NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. General
The terms “we,” “our,” “us” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP (SEP) and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.
Nature of Operations.
Spectra Energy Partners, through its subsidiaries and equity investments, is engaged in the transmission, storage and gathering of natural gas and the transportation and storage of crude oil through interstate pipeline systems. We are a Delaware master limited partnership (MLP). As of
June 30, 2018
, Enbridge Inc. (Enbridge) and its subsidiaries collectively owned
83%
of us and the remaining
17%
was publicly owned. Enbridge owns and controls our general partner, Spectra Energy Partners (DE) GP, LP (SEP GP), which owns a non-economic general partner interest in us. See Note 13 for additional information on our general partner interest.
We manage our business in two reportable segments: U.S. Transmission and Liquids. The U.S. Transmission segment provides interstate transmission, storage and gathering of natural gas. The Liquids segment provides transportation of crude oil and storage of natural gas.
Basis of Presentation.
The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended
December 31, 2017
. In the opinion of management, the Condensed Consolidated Financial Statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These Condensed Consolidated Financial Statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended
December 31, 2017
, except for the adoption of new standards. See Note 2 for additional information on the adoption of new standards.
2. New Accounting Pronouncements
Adoption of New Standards
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our Condensed Consolidated Financial Statements.
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:
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June 30, 2018
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December 31, 2017
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|
June 30, 2017
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|
December 31, 2016
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(in millions)
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|
Cash and cash equivalents
|
|
$
|
96
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|
|
$
|
107
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|
|
$
|
153
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$
|
216
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|
Restricted cash in Other assets, net
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3
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|
|
3
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|
|
3
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|
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3
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Restricted cash in Regulatory and other assets
|
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2
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|
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4
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|
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3
|
|
|
14
|
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|
Cash, cash equivalents and restricted cash
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|
$
|
101
|
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|
$
|
114
|
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|
$
|
159
|
|
|
$
|
233
|
|
Simplifying Cash Flow Classification
Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Condensed Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and determined that the adoption of this ASU did not have a material impact on our Condensed Consolidated Financial Statements.
Recognition and Measurement of Financial Assets and Liabilities
Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale (AFS) securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our Condensed Consolidated Financial Statements.
Revenue from Contracts with Customers
Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not yet completed at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based, five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards. The adoption of this new standard did not have a material impact on our Condensed Consolidated Financial Statements. See Note 4 for additional information.
Future Accounting Policy Changes
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our Condensed Consolidated Financial Statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our Condensed Consolidated Financial Statements.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients permits entities not to reassess whether any expired or existing contracts contain leases, their lease classification, or any related initial direct costs.
Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.
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).
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Condensed Consolidated Statements of Income
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Total Operating Revenues
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Depreciation and Amortization
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Segment EBITDA/ Consolidated Earnings Before Income Taxes
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(in millions)
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Three Months Ended June 30, 2018
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U.S. Transmission
|
$
|
624
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|
|
$
|
82
|
|
|
$
|
505
|
|
|
Liquids
|
102
|
|
|
8
|
|
|
67
|
|
|
Total reportable segments
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726
|
|
|
90
|
|
|
572
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|
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Other
|
—
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|
|
—
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|
|
(2
|
)
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Depreciation and amortization
|
—
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|
|
—
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|
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90
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|
|
Interest expense
|
—
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|
|
—
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|
|
85
|
|
|
Interest income and other
|
—
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|
|
—
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|
|
3
|
|
|
Total consolidated
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$
|
726
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|
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$
|
90
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|
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$
|
398
|
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|
|
|
|
|
|
|
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Three Months Ended June 30, 2017
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U.S. Transmission
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$
|
592
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$
|
79
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$
|
480
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Liquids
|
103
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|
|
8
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|
|
64
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Total reportable segments
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695
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|
|
87
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|
|
544
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Other
|
—
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—
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(25
|
)
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Depreciation and amortization
|
—
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|
|
—
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|
|
87
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|
|
Interest expense
|
—
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|
|
—
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|
|
60
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|
|
Interest income and other
|
—
|
|
|
—
|
|
|
—
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|
Total consolidated
|
$
|
695
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$
|
87
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$
|
372
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|
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Six Months Ended June 30, 2018
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U.S. Transmission
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$
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1,295
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$
|
163
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$
|
1,027
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Liquids
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210
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|
16
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|
|
142
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Total reportable segments
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1,505
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|
179
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|
1,169
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Other
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—
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—
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|
(3
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)
|
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Depreciation and amortization
|
—
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|
|
—
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|
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179
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|
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Interest expense
|
—
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|
|
—
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|
|
170
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|
|
Interest income and other
|
—
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|
|
—
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|
|
4
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|
|
Total consolidated
|
$
|
1,505
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|
$
|
179
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|
|
$
|
821
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|
|
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|
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Six Months Ended June 30, 2017
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|
|
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U.S. Transmission
|
$
|
1,188
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|
|
$
|
156
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|
|
$
|
959
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|
|
Liquids
|
207
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|
|
16
|
|
|
130
|
|
|
Total reportable segments
|
1,395
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|
|
172
|
|
|
1,089
|
|
|
Other
|
—
|
|
|
—
|
|
|
(71
|
)
|
|
Depreciation and amortization
|
—
|
|
|
—
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|
|
172
|
|
|
Interest expense
|
—
|
|
|
—
|
|
|
116
|
|
|
Interest income and other
|
—
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|
|
—
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|
|
1
|
|
|
Total consolidated
|
$
|
1,395
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|
|
$
|
172
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|
|
$
|
731
|
|
4. Revenue from Contracts with Customers
Major Products and Services
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U.S. Transmission
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|
Liquids
|
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Consolidated
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(in millions)
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Three Months Ended June 30, 2018
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Transportation of natural gas
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$
|
575
|
|
|
$
|
—
|
|
|
$
|
575
|
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|
Transportation of crude oil
|
|
—
|
|
|
97
|
|
|
97
|
|
|
Storage of natural gas
|
|
47
|
|
|
5
|
|
|
52
|
|
|
Total revenue from contracts with customers
|
|
622
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|
|
102
|
|
|
724
|
|
|
Other revenue
|
|
2
|
|
|
—
|
|
|
2
|
|
|
Intersegment revenue
|
|
—
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|
|
—
|
|
|
—
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|
|
Total revenue
|
|
$
|
624
|
|
|
$
|
102
|
|
|
$
|
726
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2018
|
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|
|
|
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|
|
Transportation of natural gas
|
|
$
|
1,189
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|
|
$
|
—
|
|
|
$
|
1,189
|
|
|
Transportation of crude oil
|
|
—
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|
|
195
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|
|
195
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|
|
Storage of natural gas and other
|
|
102
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|
|
15
|
|
|
117
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|
|
Total revenue from contracts with customers
|
|
1,291
|
|
|
210
|
|
|
1,501
|
|
|
Other revenue
|
|
4
|
|
|
—
|
|
|
4
|
|
|
Intersegment revenue
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total revenue
|
|
$
|
1,295
|
|
|
$
|
210
|
|
|
$
|
1,505
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|
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
|
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|
|
Accounts Receivable
|
|
Contract Assets
|
|
Contract Liabilities
|
|
|
(in millions)
|
|
Balance at adoption date
|
|
$
|
265
|
|
|
$
|
—
|
|
|
$
|
65
|
|
|
Balance at reporting date
|
|
248
|
|
|
—
|
|
|
65
|
|
Contract liabilities primarily relate to deferred revenue. There were no material changes in contract liabilities during the three and
six months ended June 30, 2018
.
Recognition and Measurement of Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Transmission
|
|
Liquids
|
|
Consolidated
|
|
Three months ended June 30, 2018
|
(in millions)
|
|
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage
|
|
$
|
622
|
|
|
$
|
102
|
|
|
$
|
724
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2018
|
|
|
|
|
|
|
|
Revenue from products and services transferred over time - crude oil and natural gas transportation and storage
|
|
$
|
1,291
|
|
|
$
|
210
|
|
|
$
|
1,501
|
|
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is
$22.0 billion
, of which
$1.3 billion
and
$2.4 billion
is expected to be recognized during the remaining six months ending
December 31, 2018
and year ending
December 31, 2019
, respectively. Revenues from contracts with customers which have an original expected duration of one year or less are excluded from these amounts.
5. Net Income Per Limited Partner Unit and Cash Distributions
We determined basic and diluted net income per limited partner unit as follows:
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|
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|
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|
|
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|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(in millions, except per unit amounts)
|
|
Net income attributable to controlling interests
|
|
$
|
381
|
|
|
$
|
328
|
|
|
$
|
788
|
|
|
$
|
645
|
|
|
Less: Net income attributable to:
|
|
|
|
|
|
|
|
|
|
General partner’s interest in general partner units—2% (a)
|
|
—
|
|
|
7
|
|
|
—
|
|
|
13
|
|
|
General partner’s interest in incentive distribution rights (a)
|
|
—
|
|
|
87
|
|
|
—
|
|
|
170
|
|
|
Limited partners’ interest in net income attributable to common units
|
|
$
|
381
|
|
|
$
|
234
|
|
|
$
|
788
|
|
|
$
|
462
|
|
|
Weighted average limited partner units outstanding—basic and diluted
|
|
485
|
|
|
310
|
|
|
465
|
|
|
310
|
|
|
Net income per limited partner unit—basic and diluted
|
|
$
|
0.78
|
|
|
$
|
0.75
|
|
|
$
|
1.69
|
|
|
$
|
1.49
|
|
______________
(a) General partner units and incentive distribution rights (IDRs) were converted to common units of Spectra Energy Partners as a result of the Equity Restructuring Agreement dated January 21, 2018 (Equity Restructuring Agreement). See Note 13 for additional information.
Our partnership agreement requires that, within 60 days after the end of each quarter, we distribute all of our Available Cash, as defined below, to unitholders of record on the applicable record date.
Available Cash.
Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
|
|
|
|
•
|
less the amount of cash reserves established by the general partner to:
|
|
|
|
|
•
|
provide for the proper conduct of business,
|
|
|
|
|
•
|
comply with applicable law, any debt instrument or other agreement, or
|
|
|
|
|
•
|
provide funds for distributions for any one or more of the next four quarters,
|
|
|
|
|
•
|
plus, if the general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter;
|
|
|
|
|
•
|
provided, however, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of Available Cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that quarter if our general partner so determines
.
|
6. Variable Interest Entities
Sabal Trail.
We own a
50%
interest in Sabal Trail Transmission, LLC (Sabal Trail), a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida.
On April 30, 2018, Sabal Trail issued
$500 million
in aggregate principal amount of 4.246% senior notes due in 2028,
$600 million
in aggregate principal amount of 4.682% senior notes due in 2038 and
$400 million
in aggregate principal amount of 4.832% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to its partners as a partial reimbursement of construction and development costs incurred by the partners. The net distribution made to us was $744 million and was used to pay down short-term borrowings.
As of June 30, 2018, Sabal Trail is no longer a variable interest entity (VIE) due to Sabal Trail having sufficient equity at risk to finance its activities based on reconsideration triggered by to Sabal Trail's debt issuance and the distributions made to its members in April 2018.
NEXUS.
We own a
50%
interest in NEXUS Gas Transmission, LLC (NEXUS), a joint venture that is constructing a greenfield natural gas pipeline from Ohio to Michigan and leasing capacity on third party pipelines in order to provide transportation of Appalachian Basin natural gas to markets in Ohio, Michigan, and the Dawn Hub in Ontario, Canada through the Vector Pipeline. NEXUS is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of NEXUS that most significantly impact its economic performance is shared. We account for NEXUS under the equity method. Our maximum exposure to loss is
$1.3 billion
. We have an investment in NEXUS of
$869 million
and
$640 million
as of
June 30, 2018
and
December 31, 2017
, respectively, classified as Investments in and loans to unconsolidated affiliates on our Condensed Consolidated Balance Sheets.
In 2016, we issued performance guarantees to a third party and an affiliate on behalf of NEXUS. See Note 12 for further discussion of the guarantee arrangement.
PennEast.
In 2017, we purchased an additional 10% interest in PennEast Pipeline Company, LLC (PennEast) from PSEG Power Gas Holdings, LLC, increasing our ownership interest in PennEast to
20%
. PennEast is a joint venture that is proposing to construct a natural gas pipeline originating in northeastern Pennsylvania, and ending near Pennington, Mercer County, New Jersey. PennEast is a VIE due to insufficient equity at risk to finance its activities. We determined that we are not the primary beneficiary because the power to direct the activities of PennEast that most significantly impact its economic performance is shared. We account for PennEast under the equity method. Our maximum exposure to loss is
$279 million
. We have an investment in PennEast of
$66 million
and
$55 million
as of
June 30, 2018
and
December 31, 2017
, respectively, classified as Investments in and loans to unconsolidated affiliates on our Condensed Consolidated Balance Sheets.
The maximum exposure to loss for these entities is limited to our current equity investment and the remaining expected contributions for each joint venture.
7. Marketable Securities and Restricted Funds
We routinely invest excess cash and various restricted balances in securities such as commercial paper, corporate debt securities, and other money market securities in the United States, as well as equity securities in Canada. We do not purchase marketable securities for speculative purposes, therefore we do not have any securities classified as trading securities. While we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for the purposes of funding future capital expenditures and National Energy Board (NEB) regulatory requirements, so these investments are classified as AFS marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective type of securities (AFS marketable securities or held-to-maturity (HTM) marketable securities). Maturities of AFS securities are presented within Net cash used in investing activities within the Condensed Consolidated Statements of Cash Flows.
AFS Securities.
We had
$3 million
of AFS securities classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets as of
June 30, 2018
and
December 31, 2017
. At
June 30, 2018
and
December 31, 2017
, these investments include
$3 million
of restricted funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB's regulatory requirements, as well as less than
$1 million
of restricted funds related to certain construction projects as of
December 31, 2017
.
At
June 30, 2018
, the weighted-average contractual maturity of outstanding AFS securities was less than
one year
.
There were
no
material gross unrecognized holding gains or losses associated with investments in AFS securities at
June 30, 2018
or
December 31, 2017
.
HTM Securities.
All of our HTM securities are restricted funds. We had
$3 million
money market securities classified as Other assets, net on the Condensed Consolidated Balance Sheets as of
June 30, 2018
and
December 31, 2017
. These securities are restricted pursuant to certain Express-Platte pipeline system debt agreements.
At
June 30, 2018
, the weighted-average contractual maturity of outstanding HTM securities was less than
one year
.
There were
no
material gross unrecognized holding gains or losses associated with investments in HTM securities at
June 30, 2018
or
December 31, 2017
.
Other Restricted Funds.
In addition to the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling
$2 million
and
$4 million
classified as Regulatory and other assets on the Condensed Consolidated Balance Sheets at
June 30, 2018
and
December 31, 2017
, respectively. These restricted funds are related to certain construction projects.
Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. As a result, changes in restricted cash and restricted cash equivalents, which include HTM securities and other restricted funds discussed above, have been included within Cash and cash equivalents when reconciling the opening and closing period amounts shown on our Condensed Consolidated Statements of Cash Flows. Changes in restricted funds that are not restricted cash or restricted cash equivalents are presented within Net cash used in investing activities on our Condensed Consolidated Statements of Cash Flows. See Note 2 for additional information.
8. Debt
Credit Facility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity Date (a)
|
|
Total Facility
|
|
Draws (b)
|
|
Available
|
|
|
|
|
|
(in millions)
|
|
Spectra Energy Partners, LP
|
|
2022
|
|
$
|
2,500
|
|
|
$
|
1,161
|
|
|
$
|
1,339
|
|
______________
(a) Includes $336 million of commitments that expire in 2021.
(b) Includes facility draws and commercial paper issuances that are back-stopped by the credit facility.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of
June 30, 2018
, there were no letters of credit issued or revolving borrowings outstanding under the credit facility.
Our commercial paper program provides for the issuance of up to an aggregate principal amount
$2.5 billion
of commercial paper and is supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt as of
June 30, 2018
and
December 31, 2017
, respectively.
Our credit facility agreement and term debt indentures include common events of default and covenant provisions, including a financial covenant, whereby accelerated repayment and/or termination of the agreement may result if we were to default on payment or violate certain covenants. As of
June 30, 2018
, we were in compliance with those covenants.
Debt Issuances
. On January 9, 2018, Texas Eastern Transmission, LP (Texas Eastern), an indirect subsidiary of Spectra Energy Partners, issued
$400 million
in aggregate principal amount of 3.50% senior notes due in 2028 and
$400 million
in aggregate principal amount of 4.15% senior notes due in 2048. Texas Eastern used a portion of the net proceeds from the offering to fund expansion projects and capital expenditures on the Texas Eastern pipeline system. In addition, Texas Eastern used a portion of the net proceeds from the offering to repay funds we advanced to Texas Eastern in September 2017, which Texas Eastern used to repay a $400 million debt maturity. We used the proceeds received to repay commercial paper and credit facility borrowings, which were incurred primarily to fund Texas Eastern’s capital expenditures, as well as those of our other subsidiaries.
9. Fair Value Measurements
The following presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis as of
June 30, 2018
and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Condensed Consolidated Balance Sheet Caption
|
|
June 30, 2018
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
|
(in millions)
|
|
Interest rate swaps
|
Other assets, net
|
|
22
|
|
|
$
|
—
|
|
|
$
|
22
|
|
|
$
|
—
|
|
|
Commodity swaps
|
Other assets, net
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
Canadian equity securities
|
Regulatory and other assets
|
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
Interest rate swaps
|
Regulatory and other assets
|
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
Commodity swaps
|
Regulatory and other assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
Total Assets
|
|
$
|
33
|
|
|
$
|
3
|
|
|
$
|
28
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
Current liabilities — other
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
Interest rate swaps
|
Regulatory and other liabilities
|
|
7
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
Total Liabilities
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
Condensed Consolidated Balance Sheet Caption
|
|
December 31, 2017
|
|
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.
Financial Instruments
The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
|
Condensed Consolidated Balance Sheets
|
|
Book
Value
|
|
Approximate
Fair Value
|
|
Book
Value
|
|
Approximate
Fair Value
|
|
|
|
(in millions)
|
|
Note receivable, noncurrent (a)
|
|
$
|
71
|
|
|
$
|
71
|
|
|
$
|
71
|
|
|
$
|
71
|
|
|
Long-term debt, including current maturities (b)
|
|
6,650
|
|
|
6,639
|
|
|
5,850
|
|
|
6,211
|
|
______________
(a)
Included within Investments in and loans to unconsolidated affiliates.
(b)
Excludes variable rate debt, unamortized items and fair value hedge carrying value adjustments.
The fair value of our fixed-rate long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and is classified as Level 2.
The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, note receivable-noncurrent, accounts payable, short-term money market securities, commercial paper, credit facility borrowings and long-term variable-rate debt are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
10. Risk Management and Hedging Activities
Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt and commercial paper. We are exposed to foreign currency risk from the Canadian portion of the Express-Platte pipeline. We employ established policies and procedures to manage our risks associated with these market fluctuations, which may include the use of derivatives, mostly around interest rate exposures.
Total Interest Rate Derivative Instruments
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduces our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement in the event of these specific circumstances. All amounts are presented gross on the Condensed Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
|
|
Gross Amounts
Presented in
the Condensed
Consolidated
Balance Sheet
|
|
Amounts Available for Offset
|
|
Net
Amount
|
|
Gross Amounts
Presented in
the Condensed
Consolidated
Balance Sheet
|
|
Amounts Available for Offset
|
|
Net
Amount
|
|
Description
|
(in millions)
|
|
Assets
|
$
|
28
|
|
|
$
|
(1
|
)
|
|
$
|
27
|
|
|
$
|
4
|
|
|
$
|
(1
|
)
|
|
$
|
3
|
|
|
Liabilities
|
(10
|
)
|
|
1
|
|
|
(9
|
)
|
|
(8
|
)
|
|
1
|
|
|
(7
|
)
|
Fair Value Hedges
At
June 30, 2018
, we had
“pay floating - receive fixed” interest rate swaps outstanding with a total notional amount of
$900 million
to hedge against changes in the fair value of our fixed-rate financial instruments that arise as a result of changes in market interest rates
. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term debt securities from fixed-rate to variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt. Our "pay floating
- received fixed"
interest rate derivative instruments are designated and qualify as fair value hedges. The gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is recognized in the Condensed Consolidated Statements of Income. During the
six months ended June 30, 2018
, the amounts recognized were
$8 million
loss on the fair value hedges and offsetting
$8 million
gain on long-term debt.
Cash Flow Hedges
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. Since the third quarter of 2017, we have entered into pre-issuance interest rate swaps which are designated and qualified as cash flow hedges. The information of these cash flow swaps are presented as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at
|
|
Date of Maturity & Contract Type
|
|
Accounting Treatment
|
|
Average Interest Rate
|
|
Notional Amount
|
|
June 30, 2018
|
|
December 31, 2017
|
|
|
|
|
|
|
|
(in millions)
|
|
Contracts maturing in 2018
|
|
Cash Flow Hedge
|
|
2.51
|
%
|
|
$
|
560
|
|
|
$
|
22
|
|
|
$
|
1
|
|
|
Contracts maturing in 2020
|
|
Cash Flow Hedge
|
|
2.70
|
%
|
|
250
|
|
|
6
|
|
|
(3
|
)
|
We estimate that
$2 million
of Accumulated Other Comprehensive Income will be reclassified into net income in the next 12 months related to these swaps.
The effects of derivative instruments on the Condensed Consolidated Statements of Income and the Condensed Consolidated Statements of Comprehensive Income are shown as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of unrealized gain recognized in Other Comprehensive Income
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
(in millions)
|
|
(in millions)
|
|
Cash flow hedges - interest rate swaps
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
35
|
|
|
$
|
—
|
|
Non-qualifying Hedges
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets. In July 2017, we entered into a power swap to fix a portion of the variable price exposure for power costs from the Canadian portion of our Express-Platte pipeline system until 2020. As a result, we recognized an unrealized loss of
$1 million
and less than
$1 million
included in Operating, maintenance and other on the Condensed Consolidated Statements of Income during the three and
six months ended June 30, 2018
, respectively and hedge assets of
$2 million
included in Other assets, net and Regulatory and other assets on the Condensed Consolidated Balance Sheets at
June 30, 2018
.
11. Commitments and Contingencies
Environmental
We are subject to various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial laws, relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.
Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and we and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses.
Litigation
We are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our condensed consolidated financial position or results of operations.
12. Guarantees
We have various financial guarantees which are issued in the normal course of business. We enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Condensed Consolidated Balance Sheets. The possibility of having to perform under these guarantees is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events.
In December 2016, we issued performance guarantees to a third party and an affiliate on behalf of an equity method investee. These guarantees were issued to enable the equity method investee to enter into long-term transportation contracts with the third party. While the likelihood is remote, the maximum potential amount of future payments we could have been required to make as of
June 30, 2018
was
$107 million
. These performance guarantees expire in
2032
.
As of
June 30, 2018
, the amounts recorded for the guarantees described above are not material, either individually or in the aggregate.
13. Issuances of Common Units
On January 21, 2018, we entered into the Equity Restructuring Agreement with SEP GP, our general partner pursuant to which the IDRs and the 2% general partner interest in us held by that entity were converted into
172,500,000
newly issued common units and a non-economic general partner interest in us.
|
|
|
|
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
|
INTRODUCTION
Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying Condensed Consolidated Financial Statements.
EXECUTIVE OVERVIEW
For the
three months ended June 30, 2018
and
2017
, we reported net income attributable to controlling interests of
$381 million
and
$328 million
, respectively. For the
six months ended June 30, 2018
and
2017
, we reported net income attributable to controlling interests of
$788 million
and
$645 million
, respectively. Key highlights for the
six months ended June 30, 2018
include increased earnings driven by natural gas pipeline expansions, an adjustment to the established regulatory liability resulting from the 2017 U.S. tax reform legislation, increased natural gas transportation revenues, and a decrease in merger-related severance costs, partially offset by lower allowance for funds used during construction (AFUDC) due to Sabal Trail being placed into service.
For the
three months ended June 30, 2018
and
2017
, Distributable Cash Flow was
$398 million
and
$341 million
, respectively. For the
six months ended June 30, 2018
and
2017
, Distributable Cash Flow was
$851 million
and
$697 million
, respectively. A cash distribution of
$0.76375
per limited partner unit was declared on
August 2, 2018
and is payable on
August 29, 2018
. We intend to increase our quarterly distribution by one and a quarter cents per unit each quarter through
2018
. The declaration and payment of distributions, however, is subject to the sole discretion of our Board of Directors and depends upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints, our partnership agreement and other factors deemed relevant by our Board of Directors.
For the
six months ended June 30, 2018
, we had
$617 million
of capital and investment expenditures. We currently project
$1.8 billion
of capital and investment expenditures for the full year of 2018, including expansion capital expenditures of
$1.6 billion
.
We are committed to an investment-grade balance sheet and continued prudent financial management of our capital structure. Therefore, financing growth activities will continue to be based on our strong and growing fee-based earnings and cash flows and the issuances of debt and equity securities. As of
June 30, 2018
, we had access to approximately
$1.3 billion
in borrowing capacity under our
$2.5 billion
revolving credit facility which is used principally as a back-stop for our commercial paper program.
Enbridge offer to acquire publicly owned common units
On May 18, 2018, we announced that we received a non-binding offer from Enbridge and Enbridge (U.S.) Inc. to acquire all of our outstanding common units not currently beneficially owned by Enbridge (the Proposal). Under the terms of the Proposal, our common unitholders would receive 1.0123 common shares of Enbridge per common unit.
The board of directors of SEP GP has established a conflicts committee of independent directors to review and consider the Proposal. Any definitive agreement is subject to approval of a majority of the outstanding common units, and is expected to contain customary closing conditions, including standard regulatory notifications and approvals.
The Proposal is part of Enbridge's sponsored vehicle restructuring initiative to simplify its corporate structure. On May 17, 2018, Enbridge announced separate all-share proposals to the respective boards of directors of Enbridge's other sponsored vehicles, including Enbridge Energy Management, L.L.C., Enbridge Energy Partners, L.P., and Enbridge Income Fund Holdings Inc. to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by Enbridge.
United States tax reform update
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (TCJA). The most significant change included in the TCJA is the reduction in the corporate federal income tax rate from 35% to 21% (U.S. Tax Reform). As disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the U.S. Securities and Exchange Commission (SEC) on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the U.S. Tax Reform for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of the U.S Tax Reform, we continue to refine our estimates. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the U.S. Tax Reform. This resulted in a reduction of the $860 million overall regulatory liability by $25 million.
Revised Federal Energy Regulatory Commission (FERC) policy on the treatment of income taxes
On March 15, 2018, the FERC changed its long-standing policy on the treatment of income tax amounts included in the rates of pipelines and other entities subject to cost of service rate regulation within a MLP. In its order, the FERC revised a policy in place since 2005 to no longer permit entities organized as MLPs to recover an income tax allowance in their cost of service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking (NOPR) proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each pipeline; and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. These FERC announcements have negatively affected MLPs generally.
We filed comments to request clarification, reconsideration and rehearing of this policy change at the FERC. We also responded to the NOPR in April and filed comments in response to the Notice of Inquiry. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing.
On July 18, 2018, the FERC issued an Order that: (1) dismissed all requests for rehearing of its March 15, 2018 revised policy statement and explained that its revised policy statement does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (2) provides guidance that if an MLP or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC’s Revised Policy Statement, then Accumulated Deferred Income Taxes (ADIT) will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT instead of flowing ADIT balances back to ratepayers. As a statement of general policy, the FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.
While many uncertainties remain with regards to the implementation of the FERC actions, if implemented as announced, and combined with the impact of the U.S. Tax Reform, we estimate the impact to revenue and cash flow to be immaterial. The benefit from the changes related to ADIT offset the discontinuance of recovering an income tax allowance in cost of service rates. Any future direct impacts would only take effect upon the execution and settlement of a rate case where the outcome could be different.
In a companion rulemaking proceeding, the FERC also codified the final rules for certain natural gas pipeline compliance filings known as Form 501-G. This new filing is expected, in most circumstances, to be a one-time filing. In this filing a FERC regulated natural gas pipeline specifies how it intends to adjust (or not) its rates due to the collective impacts of reductions in the US income tax rates and, in the case of MLP’s and certain other pass through entities, the impacts of FERC’s revised tax allowance policy. Under the new rulemaking, a number of our natural gas pipelines will need to file under this new rule by the end of 2018. Pending greater clarification from the FERC on the application of its new policy, assessing the near-term and long-term implications of the policy is challenging.
RESULTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(in millions)
|
|
Operating revenues
|
|
$
|
726
|
|
|
$
|
695
|
|
|
$
|
1,505
|
|
|
$
|
1,395
|
|
|
Operating expenses
|
|
340
|
|
|
352
|
|
|
677
|
|
|
720
|
|
|
Operating income
|
|
386
|
|
|
343
|
|
|
828
|
|
|
675
|
|
|
Earnings from equity investments
|
|
71
|
|
|
40
|
|
|
129
|
|
|
78
|
|
|
Other income and expenses, net
|
|
26
|
|
|
49
|
|
|
34
|
|
|
94
|
|
|
Interest expense
|
|
85
|
|
|
60
|
|
|
170
|
|
|
116
|
|
|
Earnings before income taxes
|
|
398
|
|
|
372
|
|
|
821
|
|
|
731
|
|
|
Income tax expense
|
|
7
|
|
|
5
|
|
|
12
|
|
|
10
|
|
|
Net income
|
|
391
|
|
|
367
|
|
|
809
|
|
|
721
|
|
|
Net income—noncontrolling interests
|
|
10
|
|
|
39
|
|
|
21
|
|
|
76
|
|
|
Net income—controlling interests
|
|
$
|
381
|
|
|
$
|
328
|
|
|
$
|
788
|
|
|
$
|
645
|
|
Three Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues
. The
$31 million
increase was driven mainly by:
|
|
|
|
•
|
an increase due to expansion projects primarily on Texas Eastern and Algonquin Gas Transmission, LLC (Algonquin),
|
|
|
|
|
•
|
an increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by,
|
|
|
|
|
•
|
a decrease in revenue from Sabal Trail due to a change in accounting treatment. During the second quarter of 2017, we received contributions from Sabal Trail prior to its in-service date which were recorded in operating revenues. Upon the commencement of commercial service, we deconsolidated our investment and began accounting for it under the equity method. All contributions from Sabal Trail are now recorded within one line called earnings from equity investments as discussed below.
|
Operating expenses
. The
$12 million
decrease was driven mainly by:
|
|
|
|
•
|
a decrease due to 2017 merger-related severance costs,
|
|
|
|
|
•
|
a decrease due to higher pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident near Delmont, Pennsylvania, partially offset by
|
|
|
|
|
•
|
an increase in electric power and other costs passed through to gas transmission customers.
|
Earnings from equity investments.
The
$31 million
increase was mainly attributable to Sabal Trail being placed into service and higher AFUDC related to NEXUS.
Other income and expenses, net.
The
$23 million
decrease was mainly attributable to lower AFUDC due to Sabal Trail being placed into service.
Interest expense.
The
$25 million
increase was mainly attributable to lower capitalized interest due to Sabal Trail being placed into service and an increase in interest rates related to short-term borrowings.
Six Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues
. The
$110 million
increase was driven mainly by:
|
|
|
|
•
|
an increase due to expansion projects primarily on Texas Eastern and Algonquin,
|
|
|
|
|
•
|
an increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform,
|
|
|
|
|
•
|
an increase in recoveries of electric power and other costs passed through to gas transmission customers,
|
|
|
|
|
•
|
an increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by
|
|
|
|
|
•
|
a decrease in revenue from Sabal Trail due to a change in accounting treatment as previously discussed.
|
Operating expenses
. The
$43 million
decrease was driven mainly by:
|
|
|
|
•
|
a decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident near Delmont, Pennsylvania,
|
|
|
|
|
•
|
a decrease due to 2017 merger-related severance costs,
|
|
|
|
|
•
|
a decrease in integrity and power costs, partially offset by
|
|
|
|
|
•
|
an increase in electric power and other costs passed through to gas transmission customers, and
|
|
|
|
|
•
|
an increase in costs related to expansion.
|
Earnings from equity investments.
The
$51 million
increase was mainly attributable to Sabal Trail being placed into service and higher AFUDC related to NEXUS.
Other income and expenses, net.
The
$60 million
decrease was mainly attributable to lower AFUDC due to Sabal Trail being placed into service.
Interest expense.
The
$54 million
increase was mainly attributable to lower capitalized interest due to Sabal Trail being placed into service and an increase in interest rates related to short-term borrowings.
Segment Results
Management evaluates segment performance based on EBITDA. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income, are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.
Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(in millions)
|
|
U.S. Transmission
|
|
$
|
505
|
|
|
$
|
480
|
|
|
$
|
1,027
|
|
|
$
|
959
|
|
|
Liquids
|
|
67
|
|
|
64
|
|
|
142
|
|
|
130
|
|
|
Total reportable segment EBITDA
|
|
572
|
|
|
544
|
|
|
1,169
|
|
|
1,089
|
|
|
Other
|
|
(2
|
)
|
|
(25
|
)
|
|
(3
|
)
|
|
(71
|
)
|
|
Depreciation and amortization
|
|
90
|
|
|
87
|
|
|
179
|
|
|
172
|
|
|
Interest expense
|
|
85
|
|
|
60
|
|
|
170
|
|
|
116
|
|
|
Interest income and other
|
|
3
|
|
|
—
|
|
|
4
|
|
|
1
|
|
|
Earnings before income taxes
|
|
$
|
398
|
|
|
$
|
372
|
|
|
$
|
821
|
|
|
$
|
731
|
|
The amounts discussed below are after eliminating intercompany transactions.
U.S. Transmission
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
|
|
(in millions)
|
|
Operating revenues
|
|
$
|
624
|
|
|
$
|
592
|
|
|
$
|
32
|
|
|
$
|
1,295
|
|
|
$
|
1,188
|
|
|
$
|
107
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating, maintenance and other
|
|
212
|
|
|
201
|
|
|
11
|
|
|
426
|
|
|
401
|
|
|
25
|
|
|
Other income/(expense)
|
|
93
|
|
|
89
|
|
|
4
|
|
|
158
|
|
|
172
|
|
|
(14
|
)
|
|
EBITDA
|
|
$
|
505
|
|
|
$
|
480
|
|
|
$
|
25
|
|
|
$
|
1,027
|
|
|
$
|
959
|
|
|
$
|
68
|
|
Three Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues.
The
$32 million
increase was driven by:
|
|
|
|
•
|
a $32 million increase due to expansion projects primarily on Texas Eastern and Algonquin,
|
|
|
|
|
•
|
a $10 million increase in recoveries of electric power and other costs passed through to gas transmission customers, partially offset by
|
|
|
|
|
•
|
a $10 million decrease from Sabal Trail due to a change in accounting treatment as previously discussed.
|
Operating, maintenance and other.
The
$11 million
increase was driven by:
|
|
|
|
•
|
a $13 million increase primarily due to allocated corporate shared-service costs previously reported on "Other",
|
|
|
|
|
•
|
a $10 million increase in electric power and other costs passed through to gas transmission customers, partially offset by
|
|
|
|
|
•
|
an $11 million decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident.
|
Six Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues.
The
$107 million
increase was driven by:
|
|
|
|
•
|
a $65 million increase due to expansion projects primarily on Texas Eastern and Algonquin,
|
|
|
|
|
•
|
a $25 million increase due to an adjustment to the 2017 regulatory liability established results from the U.S. Tax Reform,
|
|
|
|
|
•
|
a $19 million increase in recoveries of electric power and other costs passed through to gas transmission customers,
|
|
|
|
|
•
|
a $16 million increase in natural gas transportation revenues mainly from firm transportation on Texas Eastern, partially offset by
|
|
|
|
|
•
|
a $10 million decrease from Sabal Trail due to a change in accounting treatment as previously discussed, and
|
|
|
|
|
•
|
an $8 million decrease in storage revenues mainly due to lower contract renewal rates.
|
Operating, maintenance and other.
The
$25 million
increase was driven by:
|
|
|
|
•
|
a $25 million increase primarily due to allocated corporate shared-service costs previously reported on "Other",
|
|
|
|
|
•
|
a $19 million increase in electric power and other costs passed through to gas transmission customers,
|
|
|
|
|
•
|
a $7 million increase in costs related to expansion, partially offset by
|
|
|
|
|
•
|
a $13 million decrease due to pipeline inspection and repair costs in 2017 related to the 2016 Texas Eastern pipeline incident, and
|
|
|
|
|
•
|
a $12 million decrease due to 2017 merger-related severance costs.
|
Other income and expenses.
The
$14 million
decrease was driven by:
|
|
|
|
•
|
a $77 million decrease in equity AFUDC due to Sabal Trail being placed into service, partially offset by
|
|
|
|
|
•
|
a $51 million increase due to higher equity earnings from Sabal Trail being placed into service, and
|
|
|
|
|
•
|
an $11 million increase due to corporate allocations of pension costs.
|
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
|
|
(in millions)
|
|
Operating revenues
|
|
$
|
102
|
|
|
$
|
103
|
|
|
$
|
(1
|
)
|
|
$
|
210
|
|
|
$
|
207
|
|
|
$
|
3
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating, maintenance and other
|
|
36
|
|
|
39
|
|
|
(3
|
)
|
|
69
|
|
|
76
|
|
|
(7
|
)
|
|
Other income/(expense)
|
|
1
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
(1
|
)
|
|
2
|
|
|
EBITDA
|
|
$
|
67
|
|
|
$
|
64
|
|
|
$
|
3
|
|
|
$
|
142
|
|
|
$
|
130
|
|
|
$
|
12
|
|
|
Express pipeline revenue receipts, MBbl/d (a)
|
|
263
|
|
|
254
|
|
|
9
|
|
|
262
|
|
|
263
|
|
|
(1
|
)
|
|
Platte PADD II deliveries, MBbl/d (a)
|
|
121
|
|
|
136
|
|
|
(15
|
)
|
|
132
|
|
|
140
|
|
|
(8
|
)
|
______________
(a) Thousand barrels per day.
Three Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues.
Operating revenues were consistent period over period.
Operating, maintenance and other.
The
$3 million
decrease in operating expenses was mainly driven by a decrease in integrity and power costs.
Six Months Ended June 30, 2018
Compared to Same Period in
2017
Operating revenues.
The
$3 million
increase in operating revenues was mainly driven by an increase in inventory settlement, partially offset by lower transportation volumes.
Operating, maintenance and other.
The
$7 million
decrease in operating expenses was mainly driven by a decrease in integrity and power costs.
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
2018
|
|
2017
|
|
Increase (Decrease)
|
|
|
|
(in millions)
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating, maintenance and other
|
|
$
|
2
|
|
|
$
|
25
|
|
|
$
|
(23
|
)
|
|
$
|
3
|
|
|
$
|
71
|
|
|
$
|
(68
|
)
|
|
EBITDA
|
|
$
|
(2
|
)
|
|
$
|
(25
|
)
|
|
$
|
23
|
|
|
$
|
(3
|
)
|
|
$
|
(71
|
)
|
|
$
|
68
|
|
Three Months Ended June 30, 2018
Compared to Same Period in
2017
Operating, maintenance and other.
The
$23 million
decrease was driven by:
|
|
|
|
•
|
a $13 million decrease due to 2017 merger-related severance costs, and
|
|
|
|
|
•
|
a $10 million decrease due to lower allocated corporate shared-service costs previously recorded in "Other".
|
Six Months Ended June 30, 2018
Compared to Same Period in
2017
Operating, maintenance and other.
The
$68 million
decrease was driven by:
|
|
|
|
•
|
a $37 million decrease due to 2017 merger-related severance costs, and
|
|
|
|
|
•
|
a $31 million decrease due to lower allocated corporate shared-service costs previously recorded in "Other".
|
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,
|
|
|
|
|
•
|
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.
Reconciliation of Net Income to Non-GAAP “Distributable Cash Flow”
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
(in millions)
|
|
Net income
|
|
$
|
391
|
|
|
$
|
367
|
|
|
$
|
809
|
|
|
$
|
721
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
85
|
|
|
60
|
|
|
170
|
|
|
116
|
|
|
Income tax expense
|
|
7
|
|
|
5
|
|
|
12
|
|
|
10
|
|
|
Depreciation and amortization
|
|
90
|
|
|
87
|
|
|
179
|
|
|
172
|
|
|
Foreign currency (gain) loss
|
|
(2
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Third party interest income
|
|
1
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
EBITDA
|
|
570
|
|
|
519
|
|
|
1,166
|
|
|
1,018
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Earnings from equity investments
|
|
(71
|
)
|
|
(40
|
)
|
|
(129
|
)
|
|
(78
|
)
|
|
Distributions from equity investments
|
|
75
|
|
|
40
|
|
|
135
|
|
|
78
|
|
|
Non-cash impact of the U.S. Tax Reform
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
Other
|
|
(4
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
—
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
85
|
|
|
60
|
|
|
170
|
|
|
116
|
|
|
Equity AFUDC
|
|
9
|
|
|
48
|
|
|
15
|
|
|
93
|
|
|
Net cash paid for income taxes
|
|
4
|
|
|
3
|
|
|
5
|
|
|
8
|
|
|
Distributions to noncontrolling interests
|
|
13
|
|
|
13
|
|
|
28
|
|
|
25
|
|
|
Maintenance capital expenditures
|
|
61
|
|
|
53
|
|
|
75
|
|
|
79
|
|
|
Distributable Cash Flow
|
|
$
|
398
|
|
|
$
|
341
|
|
|
$
|
851
|
|
|
$
|
697
|
|
LIQUIDITY AND CAPITAL RESOURCES
As of
June 30, 2018
, we had negative working capital of
$506 million
. This balance includes current maturities of long-term debt of
$500 million
. We will rely upon cash flows from operations, including cash distributions received from our equity affiliates, and various financing transactions, which may include debt and/or equity issuances, to fund our liquidity and capital requirements for the next 12 months. We have access to a revolving credit facility, with available capacity of
$1,339 million
at
June 30, 2018
. This facility is used principally as a back-stop for our commercial paper program, which is used to manage working capital requirements and for temporary funding of capital expenditures. Capital resources may continue to include commercial paper, short-term borrowings under our current credit facility and possibly securing additional sources of capital including debt and/or equity. See Note 8 of Notes to Condensed Consolidated Financial Statements for a discussion of the available credit facility and Financing Cash Flows and Liquidity below for a discussion of effective shelf registrations.
Cash Flow Analysis
The following table summarizes the changes in cash flows for each of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
|
2018
|
|
2017
|
|
|
|
(in millions)
|
|
Net cash provided by (used in):
|
|
|
|
|
|
Operating activities
|
|
$
|
883
|
|
|
$
|
808
|
|
|
Investing activities
|
|
163
|
|
|
(1,496
|
)
|
|
Financing activities
|
|
(1,059
|
)
|
|
614
|
|
|
Net decrease in Cash, cash equivalents and restricted cash
|
|
(13
|
)
|
|
(74
|
)
|
|
Cash, cash equivalents and restricted cash at beginning of the period
|
|
114
|
|
|
233
|
|
|
Cash, cash equivalents and restricted cash at end of the period
|
|
$
|
101
|
|
|
$
|
159
|
|
Operating Cash Flows
Net cash provided by operating activities increased
$75 million
to
$883 million
in the
six months ended June 30, 2018
compared to the same period in
2017
, driven mainly by higher earnings and higher distributions from equity investments as a result of positive operating factors discussed in
Results of Operations
, and changes in working capital.
Investing Cash Flows
Net cash provided by investing activities totaled $
163 million
in the
six months ended June 30, 2018
compared to
$1,496 million
used in investing activities in the same period in
2017
. The change was mainly driven by:
|
|
|
|
•
|
a decrease of $976 million in capital expenditures primarily due to Sabal Trail being placed in-service in July 2017,
|
|
|
|
|
•
|
a $744 million distribution received from Sabal Trail during the three months ended June 30, 2018 as a partial return of capital for construction and development costs, partially offset by
|
|
|
|
|
•
|
a $74 million increase in investments in and loans to unconsolidated affiliates mainly due to increased investment in NEXUS, Sabal Trail being classified as an unconsolidated affiliate upon its deconsolidation in July 2017, and partially offset by an additional 10% investment purchased in PennEast in June 2017.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
Capital and Investment Expenditures by Business Segment
|
|
2018
|
|
2017
|
|
|
|
(in millions)
|
|
U.S. Transmission
|
|
$
|
595
|
|
|
$
|
1,508
|
|
|
Liquids
|
|
22
|
|
|
11
|
|
|
Total consolidated
|
|
$
|
617
|
|
|
$
|
1,519
|
|
Capital and investment expenditures for the
six months ended
June 30, 2018
consisted of $542 million for expansion projects and
$75 million
for maintenance and other projects.
We project 2018 capital and investment expenditures of approximately
$1.8 billion
, consisting of
$1.6 billion
of expansion capital expenditures and $0.2 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. These projections exclude contributions from noncontrolling interests.
Financing Cash Flows and Liquidity
Net cash used in financing activities totaled
$1,059 million
in the
six months ended June 30, 2018
compared to
$614 million
provided by financing activities in the same period in
2017
. The change was mainly driven by:
|
|
|
|
•
|
$1,093 million of repayments of credit facility in 2018 compared to $750 million of issuances of credit facility in 2017,
|
|
|
|
|
•
|
a $415 million decrease in contributions from noncontrolling interest as a result of Sabal Trail being classified as an unconsolidated affiliate upon its deconsolidation in July 2017,
|
|
|
|
|
•
|
a $125 million increase in distributions to partners as a result of an increase in our quarterly per unit distribution and an increase in the number of common units outstanding and
|
|
|
|
|
•
|
an $87 million decrease in proceeds from the issuances of units as a result of the issuance of common and general partner units in 2017, partially offset by
|
|
|
|
|
•
|
a $416 million decrease in payments for the redemption of long-term debt,
|
|
|
|
|
•
|
a $394 million increase in proceeds from issuance of long-term debt.
|
Available Credit Facility and Restrictive Debt Covenants.
Our credit facility agreements and term debt indentures include common events of default and covenant provisions, including a financial covenant, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As of
June 30, 2018
, we were in compliance with the covenants. See Note 8 of Notes to Condensed Consolidated Financial Statements for a discussion of the available credit facility and related financial and other covenants.
Cash Distributions.
A cash distribution of
$0.76375
per limited partner unit was declared on
August 2, 2018
, payable on
August 29, 2018
, representing the forty-third consecutive quarterly increase.
Other Financing Matters.
We have an effective shelf registration statement on file with the SEC to register the issuance of unspecified amounts of limited partner common units and various debt securities. We have another effective registration statement on file with the SEC to register the issuance of $1 billion, in the aggregate, of limited partner units over time. This registration has $186 million available as of
June 30, 2018
.
OTHER ISSUES
New Accounting Pronouncements.
See Note 2 of Notes to Condensed Consolidated Financial Statements for discussion.
