues	$	726	$	695	$	1,505	$	1,395
Operating expenses	340		352		677		720
Operating income	386		343		828		675
Earnings from equity investments	71		40		129		78
Other income and expenses, net	26		49		34		94
Interest expense	85		60		170		116
Earnings before income taxes	398		372		821		731
Income tax expense	7		5		12		10
Net income	391		367		809		721
Net income—noncontrolling interests	10		39		21		76
Net income—controlling interests	$	381	$	328	$	788	$	645

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Three Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. The $31 million increase was driven mainly by:


•	an increase due to expansion projects primarily on Texas Eastern and Algonquin Gas Transmission, LLC (Algonquin),


•	an increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by,

•

a decrease in revenue from Sabal Trail due to a change in accounting treatment. During the second quarter of 2017, we received contributions from Sabal Trail prior to its in-service date which were recorded in operating revenues. Upon the commencement of commercial service, we deconsolidated our investment and began accounting for it under the equity method. All contributions from Sabal Trail are now recorded within one line called earnings from equity investments as discussed below.

Operating expenses. The $12 million decrease was driven mainly by:


•	a decrease due to 2017 merger-related severance costs,


•	a decrease due to higher pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident near Delmont, Pennsylvania, partially offset by


•	an increase in electric power and other costs passed through to gas transmission customers.

Earnings from equity investments. The $31 million increase was mainly attributable to Sabal Trail being placed into service and higher AFUDC related to NEXUS.

Other income and expenses, net. The $23 million decrease was mainly attributable to lower AFUDC due to Sabal Trail being placed into service.

Interest expense. The $25 million increase was mainly attributable to lower capitalized interest due to Sabal Trail being placed into service and an increase in interest rates related to short-term borrowings.

Six Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. The $110 million increase was driven mainly by:


•	an increase due to expansion projects primarily on Texas Eastern and Algonquin,


•	an increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform,


•	an increase in recoveries of electric power and other costs passed through to gas transmission customers,


•	an increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by


•	a decrease in revenue from Sabal Trail due to a change in accounting treatment as previously discussed.

Operating expenses. The $43 million decrease was driven mainly by:


•	a decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident near Delmont, Pennsylvania,


•	a decrease due to 2017 merger-related severance costs,


•	a decrease in integrity and power costs, partially offset by


•	an increase in electric power and other costs passed through to gas transmission customers, and


•	an increase in costs related to expansion.

Earnings from equity investments. The $51 million increase was mainly attributable to Sabal Trail being placed into service and higher AFUDC related to NEXUS.

Other income and expenses, net. The $60 million decrease was mainly attributable to lower AFUDC due to Sabal Trail being placed into service.

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Interest expense. The $54 million increase was mainly attributable to lower capitalized interest due to Sabal Trail being placed into service and an increase in interest rates related to short-term borrowings.

Segment Results

Management evaluates segment performance based on EBITDA. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income, are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.

Segment EBITDA is summarized in the following table. Detailed discussions follow.

EBITDA by Business Segment



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)
U.S. Transmission	$	505		$	480		$	1,027		$	959
Liquids	67			64			142			130
Total reportable segment EBITDA	572			544			1,169			1,089
Other	(2		)	(25		)	(3		)	(71		)
Depreciation and amortization	90			87			179			172
Interest expense	85			60			170			116
Interest income and other	3			—			4			1
Earnings before income taxes	$	398		$	372		$	821		$	731

The amounts discussed below are after eliminating intercompany transactions.

U.S. Transmission



	Three Months Ended June 30,						Six Months Ended June 30,
	2018		2017		Increase (Decrease)		2018		2017		Increase (Decrease)
	(in millions)
Operating revenues	$	624	$	592	$	32	$	1,295	$	1,188	$	107
Operating expenses
Operating, maintenance and other	212		201		11		426		401		25
Other income/(expense)	93		89		4		158		172		(14		)
EBITDA	$	505	$	480	$	25	$	1,027	$	959	$	68

Three Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. The $32 million increase was driven by:


•	a $32 million increase due to expansion projects primarily on Texas Eastern and Algonquin,


•	a $10 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by


•	a $10 million decrease from Sabal Trail due to a change in accounting treatment as previously discussed.

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Operating, maintenance and other. The $11 million increase was driven by:


•	a $13 million increase primarily due to allocated corporate shared-service costs previously reported on "Other",


•	a $10 million increase in electric power and other costs passed through to gas transmission customers, partially offset by


•	an $11 million decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident.

Six Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. The $107 million increase was driven by:


•	a $65 million increase due to expansion projects primarily on Texas Eastern and Algonquin,


•	a $25 million increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform,


•	a $19 million increase in recoveries of electric power and other costs passed through to gas transmission customers,


•	a $16 million increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by


•	a $10 million decrease from Sabal Trail due to a change in accounting treatment as previously discussed, and


•	an $8 million decrease in storage revenues mainly due to lower contract renewal rates.

Operating, maintenance and other. The $25 million increase was driven by:


•	a $25 million increase primarily due to allocated corporate shared-service costs previously reported on "Other",


•	a $19 million increase in electric power and other costs passed through to gas transmission customers,


•	a $7 million increase in costs related to expansion, partially offset by


•	a $13 million decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident, and


•	a $12 million decrease due to 2017 merger-related severance costs.

Other income and expenses. The $14 million decrease was driven by:


•	a $77 million decrease in equity AFUDC due to Sabal Trail being placed into service, partially offset by


•	a $51 million increase due to higher equity earnings from Sabal Trail being placed into service, and


•	an $11 million increase due to corporate allocations of pension costs.

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Liquids



	Three Months Ended June 30,							Six Months Ended June 30,
	2018		2017		Increase (Decrease)			2018		2017			Increase (Decrease)
	(in millions)
Operating revenues	$	102	$	103	$	(1	)	$	210	$	207		$	3
Operating expenses
Operating, maintenance and other	36		39		(3		)	69		76			(7		)
Other income/(expense)	1		—		1			1		(1		)	2
EBITDA	$	67	$	64	$	3		$	142	$	130		$	12
Express pipeline revenue receipts, MBbl/d (a)	263		254		9			262		263			(1		)
Platte PADD II deliveries, MBbl/d (a)	121		136		(15		)	132		140			(8		)

______________

(a) Thousand barrels per day.

Three Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. Operating revenues were consistent period over period.

Operating, maintenance and other. The $3 million decrease in operating expenses was mainly driven by a decrease in integrity and power costs.

Six Months Ended June 30, 2018 Compared to Same Period in 2017

Operating revenues. The $3 million increase in operating revenues was mainly driven by an increase in inventory settlement, partially offset by lower transportation volumes.

Operating, maintenance and other. The $7 million decrease in operating expenses was mainly driven by a decrease in integrity and power costs.

Other



	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Increase (Decrease)			2018			2017			Increase (Decrease)
	(in millions)
Operating expenses
Operating, maintenance and other	$	2		$	25		$	(23	)	$	3		$	71		$	(68	)
EBITDA	$	(2	)	$	(25	)	$	23		$	(3	)	$	(71	)	$	68

Three Months Ended June 30, 2018 Compared to Same Period in 2017

Operating, maintenance and other. The $23 million decrease was driven by:


•	a $13 million decrease due to 2017 merger-related severance costs, and


•	a $10 million decrease due to lower allocated corporate shared-service costs previously recorded in "Other".

Six Months Ended June 30, 2018 Compared to Same Period in 2017

Operating, maintenance and other. The $68 million decrease was driven by:


•	a $37 million decrease due to 2017 merger-related severance costs, and


•	a $31 million decrease due to lower allocated corporate shared-service costs previously recorded in "Other".

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DISTRIBUTABLE CASH FLOW

We define Distributable Cash Flow as EBITDA plus


•	distributions from equity investments,


•	other non-cash items affecting net income, less


•	earnings from equity investments,


•	interest expense,


•	equity AFUDC,


•	net cash paid for income taxes,


•	distributions to noncontrolling interests, and


•	maintenance capital expenditures.

Distributable Cash Flow does not reflect changes in working capital balances. Distributable Cash Flow should not be viewed as indicative of the actual amount of cash that we plan to distribute for a given period.

Distributable Cash Flow is the primary financial measure used by our management and by external users of our financial statements to assess the amount of cash that is available for distribution.

Distributable Cash Flow is a non-GAAP measure and 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. Distributable Cash Flow excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Distributable Cash Flow as presented may not be comparable to similarly titled measures of other companies.

Significant drivers of variances in Distributable Cash Flow 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.

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Reconciliation of Net Income to Non-GAAP “Distributable Cash Flow”



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)
Net income	$	391		$	367		$	809		$	721
Add:
Interest expense	85			60			170			116
Income tax expense	7			5			12			10
Depreciation and amortization	90			87			179			172
Foreign currency (gain) loss	(2		)	—			(3		)	—
Less:
Third party interest income	1			—			1			1
EBITDA	570			519			1,166			1,018
Add:
Earnings from equity investments	(71		)	(40		)	(129		)	(78		)
Distributions from equity investments	75			40			135			78
Non-cash impact of the U.S. Tax Reform	—			—			(25		)	—
Other	(4		)	(1		)	(3		)	—
Less:
Interest expense	85			60			170			116
Equity AFUDC	9			48			15			93
Net cash paid for income taxes	4			3			5			8
Distributions to noncontrolling interests	13			13			28			25
Maintenance capital expenditures	61			53			75			79
Distributable Cash Flow	$	398		$	341		$	851		$	697

LIQUIDITY AND CAPITAL RESOURCES

As of June 30, 2018, we had negative working capital of $506 million. This balance includes current maturities of long-term debt of $500 million. We will rely upon cash flows from operations, including cash distributions received from our equity affiliates, and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for the next 12 months. We have access to a revolving credit facility, with available capacity of $1,339 million at June 30, 2018. This facility is used principally as a back-stop for our commercial paper program, which is used to manage working capital requirements and for temporary funding of capital expenditures. Capital resources may continue to include commercial paper, short-term borrowings under our current credit facility and possibly securing additional sources of capital including debt and/or equity. See Note 8 of Notes to Condensed Consolidated Financial Statements for a discussion of the available credit facility and Financing Cash Flows and Liquidity below for a discussion of effective shelf registrations.

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Cash Flow Analysis

The following table summarizes the changes in cash flows for each of the periods presented:



	Six Months Ended June 30,
	2018			2017
	(in millions)
Net cash provided by (used in):
Operating activities	$	883		$	808
Investing activities	163			(1,496		)
Financing activities	(1,059		)	614
Net decrease in Cash, cash equivalents and restricted cash	(13		)	(74		)
Cash, cash equivalents and restricted cash at beginning of the period	114			233
Cash, cash equivalents and restricted cash at end of the period	$	101		$	159

Operating Cash Flows

Net cash provided by operating activities increased $75 million to $883 million in the six months ended June 30, 2018 compared to the same period in 2017, driven mainly by higher earnings and higher distributions from equity investments as a result of positive operating factors discussed in Results of Operations, and changes in working capital.

Investing Cash Flows

Net cash provided by investing activities totaled $163 million in the six months ended June 30, 2018 compared to $1,496 million used in investing activities in the same period in 2017. The change was mainly driven by:


•	a decrease of $976 million in capital expenditures primarily due to Sabal Trail being placed in-service in July 2017,


•	a $744 million distribution received from Sabal Trail during the three months ended June 30, 2018 as a partial return of capital for construction and development costs, partially offset by


•	a $74 million increase in investments in and loans to unconsolidated affiliates mainly due to increased investment in NEXUS, Sabal Trail being classified as an unconsolidated affiliate upon its deconsolidation in July 2017, and partially offset by an additional 10% investment purchased in PennEast in June 2017.



	Six Months Ended June 30,
Capital and Investment Expenditures by Business Segment	2018		2017
	(in millions)
U.S. Transmission	$	595	$	1,508
Liquids	22		11
Total consolidated	$	617	$	1,519

Capital and investment expenditures for the six months ended June 30, 2018 consisted of $542 million for expansion projects and $75 million for maintenance and other projects.

We project 2018 capital and investment expenditures of approximately $1.8 billion, consisting of $1.6 billion of expansion capital expenditures and $0.2 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These projections exclude contributions from noncontrolling interests.

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Financing Cash Flows and Liquidity

Net cash used in financing activities totaled $1,059 million in the six months ended June 30, 2018 compared to $614 million provided by financing activities in the same period in 2017. The change was mainly driven by:


•	$1,093 million of repayments of credit facility in 2018 compared to $750 million of issuances of credit facility in 2017,


•	a $415 million decrease in contributions from noncontrolling interest as a result of Sabal Trail being classified as an unconsolidated affiliate upon its deconsolidation in July 2017,


•	a $125 million increase in distributions to partners as a result of an increase in our quarterly per unit distribution and an increase in the number of common units outstanding and


•	an $87 million decrease in proceeds from the issuances of units as a result of the issuance of common and general partner units in 2017, partially offset by


•	a $416 million decrease in payments for the redemption of long-term debt,


•	a $394 million increase in proceeds from issuance of long-term debt.

Available Credit Facility and Restrictive Debt Covenants. Our credit facility agreements and term debt indentures include common events of default and covenant provisions, including a financial covenant, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As of June 30, 2018, we were in compliance with the covenants. See Note 8 of Notes to Condensed Consolidated Financial Statements for a discussion of the available credit facility and related financial and other covenants.

Cash Distributions. A cash distribution of $0.76375 per limited partner unit was declared on August 2, 2018, payable on August 29, 2018, representing the forty-third consecutive quarterly increase.

Other Financing Matters. We have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. We have another effective registration statement on file with the SEC to register the issuance of $1 billion, in the aggregate, of limited partner units over time. This registration has $186 million available as of June 30, 2018.

OTHER ISSUES

New Accounting Pronouncements. See Note 2 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, 2017. We believe our exposure to market risk has not changed materially since then.



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 SEC’s 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 Principal Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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Under the supervision and with the participation of the management of SEP GP, including the Principal Executive Officer and Principal 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, 2018, and, based upon this evaluation, the Principal Executive Officer and Principal Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of the management of our General Partner, including the Principal Executive Officer and Principal 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, 2018 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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PART II. OTHER INFORMATION



Item 1.	Legal Proceedings.

Except for the matters described below, we have no material pending legal proceedings that are required to be disclosed hereunder. For more information regarding other legal proceedings, including regulatory and environmental matters, see Note 11 of Notes to Condensed Consolidated Financial Statements, which information is incorporated by reference into this Part II.

Paul Morris v. Spectra Energy Partners (DE) GP, LP, Spectra Energy Corp, Defendants, and Spectra Energy Partners, LP, Nominal Defendant

A putative class action lawsuit asserting direct and derivative claims was filed in the Delaware Court of Chancery in March of 2016 by Paul Morris (Plaintiff), a unitholder of SEP. The claims in the lawsuit relate to a transaction in October 2015 whereby 33% ownership interests in the Sand Hills and Southern Hills pipelines were sold by us to Spectra Energy Corp (SE Corp) and, subsequent to that transaction, SE Corp contributed those ownership interests to DCP Midstream, LLC, a joint venture in which SE Corp owns a 50% ownership interest. The lawsuit alleges that the consideration paid to us by SE Corp in exchange for those ownership interests was approximately $525 million less than the purported value of such ownership interests. The lawsuit asserted direct and derivative claims of breach of contract and breach of the implied duty of good faith and fair dealing against SEP GP and direct and derivative claims of tortious interference with the SEP Limited Partnership Agreement against SE Corp. SEP is also named as a “nominal” defendant in the lawsuit for the derivative claims.

On January 13, 2017, Plaintiff withdrew all of his direct claims in the lawsuit. On June 27, 2017, the Delaware Court of Chancery issued a Memorandum Opinion dismissing the derivative claims of tortious interference against SE Corp and the breach of the implied duty of good faith and fair dealing against SEP GP, leaving only the derivative claim for breach of the Limited Partnership Agreement against SEP GP pending. The relief sought in the complaint includes rescission of the transaction, damages, interest and attorneys’ fees.

Sierra Club v. Federal Energy Regulatory Commission, Respondent, and Sabal Trail Transmission, LLC et al., Intervenor-Respondents (D.C. Cir.)

Sierra Club and two other non-governmental organizations filed a Petition for Review of Sabal Trail’s FERC certificate on September 20, 2016 in the D.C. Circuit Court of Appeals. On August 22, 2017, the D.C. Circuit issued an opinion denying one of the petitions, and granting the other petition in part, vacating the certificates, and remanding the case to the FERC to supplement the environmental impact statement for the project to estimate the quantity of green-house gases to be released into the environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and the FERC each filed timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions for rehearing. On February 5, 2018, the FERC issued its final supplemental environmental impact statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, the FERC filed a motion with the court requesting a 45-day stay of the mandate. On March 7, 2018, the Court granted FERC’s 45-day request for stay, and directed that issuance of the mandate be withheld through March 26, 2018. On March 14, 2018, the FERC issued its Order on Remand Reinstating Certificate and Abandonment Authorizations which addressed the Court’s ruling in the August 22, 2017 decision, and on March 30, 2018 the Court issued its mandate.

Sierra Club and two other non-governmental organizations, as well as the two landowners, timely requested rehearing from FERC of the March 14, 2018 Order. These requests for rehearing are currently pending before the FERC.



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, 2017, which could materially affect our financial condition or future results. There have been no material changes to those risk factors except as described below.

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There can be no assurance that the proposed combination transactions between the Partnership, Enbridge and Enbridge (U.S.) Inc. will be agreed upon, approved and ultimately consummated, and the terms of any such transactions may differ materially from those originally proposed by Enbridge.

On May 17, 2018, Enbridge and Enbridge (U.S.) Inc. made a non-binding all-share proposal to the boards of directors of the delegate of the general partner of the Partnership (the Board), to acquire, in a combination transaction, all of the outstanding common units of the Partnership not beneficially owned by Enbridge. Under the original proposal, the Partnership common unitholders would receive 1.0123 common shares of Enbridge per common unit.

The Proposal is subject to negotiation. Any definitive agreement with respect to the Proposal is subject to approval by the Enbridge board of directors and the Board, and general partner and unitholder approvals. In addition, the Proposal is expected to be subject to customary closing conditions, including standard regulatory notifications and approvals.

We cannot predict whether the terms of the potential transaction will be agreed upon by Enbridge and the Board’s conflicts committee for recommendation to their respective boards of directors, and with respect to the Partnership, additionally to its general partner, for approval of the transaction, or whether any such transactions would be approved by the requisite votes of unitholders of the Partnership.

As a result, we also cannot predict the timing, final structure or other terms of any potential transaction, and the terms of any such transaction may differ materially from those originally proposed by Enbridge. Any decrease in the market prices of Enbridge’s common shares would result in a corresponding proportional decrease in the value of the Enbridge common shares the unitholders of the Partnership would receive in the event the proposed transactions were consummated on the terms proposed by Enbridge. Any changes in the market prices of Enbridge’s common shares or the common units of the Partnership could affect whether the proposed transaction is ultimately approved, or if such approval is granted, the terms on which the proposed transactions are approved.



Item 6.	Exhibits.

Any agreements included as exhibits to this Form 10-Q may 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:


•	were not intended to 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;


•	may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement;


•	may apply contract standards of “materiality” that are different from “materiality” under the applicable securities laws; 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.

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.

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(a) Exhibits
Exhibit Number

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

*31.2		Certification 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.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase.

*101.LAB		XBRL Taxonomy Extension Label Linkbase.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase.



*	Filed herewith

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the SEC, to furnish copies of any or all of such instruments to it.

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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 3, 2018	By:	/S/ William T. Yardley
		William T. Yardley President and Chairman of the Board

Date: August 3, 2018	By:	/S/ Stephen J. Neyland
		Stephen J. Neyland Vice President—Finance