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 September 30, 2018
or
¨ 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
 
 
 
 
 
seplogoa02.jpg 
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 every Interactive Data File required to be submitted 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 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 October 30, 2018, there were 484,896,871 common units outstanding.
 
 
 
 
 


SPECTRA ENERGY PARTNERS, LP
FORM 10-Q FOR THE QUARTER ENDED
September 30, 2018
INDEX
 
 
 
 
 
Page
 
 
 
 
Item 1.
 
 
 
 
 
 
Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
 
 
Item 3.
 
 
 
 
 
Item 4.
 
 
 
 
 
 
 
 
 
 
Item 1.
 
 
 
 
 
Item 1A.
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
 
 
 
 
 
 
 

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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, including with respect to the transactions contemplated by the Agreement and Plan of Merger, dated August 24, 2018, among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP (SEP GP), Enbridge Inc. (Enbridge), Enbridge (U.S.) Inc. (EUS), Autumn Acquisition Sub, LLC, and, solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc., Spectra Energy Corp, Spectra Energy Capital, LLC and Spectra Energy Transmission, LLC (the Proposed Merger). 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, including the Proposed Merger;
•
the risk that Enbridge may be unable to obtain governmental and regulatory approvals required for the Proposed Merger or required governmental and regulatory approvals may delay the Proposed Merger or result in the imposition of conditions that could cause the parties to abandon the Proposed Merger;
•
the risk that a condition to closing of the Proposed Merger may not be satisfied;
•
the timing to complete the Proposed Merger;

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•
the ability to realize expected cost savings, benefits and any other synergies from the Proposed Merger and the proposed simplification of Enbridge’s overall corporate structure may not be fully realized or may take longer to realize than expected;
•
disruption from the Proposed Merger may make it more difficult to maintain relationships with customers, employees or suppliers; and
•
the impact and outcome of pending and future litigation, including litigation, if any, relating to the Proposed Merger.
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
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
Operating revenues
 
 
 
 
 
 
 
 
Transportation of natural gas
 
$
581

 
$
541

 
$
1,770

 
$
1,617

Transportation of crude oil
 
102

 
94

 
297

 
295

Storage of natural gas and other
 
54

 
58

 
175

 
176

Total operating revenues
 
737

 
693

 
2,242

 
2,088

Operating expenses
 
 
 
 
 
 
 
 
Operating, maintenance and other
 
227

 
197

 
606

 
633

Depreciation and amortization
 
89

 
86

 
268

 
258

Property and other taxes
 
54

 
36

 
173

 
148

Total operating expenses
 
370

 
319

 
1,047

 
1,039

Operating income
 
367

 
374

 
1,195

 
1,049

Other income and expenses
 
 
 
 
 
 
 
 
Earnings from equity investments
 
81

 
161

 
210

 
239

Other income and expenses, net
 
17

 
15

 
51

 
109

Total other income and expenses
 
98

 
176

 
261

 
348

Interest expense
 
85


75


255


191

Earnings before income taxes
 
380

 
475

 
1,201

 
1,206

Income tax expense
 
3


4


15


14

Net income
 
377

 
471

 
1,186

 
1,192

Net income attributable to noncontrolling interests
 
11


11


32


87

Net income attributable to controlling interests
 
$
366

 
$
460

 
$
1,154

 
$
1,105

 
 
 
 
 
 
 
 
 
Net income attributable to controlling interests
 
$
366

 
$
460

 
$
1,154

 
$
1,105

Net income attributable to general partner
 
—

 
101

 
—

 
284

Net income attributable to limited partners
 
$
366

 
$
359

 
$
1,154

 
$
821

Weighted average limited partner units outstanding—basic and diluted
 
485

 
311

 
472

 
310

Net income per limited partner unit—basic and diluted
 
$
0.75

 
$
1.15

 
$
2.44

 
$
2.65

Distributions paid per limited partner unit
 
$
0.76375

 
$
0.71375

 
$
2.25375

 
$
2.10375

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
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
Net income
 
$
377

 
$
471

 
$
1,186

 
$
1,192

Other comprehensive income:
 
 
 
 
 
 
 
 
Foreign currency translation adjustments
 
6

 
8

 
(8
)
 
15

General partner units restructuring
 
—

 
—

 
(3
)
 
—

Change in unrealized gain (loss) on cash flow hedges
 
12

 
(3
)
 
47

 
(3
)
Other comprehensive income
 
18

 
5

 
36

 
12

Comprehensive income
 
395

 
476

 
1,222

 
1,204

Comprehensive income attributable to noncontrolling interests
 
11

 
11

 
32

 
87

Comprehensive income attributable to controlling interests
 
$
384

 
$
465

 
$
1,190

 
$
1,117

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)
 
 
September 30,
2018
 
December 31,
2017
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
156

 
$
107

Receivables (net of allowance for doubtful accounts of $16 and $10 at September 30, 2018 and December 31, 2017, respectively)
 
322

 
372

Inventory
 
55

 
40

Fuel Tracker
 
114

 
19

Other assets, net
 
48

 
23

Total current assets
 
695

 
561

Investments in and loans to unconsolidated affiliates
 
3,101

 
3,302

Goodwill
 
2,954

 
2,957

Property, plant and equipment, net
 
15,322

 
14,899

Regulatory and other assets
 
339

 
337

Total assets
 
$
22,411

 
$
22,056

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
249

 
$
259

Taxes payable
 
101

 
84

Interest payable
 
45

 
68

Current portion of long-term debt
 
—

 
500

Natural gas imbalance payables
 
49

 
80

Collateral liabilities
 
41

 
39

Other
 
72

 
75

Total current liabilities
 
557

 
1,105

Loan from affiliate
 
638

 
—

Long-term debt
 
8,157

 
7,963

Deferred income taxes
 
47

 
46

Regulatory and other liabilities
 
1,010

 
1,041

Total liabilities
 
10,409

 
10,155

Commitments and contingencies
 
 
 
 
Partners’ capital
 
 
 
 
Common units (484.9 and 312.4 units issued and outstanding at September 30, 2018 and December 31, 2017, respectively)
 
11,641

 
11,183

General partner units (no units and 6.4 units issued and outstanding at September 30, 2018 and December 31, 2017, respectively)
 
—

 
386

Accumulated other comprehensive income (loss)
 
3

 
(33
)
Total partners’ capital
 
11,644

 
11,536

Noncontrolling interests
 
358

 
365

Total equity
 
12,002

 
11,901

Total liabilities and equity
 
$
22,411

 
$
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)
 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
 
 
 
OPERATING ACTIVITIES
 
 
 
 
Net income
 
$
1,186

 
$
1,192

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
278

 
255

Deferred income tax expense
 
1

 
2

Earnings from equity investments
 
(210
)
 
(239
)
Distributions from equity investments
 
153

 
105

Regulatory liability - deferred income taxes
 
(25
)
 
—

Change in operating assets and liabilities
 
(126
)
 
(174
)
Net cash provided by operating activities
 
1,257

 
1,141

INVESTING ACTIVITIES
 
 
 
 
Capital expenditures
 
(680
)
 
(1,592
)
Investments in and loans to unconsolidated affiliates
 
(520
)
 
(218
)
Purchase of intangible, net
 
—

 
(40
)
Distributions from equity investments
 
39

 
27

Distribution from Sabal Trail debt proceeds
 
744

 
—

Net cash outflow from deconsolidation of Sabal Trail
 
—

 
(67
)
Other
 
3

 
1

Net cash used in investing activities
 
(414
)
 
(1,889
)
FINANCING ACTIVITIES
 
 
 
 
Proceeds from the issuance of long-term debt
 
794

 
400

Payments for the redemption of long-term debt
 
(500
)
 
(816
)
Borrowings from affiliate
 
638

 
—

Net change in credit facility draws and commercial paper borrowings
 
(589
)
 
1,459

Distributions to noncontrolling interests
 
(40
)
 
(37
)
Contributions from noncontrolling interests
 
1

 
416

Proceeds from the issuances of units
 
—

 
115

Distributions to partners
 
(1,092
)
 
(907
)
Other
 
(11
)
 
(1
)
Net cash provided by (used in) financing activities
 
(799
)
 
629

Net increase (decrease) in Cash, cash equivalents and restricted cash
 
44

 
(119
)
Cash, cash equivalents and restricted cash at beginning of period
 
114

 
233

Cash, cash equivalents and restricted cash at end of period
 
$
158

 
$
114

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)
December 31, 2017
 
$
11,183

 
$
386

 
$
(33
)
 
$
365

 
$
11,901

Net income
 
1,154

 
—

 
—

 
32

 
1,186

General partner units restructuring
 
389

 
(386
)
 
(3
)
 
—

 
—

Other comprehensive income
 
—

 
—

 
39

 
—

 
39

Attributed deferred tax benefit
 
11

 
—

 
—

 
—

 
11

Incentive distribution rights restructuring legal fees
 
(4
)
 
—

 
—

 
—

 
(4
)
Distributions to partners
 
(1,092
)
 
—

 
—

 
—

 
(1,092
)
Contributions from noncontrolling interests
 
—

 
—

 
—

 
1

 
1

Distributions to noncontrolling interests
 
—

 
—

 
—

 
(40
)
 
(40
)
September 30, 2018
 
$
11,641

 
$
—

 
$
3

 
$
358

 
$
12,002

 
 
 
 
 
 
 
 
 
 
 
December 31, 2016
 
$
11,650

 
$
452

 
$
(45
)
 
$
1,347

 
$
13,404

Net income
 
821

 
284

 
—

 
87

 
1,192

Other comprehensive income
 
—

 
—

 
12

 
—

 
12

Attributed deferred tax benefit
 
—

 
55

 
—

 
—

 
55

Issuances of units
 
113

 
2

 
—

 
—

 
115

Distributions to partners
 
(651
)
 
(256
)
 
—

 
—

 
(907
)
Contributions from noncontrolling interests
 
—

 
—

 
—

 
416

 
416

Distributions to noncontrolling interests
 
—

 
—

 
—

 
(37
)
 
(37
)
Sabal Trail deconsolidation
 
—

 
—

 
—

 
(1,440
)
 
(1,440
)
September 30, 2017
 
$
11,933

 
$
537

 
$
(33
)
 
$
373

 
$
12,810

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” and “us” 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 SEP.

Nature of Operations. SEP, 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 September 30, 2018, Enbridge and its subsidiaries collectively owned 83% of us and the remaining 17% was publicly owned. Enbridge owns and controls our general partner, 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:
 
 
September 30, 2018
 
December 31, 2017
 
September 30, 2017
 
December 31, 2016
 
(in millions)
Cash and cash equivalents
 
$
156

 
$
107

 
$
107

 
$
216

Restricted cash in Other assets, net
 
1

 
3

 
5

 
3

Restricted cash in Regulatory and other assets
 
1

 
4

 
2

 
14

Cash, cash equivalents and restricted cash
 
$
158

 
$
114

 
$
114

 
$
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 Statements 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.

Future Accounting Policy Changes

Amended Guidance on Cloud Computing Arrangements

In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity

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would apply ASC 350-40 to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require that capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.
Disclosure Effectiveness
In August 2018, the Financial Accounting Standards Board (FASB) issued amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements.

ASU 2018-13 was issued to modify the disclosure requirements in ASC 820, Fair Value Measurement. The amendments in ASU 2018-13 eliminate and modify some disclosures, while also adding new disclosures for fair value measurements. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified current disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements.
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 FASB 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 also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under ASC 840 continue to meet the definition of initial direct costs under the new guidance.
 

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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.

In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however we continue to evaluate the lessor practical expedient to combine lease and nonlease components.

We have developed a preliminary inventory of existing lease agreements and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our statement of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard.

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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 September 30, 2018
 
 
 
 
 
U.S. Transmission
$
633

 
$
81

 
$
503

Liquids
104

 
8

 
59

Total reportable segments
737

 
89

 
562

Other
—

 
—

 
(6
)
Depreciation and amortization
—

 
—

 
89

Interest expense
—

 
—

 
85

Interest income and other
—

 
—

 
(2
)
Total consolidated
$
737

 
$
89

 
$
380

 
 
 
 
 
 
Three Months Ended September 30, 2017
 
 
 
 
 
U.S. Transmission
$
595

 
$
78

 
$
589

Liquids
98

 
8

 
67

Total reportable segments
693

 
86

 
656

Other
—

 
—

 
(21
)
Depreciation and amortization
—

 
—

 
86

Interest expense
—

 
—

 
75

Interest income and other
—

 
—

 
1

Total consolidated
$
693

 
$
86

 
$
475

 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
U.S. Transmission
$
1,928

 
$
244

 
$
1,530

Liquids
314

 
24

 
201

Total reportable segments
2,242

 
268

 
1,731

Other
—

 
—

 
(9
)
Depreciation and amortization
—

 
—

 
268

Interest expense
—

 
—

 
255

Interest income and other
—

 
—

 
2

Total consolidated
$
2,242

 
$
268

 
$
1,201

 
 
 
 
 
 
Nine Months Ended September 30, 2017
 
 
 
 
 
U.S. Transmission
$
1,783

 
$
234

 
$
1,548

Liquids
305

 
24

 
197

Total reportable segments
2,088

 
258

 
1,745

Other
—

 
—

 
(92
)
Depreciation and amortization
—

 
—

 
258

Interest expense
—

 
—

 
191

Interest income and other
—

 
—

 
2

Total consolidated
$
2,088

 
$
258

 
$
1,206


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4. Revenue from Contracts with Customers
Major Products and Services
 
 
U.S. Transmission
 
Liquids
 
Consolidated
 
 
(in millions)
Three Months Ended September 30, 2018
 
 
 
 
 
 
Transportation of natural gas
 
$
581

 
$
—

 
$
581

Transportation of crude oil
 
—

 
102

 
102

Storage of natural gas
 
49

 
2

 
51

Total revenue from contracts with customers
 
630

 
104

 
734

Other revenue
 
3

 
—

 
3

Total revenue
 
$
633

 
$
104

 
$
737

 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
Transportation of natural gas
 
$
1,770

 
$
—

 
$
1,770

Transportation of crude oil
 
—

 
297

 
297

Storage of natural gas
 
151

 
17

 
168

Total revenue from contracts with customers
 
1,921

 
314

 
2,235

Other revenue
 
7

 
—

 
7

Total revenue
 
$
1,928

 
$
314

 
$
2,242

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
 
266

 
—

 
66

Contract liabilities primarily relate to deferred revenue. There were no material changes in contract liabilities during the three and nine months ended September 30, 2018.
Recognition and Measurement of Revenue
 
 
U.S. Transmission
 
Liquids
 
Consolidated
 
 
(in millions)
Three Months Ended September 30, 2018
 
 
 
 
 
 
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage
 
$
630

 
$
104

 
$
734

 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage
 
$
1,921

 
$
314

 
$
2,235

Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $21.5 billion, of which $0.6 billion and $2.5 billion is expected to be recognized during the remaining three 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
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions, except per unit amounts)
Net income attributable to controlling interests
 
$
366

 
$
460

 
$
1,154

 
$
1,105

Less: Net income attributable to:
 
 
 
 
 
 
 
 
General partner’s interest in general partner units—2% (a)
 
—

 
10

 
—

 
23

General partner’s interest in incentive distribution rights (a)
 
—

 
91

 
—

 
261

Limited partners’ interest in net income attributable to common units
 
$
366

 
$
359

 
$
1,154

 
$
821

Weighted average limited partner units outstanding—basic and diluted
 
485

 
311

 
472

 
310

Net income per limited partner unit—basic and diluted
 
$
0.75

 
$
1.15

 
$
2.44

 
$
2.65

______________
(a)
General partner units and incentive distribution rights (IDRs) were converted to common units of SEP 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 issued debt and made distributions to its members. These events triggered reconsideration and it was concluded that Sabal Trail is no longer a variable interest entity (VIE) due to Sabal Trail having sufficient equity at risk to finance its activities.


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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 $1.2 billion and $640 million as of September 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 $280 million. We have an investment in PennEast of $69 million and $55 million as of September 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 $4 million and $3 million of AFS securities classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively. At September 30, 2018 and December 31, 2017, these investments include $4 million and $3 million, respectively, 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 September 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 September 30, 2018 or December 31, 2017.
HTM Securities. All of our HTM securities are restricted funds. We had $1 million and $3 million of money market securities classified as Other assets, net on the Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017, respectively. These securities are restricted pursuant to certain Express-Platte pipeline system debt agreements.
At September 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 September 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 $1 million and $4 million classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets at September 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

 
$
1,665

 
$
835

______________
(a)    Includes $336 million of commitments that expire in 2021.
(b)    Includes credit facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes
our unsecured revolving 364-day credit agreement with EUS.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of September 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 a long-term committed credit facility and therefore has been classified as long-term debt as of September 30, 2018 and December 31, 2017, respectively.
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 agreement may result if we were to default on payment or violate certain covenants. As of September 30, 2018, we were in compliance with those covenants.
The EUS 364-day Credit Facility. On September 5, 2018, we entered into an unsecured revolving 364-day credit agreement (the EUS 364-day Credit Facility) with EUS, as lender. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility with revolving commitments of $750 million. As of September 30, 2018, we had $638 million outstanding under this facility, excluding any accrued interest to date. This facility is classified as a long-term obligation since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.

See Part II Item 5 Other Information for a further description of the EUS 364-day Credit Facility.
Debt Issuances. On January 9, 2018, Texas Eastern Transmission, LP (Texas Eastern), an indirect subsidiary of SEP, 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 September 30, 2018 and December 31, 2017:
Description
Condensed Consolidated Balance Sheet Caption
 
September 30, 2018
Total
 
Level 1
 
Level 2
 
Level 3
 
 
 
(in millions)
Interest rate swaps
Other assets, net
 
$
30

 
$
—

 
$
30

 
$
—

Commodity swaps
Other assets, net
 
1

 
—

 
—

 
1

Canadian equity securities
Regulatory and other assets
 
4

 
4

 
—

 
—

Interest rate swaps
Regulatory and other assets
 
10

 
—

 
10

 
—

Total Assets
 
$
45

 
$
4

 
$
40

 
$
1

 
 
 

 
 
 
 
 
 
Interest rate swaps
Current liabilities — other
 
$
7

 
$
—

 
$
7

 
$
—

Interest rate swaps
Regulatory and other liabilities
 
3

 
—

 
3

 
—

Total Liabilities
 
$
10

 
$
—

 
$
10

 
$
—

Description
Condensed Consolidated Balance Sheet Caption
 
December 31, 2017
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.
 
 
September 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)
 
6,150

 
6,204

 
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, loan from affiliate, 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
Our earnings, cash flows and other comprehensive income are subject to movements in foreign exchange rates, interest rates and commodity prices (collectively, market risk). 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. Formal risk management policies, processes and systems have been designed to mitigate these risks. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks.

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 reduce 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:
 
September 30, 2018
 
December 31, 2017
Description
Gross Amounts
Presented in
the Condensed
Consolidated
Balance Sheet
 
Amounts  Available for Offset
 
Net
Amount
 
Gross Amounts
Presented in
the Consolidated
Balance Sheet
 
Amounts  Available for Offset
 
Net
Amount
 
(in millions)
Assets
$
40

 
$
—

 
$
40

 
$
4

 
$
(1
)
 
$
3

Liabilities
(10
)
 
—

 
(10
)
 
(8
)
 
1

 
(7
)


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Fair Value Hedges
At September 30, 2018, we had “pay floating - receive fixed” interest rate swaps outstanding with a total notional amount of $450 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 nine months ended September 30, 2018, the amounts recognized were an $8 million loss on the fair value hedges and an 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 with an average swap rate of 2.6%. The information of these cash flow swaps are presented as follows:
 
 
 
 
Fair Value at
Date of Maturity & Contract Type
 
Notional Amount
 
September 30, 2018
 
December 31, 2017
 
 
(in millions)
Contracts maturing in 2018
 
$
560

 
$
30

 
$
1

Contracts maturing in 2020
 
250

 
10

 
(3
)
We estimate that $3 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 (loss) recognized in Other Comprehensive Income
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
2018
 
2017
 
2018
 
2017
 
(in millions)
Cash flow hedges - interest rate swaps
$
12

 
$
(3
)
 
$
47

 
$
(3
)

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 included in Operating, maintenance and other on the Condensed Consolidated Statements of Income during both the three and nine months ended September 30, 2018, and hedge assets of $1 million included in Other assets, net and Regulatory and other assets on the Condensed Consolidated Balance Sheets at September 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 September 30, 2018 was $129 million. These performance guarantees expire in 2032.
As of September 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.

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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 September 30, 2018 and 2017, we reported net income attributable to controlling interests of $366 million and $460 million, respectively. Key highlights for the three months ended September 30, 2018 include increased earnings driven by natural gas pipeline expansions, increased revenue contracts on Sabal Trail, and higher allowance for funds used during construction (AFUDC) on NEXUS, offset by the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017, higher operating and pipeline integrity costs and higher allocated corporate shared-service costs.
For the nine months ended September 30, 2018 and 2017, we reported net income attributable to controlling interests of $1.2 billion and $1.1 billion, respectively. Key highlights for the nine months ended September 30, 2018 include increased earnings driven by natural gas pipeline expansions, equity earnings from Sabal Trail being placed into service, higher AFUDC on NEXUS, and an adjustment recorded in the first quarter of 2018 related to the established regulatory liability resulting from the 2017 U.S. tax reform legislation, partially offset by the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017, and lower AFUDC due to Sabal Trail being placed into service.
For the three months ended September 30, 2018 and 2017, Distributable Cash Flow was $359 million and $363 million, respectively. For the nine months ended September 30, 2018 and 2017, Distributable Cash Flow was $1.2 billion and $1.1 billion, respectively. A cash distribution of $0.77625 per limited partner unit was declared on November 1, 2018 and is payable on November 29, 2018. The declaration and payment of distributions 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 nine months ended September 30, 2018, we had $1.2 billion 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 September 30, 2018, we had access to approximately $0.8 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. We also have access to $112 million borrowing capacity in the EUS 364-day Credit Facility with aggregate borrowings of up to $750 million.
Proposed Merger
On August 24, 2018, we announced our entry into a definitive agreement (the Merger Agreement) with respect to the Proposed Merger, pursuant to which an indirect wholly-owned subsidiary of Enbridge will be merged with and into SEP, with SEP surviving as an indirect wholly-owned subsidiary of Enbridge. Under the terms of the Merger Agreement, at the effective time of the Proposed Merger, Enbridge will acquire all of our outstanding common units not already directly or indirectly owned by Enbridge in an all stock-for-unit transaction at a ratio of 1.111 Enbridge common shares per SEP common unit (the Agreed Exchange Ratio), in a taxable transaction to our common unitholders. The Agreed Exchange Ratio represents an approximately 9.8% increase to the exchange ratio of 1.0123 Enbridge common shares per SEP common unit that was initially offered by SEP to Enbridge on May 17, 2018. The Proposed Merger is part of Enbridge’s sponsored vehicle restructuring initiative to simplify its corporate structure.
The completion of the Proposed Merger is subject to certain customary closing conditions, including (i) receipt of approval of the Merger Agreement by written consent of the limited partners of SEP holding SEP common units constituting at least a majority of the outstanding SEP common units entitled to vote as of the close of business on

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November 5, 2018, the record date for determining the unitholders entitled to vote on the Proposed Merger (ii) the Enbridge common stock issuable in connection with the Proposed Merger having been approved for listing on the New York Stock Exchange (NYSE) and the Toronto Stock Exchange, subject to official notice of issuance, (iii) the absence of any governmental order prohibiting the consummation of the Proposed Merger or the other transactions contemplated thereby, and (iv) Enbridge’s registration statement on Form S-4 having become effective under the Securities Act of 1933, as amended (the Securities Act). The obligation of each party to the Merger Agreement to consummate the Proposed Merger is also conditioned upon the accuracy of the representations and warranties of the other parties as of the date of the Merger Agreement and as of the closing (subject to customary materiality qualifiers), the performance by the other parties of all obligations under the Merger Agreement at or prior to closing and receipt of an officer’s certificate evidencing the satisfaction of the foregoing.
As a result of the completion of the Proposed Merger, our common units will no longer be publicly traded. All of our outstanding debt is expected to remain outstanding. Subject to the satisfaction or waiver of certain conditions, including the unitholder approval, the Proposed Merger is targeted to close in fourth quarter of 2018.
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 an 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 the FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. These FERC announcements have negatively affected MLPs generally.
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. 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 respect 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 are expected to approximately 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.

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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 U.S. 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
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions)
Operating revenues
 
$
737

 
$
693

 
$
2,242

 
$
2,088

Operating expenses
 
370

 
319

 
1,047

 
1,039

Operating income
 
367

 
374

 
1,195

 
1,049

Earnings from equity investments
 
81

 
161

 
210

 
239

Other income and expenses, net
 
17

 
15

 
51

 
109

Interest expense
 
85

 
75

 
255

 
191

Earnings before income taxes
 
380

 
475

 
1,201

 
1,206

Income tax expense
 
3

 
4

 
15

 
14

Net income
 
377

 
471

 
1,186

 
1,192

Net income—noncontrolling interests
 
11

 
11

 
32

 
87

Net income—controlling interests
 
$
366

 
$
460

 
$
1,154

 
$
1,105

Three Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $44 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, and
•
an increase in transportation volumes.
Operating expenses. The $51 million increase was driven mainly by:
•
an increase in repair and maintenance costs and higher pipeline integrity costs,
•
an increase in property taxes, higher regulatory expenses and allocated corporate costs and
•
an increase in electric power and other costs passed through to gas transmission customers, partially offset by
•
a decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident near Delmont, Pennsylvania.
Earnings from equity investments. The $80 million decrease was mainly attributable to the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017, partially offset by equity earnings from Sabal Trail as a result of additional revenue contracts and higher AFUDC related to NEXUS in 2018. Upon the commencement of commercial service of Sabal Trail, we deconsolidated our investment and began accounting for it under the equity method. All earnings from Sabal Trail are now recorded within one line called Earnings from equity investments.
Interest expense. The $10 million increase was mainly attributable to an increase in interest rates related to short-term borrowings and a higher balance of long-term debt outstanding during the three months ended September 30, 2018 than the same period in 2017.

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Nine Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $154 million increase was driven mainly by:
•
an increase due to expansion projects primarily on Texas Eastern and Algonquin,
•
an increase in recoveries of electric power and other costs passed through to gas transmission customers,
•
an increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform and
•
an increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by
•
a decrease in storage revenues mainly due to lower rates associated with contract renewals and
•
a decrease in revenue from Sabal Trail due to a change in accounting treatment as discussed above. During the second quarter of 2017, we received contributions from Sabal Trail prior to its in-service date which were recorded in operating revenues.
Operating expenses. The $8 million increase was driven mainly by:
•
an increase in recoveries of electric power and other costs passed through to gas transmission customers,
•
an increase in repair and maintenance costs and higher pipeline integrity costs,
•
an increase in property taxes and regulatory expenses and
•
an increase in costs related to expansion, partially offset by
•
a decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident and
•
a decrease due to 2017 merger-related severance costs.
Earnings from equity investments. The $29 million decrease was mainly attributable to the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017, partially offset by equity earnings from Sabal Trail as a result of being placed in service and higher AFUDC related to NEXUS in 2018.
Other income and expenses, net. The $58 million decrease was mainly attributable to lower AFUDC due to Sabal Trail being placed into service.
Interest expense. The $64 million increase was mainly attributable to lower capitalized interest due to Sabal Trail being placed into service, an increase in interest rates related to short-term borrowings, and a higher balance of long-term debt outstanding during the nine months ended September 30, 2018 compared to the same period in 2017.
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.

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Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions)
U.S. Transmission
 
$
503

 
$
589

 
$
1,530

 
$
1,548

Liquids
 
59

 
67

 
201

 
197

Total reportable segment EBITDA
 
562

 
656

 
1,731

 
1,745

Other
 
(6
)
 
(21
)
 
(9
)
 
(92
)
Depreciation and amortization
 
89

 
86

 
268

 
258

Interest expense
 
85

 
75

 
255

 
191

Interest income and other
 
(2
)
 
1

 
2

 
2

Earnings before income taxes
 
$
380

 
$
475

 
$
1,201

 
$
1,206

The amounts discussed below are after eliminating intercompany transactions.
U.S. Transmission
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
Increase (Decrease)
 
2018
 
2017
 
Increase (Decrease)
 
 
(in millions)
Operating revenues
 
$
633


$
595

 
$
38

 
$
1,928


$
1,783

 
$
145

Operating expenses
 




 
 
 



 
 
     Operating, maintenance and other
 
230


181

 
49

 
656


582

 
74

Other income/(expense)
 
100


175

 
(75
)
 
258


347

 
(89
)
EBITDA
 
$
503

 
$
589

 
$
(86
)
 
$
1,530

 
$
1,548

 
$
(18
)
Three Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $38 million increase was driven by:
•
a $29 million increase due to expansion projects primarily on Texas Eastern and Algonquin,
•
an $11 million increase in recoveries of electric power and other costs passed through to gas transmission customers and
•
a $6 million increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by
•
a $4 million decrease in storage revenues mainly due to lower rates associated with contract renewals.
Operating, maintenance and other. The $49 million increase was driven by:
•
a $23 million increase in repair and maintenance costs and higher pipeline integrity costs,
•
an $18 million increase primarily due to allocated corporate shared-service costs previously reported in "Other",
•
an $11 million increase in electric power and other costs passed through to gas transmission customers and
•
an $11 million increase in property tax accrual, partially offset by
•
an $18 million decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident.

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Other income and expenses. The $75 million decrease was driven by:
•
a $106 million decrease as a result of the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017, partially offset by
•
a $24 million increase in equity earnings mainly due to additional revenue contracts on Sabal Trail and higher AFUDC related to NEXUS in 2018 and
•
a $5 million increase due to corporate allocations of pension costs.
Nine Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $145 million increase was driven by:
•
a $94 million increase due to expansion projects primarily on Texas Eastern and Algonquin,
•
a $30 million increase in recoveries of electric power and other costs passed through to gas transmission customers,
•
a $25 million increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform and
•
a $22 million increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by
•
a $12 million decrease in storage revenues mainly due to lower rates associated with contract renewals and
•
a $10 million decrease from Sabal Trail due to a change in accounting treatment as previously discussed.
Operating, maintenance and other. The $74 million increase was driven by:
•
a $43 million increase primarily due to allocated corporate shared-service costs previously reported in "Other",
•
a $30 million increase in electric power and other costs passed through to gas transmission customers,
•
a $25 million increase in repair and maintenance costs and higher pipeline integrity costs,
•
an $11 million increase in property tax accrual and
•
an $11 million increase in costs related to expansion, partially offset by
•
a $31 million decrease due to pipeline inspection and repair costs incurred in 2017 related to the 2016 Texas Eastern pipeline incident and
•
a $14 million decrease due to 2017 merger-related severance costs.
Other income and expenses. The $89 million decrease was driven by:
•
a $106 million decrease as a result of the remeasurement gain recognized from the deconsolidation of Sabal Trail in 2017 and
•
a $78 million decrease in equity AFUDC due to Sabal Trail being placed into service, partially offset by
•
a $76 million increase mainly due to higher equity earnings from Sabal Trail being placed into service and higher AFUDC related to NEXUS in 2018 and
•
a $16 million increase due to corporate allocations of pension costs.

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Liquids
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
Increase (Decrease)
 
2018
 
2017
 
Increase (Decrease)
 
 
(in millions)
Operating revenues
 
$
104


$
98

 
$
6

 
$
314


$
305

 
$
9

Operating expenses
 



 
 
 



 
 
     Operating, maintenance and other
 
45


28

 
17

 
114


104

 
10

Other income/(expense)
 
—


(3
)
 
3

 
1


(4
)
 
5

EBITDA
 
$
59

 
$
67

 
$
(8
)
 
$
201

 
$
197

 
$
4

Express pipeline revenue receipts, MBbl/d (a)
 
259


255

 
4

 
261


260

 
1

Platte PADD II deliveries, MBbl/d (a)
 
123


119

 
4

 
129


133

 
(4
)
______________
(a)    Thousand barrels per day.
Three Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $6 million increase in operating revenues was mainly driven by an increase in transportation volumes.
Operating, maintenance and other. The $17 million increase in operating expenses was mainly driven by an increase in property taxes, higher regulatory expenses and allocated corporate costs.
Nine Months Ended September 30, 2018 Compared to Same Period in 2017
Operating revenues. The $9 million increase in operating revenues was mainly driven by an increase in inventory settlement.
Operating, maintenance and other. The $10 million increase in operating expenses was mainly driven by an increase in property taxes and regulatory expenses.
Other income and expenses. The $5 million increase in other income was due to a loss on disposal of assets in 2017.
Other
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
Increase (Decrease)
 
2018
 
2017
 
Increase (Decrease)
 
 
(in millions)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
 
     Operating, maintenance and other
 
$
6

 
$
21

 
$
(15
)
 
$
9

 
$
92

 
$
(83
)
EBITDA
 
$
(6
)
 
$
(21
)
 
$
15

 
$
(9
)
 
$
(92
)
 
$
83

Three Months Ended September 30, 2018 Compared to Same Period in 2017
Operating, maintenance and other. The $15 million decrease was primarily due to lower allocated corporate shared-service costs previously recorded in "Other".
Nine Months Ended September 30, 2018 Compared to Same Period in 2017
Operating, maintenance and other. The $83 million decrease was driven by:
•
a $49 million decrease due to lower allocated corporate shared-service costs previously recorded in "Other" and
•
a $34 million decrease due to 2017 merger-related severance costs.

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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
September 30,
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
2018
 
2017
 
 
(in millions)
Net income
 
$
377

 
$
471

 
$
1,186

 
$
1,192

Add:
 
 
 
 
 
 
 
 
Interest expense
 
85

 
75

 
255

 
191

Income tax expense
 
3

 
4

 
15

 
14

Depreciation and amortization
 
89

 
86

 
268

 
258

Foreign currency (gain) loss
 
2

 
(1
)
 
(1
)
 
(1
)
Less:
 
 
 
 
 
 
 
 
Third party interest income
 
—

 
—

 
1

 
1

EBITDA
 
556

 
635

 
1,722

 
1,653

Add:
 
 
 
 
 
 
 
 
Earnings from equity investments
 
(81
)
 
(161
)
 
(210
)
 
(239
)
Distributions from equity investments
 
57

 
54

 
192

 
132

Non-cash impact of the U.S. Tax Reform
 
—

 
—

 
(25
)
 
—

Other
 
9

 
9

 
6

 
9

Less:
 
 
 
 
 
 
 
 
Interest expense
 
85

 
75

 
255

 
191

Equity AFUDC
 
14

 
14

 
29

 
107

Net cash paid for income taxes
 
1

 
4

 
6

 
12

Distributions to noncontrolling interests
 
12

 
12

 
40

 
37

Maintenance capital expenditures
 
70

 
69

 
145

 
148

Distributable Cash Flow
 
$
359

 
$
363

 
$
1,210

 
$
1,060

LIQUIDITY AND CAPITAL RESOURCES
As of September 30, 2018, we had working capital of $138 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 $2.5 billion multi-year unsecured revolving credit facility, with available capacity of $835 million at September 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.
On September 5, 2018, we entered into the EUS 364-day Credit Facility which is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to $750 million. At September 30, 2018, we had approximately $112 million in available credit under the terms of this credit facility. This facility is used principally 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 facilities 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:
 
 
Nine Months Ended
September 30,
 
 
2018
 
2017
 
 
(in millions)
Net cash provided by (used in):
 
 
 
 
Operating activities
 
$
1,257

 
$
1,141

Investing activities
 
(414
)
 
(1,889
)
Financing activities
 
(799
)
 
629

Net increase (decrease) in Cash, cash equivalents and restricted cash
 
44

 
(119
)
Cash, cash equivalents and restricted cash at beginning of the period
 
114

 
233

Cash, cash equivalents and restricted cash at end of the period
 
$
158

 
$
114

Operating Cash Flows
Net cash provided by operating activities increased $116 million to $1,257 million in the nine months ended September 30, 2018 compared to the same period in 2017, driven mainly by higher earnings and higher distributions from equity investments as a result of the positive operating factors discussed in Results of Operations and changes in working capital.
Investing Cash Flows
Net cash used in investing activities decreased $1,475 million to $414 million in the nine months ended September 30, 2018 compared to in the same period in 2017. The change was mainly driven by:
•
a decrease of $912 million in capital expenditures primarily due to Sabal Trail being placed in-service in July 2017,
•
a $744 million distribution received from Sabal Trail in the second quarter of 2018 as a partial return of capital for construction and development costs,
•
a net cash outflow of $67 million resulting from change in accounting treatment of Sabal Trail in 2017 as previously discussed in Results of Operations and
•
$40 million in payments related to the purchase of intangibles during 2017, partially offset by
•
a $302 million increase in investments in and loans to unconsolidated affiliates mainly due to increased investment in NEXUS.
 
 
Nine Months Ended
September 30,
Capital and Investment Expenditures by Business Segment
 
2018
 
2017
 
 
(in millions)
U.S. Transmission
 
$
1,161

 
$
1,794

Liquids
 
39

 
16

Total consolidated
 
$
1,200

 
$
1,810

Capital and investment expenditures for the nine months ended September 30, 2018 consisted of $1.1 billion for expansion projects and $145 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 $799 million in the nine months ended September 30, 2018 compared to $629 million provided by financing activities in the same period in 2017. The change was mainly driven by:
•
$589 million of repayments of the credit facility in 2018 compared to $1,459 million of issuances of the 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 $185 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
•
a $115 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 $316 million decrease in payments for the redemption of long-term debt,
•
$638 million of borrowings under the EUS 364-day Credit Facility in September 2018 and
•
$394 million in proceeds from the issuance of Texas Eastern 3.50% senior notes in January 2018.
Available Credit Facilities 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 September 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 facilities and related financial and other covenants.
Cash Distributions. A cash distribution of $0.77625 per limited partner unit was declared on November 1, 2018, payable on November 29, 2018.
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 September 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 September 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 September 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.

On August 24, 2018, Enbridge announced that it (on behalf of itself and certain of its wholly owned U.S. subsidiaries) had entered into a definitive merger agreement with us under which Enbridge would acquire, subject to certain conditions, all of the outstanding common units of SEP (other than those held by Enbridge and its wholly owned subsidiaries). If the Proposed Merger closes and Enbridge acquires all of the outstanding common units of SEP (other than those held by Enbridge and its wholly owned subsidiaries), we would expect that Plaintiff would lose standing to continue his derivative claims on behalf of SEP, and we would expect that Enbridge would become the owner of such derivative claims. As of September 18, 2018, all proceedings in the lawsuit have been stayed at Plaintiff's request pending either the closing of the Proposed Merger or the termination of the Merger Agreement, and the trial originally scheduled to begin December 11, 2018, has been removed from the Delaware Court of Chancery’s calendar.

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.


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Sierra Club and two other non-governmental organizations, as well as the two landowners, timely requested rehearing from the FERC of the March 14, 2018 Order. On August 10, 2018, the FERC issued an order denying the requests of Sierra Club and others seeking Rehearing of FERC's order on remand. No appeals related to the FERC's March 14, 2018 Order were timely filed and FERC's March 14, 2018 Order is now final and non-appealable.
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.
The Proposed Merger is subject to conditions, including some conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Proposed Merger, or significant delays in completing the Proposed Merger, could negatively affect our business and financial results and the trading prices of our common units.
The completion of the Proposed Merger is not assured and is subject to risks, including the risk that Enbridge shareholder approval is not obtained. Further, the Proposed Merger may not be completed even if the Enbridge shareholder approval is obtained. The Merger Agreement contains conditions, some of which are beyond our control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Proposed Merger not occurring.
If the Proposed Merger is not completed, or if there are significant delays in completing the Proposed Merger, Enbridge’s and our future business and financial results and the trading price of our common units could be negatively affected, and each of the parties will be subject to several risks, including the following:
•
the parties may be liable for expenses to one another under the terms and conditions of the Merger Agreement;
•
there may be negative reactions from the financial markets due to the fact that current prices of our common units may reflect a market assumption that the Proposed Merger will be completed.
Because the exchange ratio is fixed and because the market price of Enbridge common shares will fluctuate prior to the completion of the Proposed Merger, our unitholders cannot be sure of the market value of the Enbridge common shares they will receive as merger consideration relative to the value of our common units they exchange.
The market value of the consideration that our unitholders will receive in the Proposed Merger will depend on the trading price of Enbridge common shares at the closing of the Proposed Merger. The exchange ratio that determines the number of Enbridge common shares that our unitholders will receive in the Proposed Merger is fixed at 1.111 Enbridge common shares for each SEP common unit. This means that there is no mechanism contained in the Merger Agreement that would adjust the number of Enbridge common shares that our unitholders will receive based on any decreases or increases in the trading price of the Enbridge common shares. Share or unit price changes may result from a variety of factors (many of which are beyond Enbridge’s and our control), including:
•
changes in Enbridge’s or our business, operations and prospects;
•
changes in market assessments of Enbridge’s or our business, operations and prospects;
•
changes in market assessments of the likelihood that the Proposed Merger will be completed;
•
interest rates, commodity prices, general market, industry and economic conditions and other factors generally affecting the price of Enbridge common shares or our common units; and
•
federal, state and local legislation, governmental regulation and legal developments in the businesses in which Enbridge and we operate.
If the price of Enbridge common shares at the closing of the Proposed Merger is less than the price of Enbridge common shares on the date that the Merger Agreement was signed, then the market value of the merger consideration will be less than contemplated at the time the Merger Agreement was signed.

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When our common unitholders receive the merger consideration depends on the completion date of the Proposed Merger, which is uncertain.
Completing the Proposed Merger is subject to several conditions, not all of which are controllable by us. Accordingly, the date on which our unitholders will receive merger consideration depends on the completion date of the Proposed Merger, which is uncertain and subject to several other closing conditions.
Item 5.
Other Information.

The EUS 364-day Credit Facility. On September 5, 2018, we entered into an unsecured revolving 364-day credit agreement with Enbridge (U.S.) Inc., as lender. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that with revolving commitments of $750 million. The EUS 364-Day Credit Facility has a scheduled termination date of 364 days from September 5, 2018 (the Revolving Credit Commitment Termination Date). On the Revolving Credit Commitment Termination Date, we have the option to convert all outstanding revolving advances to term loan advances, with such term loan advances having a scheduled termination date of 364 days from the Revolving Credit Commitment Termination Date (such date, the Term Loan Commitment Termination Date). The EUS 364-day Credit Facility matures on (a) the Revolving Credit Commitment Termination Date, if we do not exercise our conversion option and (b) the Term Loan Commitment Termination Date, if we do exercise our conversion option.
Advances under the EUS 364-Day Credit Facility bear interest at the Eurodollar Rate (as defined in the EUS 364-Day Credit Facility) plus an applicable margin of 1.075%.
The EUS 364-Day Credit Facility contains certain customary representations, warranties, affirmative and negative covenants of SEP and certain restricted subsidiaries, including a financial covenant requiring maintenance of a consolidated leverage ratio of consolidated indebtedness to consolidated EBITDA of no greater than 5.00 to 1.00 (provided that for the three fiscal quarters subsequent to the consummation of a Qualified Acquisition (as defined in the EUS 364-Day Credit Facility), the consolidated leverage ratio shall be no greater than 5.50 to 1.00) and limitations on certain liens to secure indebtedness and mergers and other fundamental changes.
Upon the occurrence of certain events of default, the SEP’s obligations under the EUS 364-Day Credit Facility may be accelerated. Such events of default include payment defaults to the lender under the EUS 364-Day Credit Facility, cross-payment defaults and cross-acceleration defaults for other material indebtedness, covenant defaults and other customary defaults.
The EUS 364-Day Credit Facility provides that proceeds from advances under the EUS 364-Day Credit Facility may be used for SEP’s and its subsidiaries’ general corporate purposes.
As of September 30, 2018, we had $638 million outstanding under this facility, excluding any accrued interest to date. This facility is classified as a long-term obligation since we have the ability and the intent to refinance the amounts outstanding on a long-term basis. As of September 30, 2018, we were in compliance with all covenants contained therein.
The foregoing description of the EUS 364-Day Credit Facility is not complete and is qualified in its entirety by reference to the full and complete terms of the EUS 364-Day Credit Facility, which is attached as Exhibit 10.1 to this Quarterly Report on Form 10-Q.

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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.
(a) Exhibits
 
 
Exhibit
Number
  
 
 
 
 
 
Agreement and Plan of Merger, dated as of August 24, 2018, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Enbridge Inc., Enbridge (U.S.) Inc., Autumn Acquisition Sub, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc., Spectra Energy Corp, Spectra Energy Capital, LLC and Spectra Energy Transmission, LLC (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated August 24, 2018).
 
 
 
 
Credit Agreement, dated as of September 5, 2018, by and between Spectra Energy Partners, LP, as Borrower, and Enbridge (U.S.) Inc., as Lender.
 
 
 
  
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
  
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
  
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: November 1, 2018
 
By:
 
/S/    William T. Yardley       
 
 
 
 
William T. Yardley
President and Chairman of the Board
 
 
 
 
Date: November 1, 2018
 
By:
 
/S/    Stephen J. Neyland        
 
 
 
 
Stephen J. Neyland
Vice President—Finance

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