Notes to Consolidated Financial Statements
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1.
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2.
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3.
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4.
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5.
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6.
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7.
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8.
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Variable Interest Entities
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9.
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Intangible Asset
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10.
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11.
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12.
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13.
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14.
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15.
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16.
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17.
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Guarantees
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18.
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19.
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20.
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1. Summary of Operations and Significant Accounting Policies
The terms “we,” “our,” “us” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.
Nature of Operations
.
Spectra Energy Partners, 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
December 31, 2016
, Spectra Energy Corp (Spectra Energy) and its subsidiaries collectively owned
75%
of us and the remaining
25%
was publicly owned.
On September 6, 2016, Spectra Energy announced that they entered into a definitive merger agreement with Enbridge Inc. (Enbridge). Under this agreement, Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy's stock at approximately
$28 billion
, based on the closing price of Enbridge common shares as of
September 2, 2016
. This transaction was approved by the boards of directors and shareholders of both Spectra Energy and Enbridge and has received all necessary regulatory approvals. The transaction is expected to close on
February 27, 2017
.
Upon completion of the proposed merger, Spectra Energy shareholders will receive
0.984
Enbridge common shares for each share of Spectra Energy stock they own. The consideration to be received is valued at
$40.33
per Spectra Energy share, based on the closing price of Enbridge common shares as of
September 2, 2016
, representing an approximate
11.5%
premium to the closing price of Spectra Energy stock as of
September 2, 2016
. Upon completion of the merger, Enbridge shareholders are expected to own approximately
57%
of the combined company and Spectra Energy shareholders are expected to own approximately
43%
.
As a result of this transaction, Enbridge and its subsidiaries will collectively own the interest in us currently held by Spectra Energy.
Basis of Presentation
.
The accompanying Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances.
During 2013, we acquired substantially all of Spectra Energy's U.S. transmission, storage and liquid assets (U.S. Assets Dropdown), excluding a
25.05%
ownership interest in Southeast Supply Header, LLC (SESH) and a
1%
ownership interest in Steckman Ridge, LP (Steckman Ridge).
In November 2014, we acquired an additional
24.95%
ownership interest in SESH and the remaining
1%
interest in Steckman Ridge from Spectra Energy.
In November 2015, we acquired the remaining
0.1%
ownership interest in SESH from Spectra Energy.
Our costs of doing business have been reflected in our financial accounting records for the periods presented. These costs include direct charges and allocations from Spectra Energy and its affiliates for business services, such as payroll, accounts payable and facilities management; corporate services, such as finance and accounting, legal, human resources, investor relations, public and regulatory policy, and senior executives; and pension and other post-retirement benefit costs.
Use of Estimates
.
To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes to Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
Fair Value Measurements.
We measure the fair value of financial assets and liabilities by maximizing the use of observable inputs and minimizing the use of unobservable inputs. Fair value is the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
Cost-Based Regulation
.
The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are mostly classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits and Current Liabilities. We evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities. See Note 5 for further discussion.
Foreign Currency Translation.
The Canadian dollar has been determined to be the functional currency of the Canadian portion of the Express-Platte pipeline system (Express Canada) based on an assessment of the economic circumstances of those operations. Assets and liabilities of Express Canada are translated into U.S. dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of Other Comprehensive Income (Loss) on the Consolidated Statements of Comprehensive Income. Revenue and expense accounts of these operations are translated at average monthly exchange rates prevailing during the periods. Gains and losses arising from transactions denominated in currencies other than the functional currency are included in the results of operations of the period in which they occur. Foreign currency transaction losses totaled
$1 million
,
$6 million
, and
$3 million
in
2016
,
2015
, and
2014
respectively and are included in Other Income and Expenses, Net on the Consolidated Statements of Operations.
Revenue Recognition
.
Revenues from the transmission, storage and gathering of natural gas, and from the transportation of crude oil are generally recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated revenues are immaterial. There were no customers accounting for 10% or more of consolidated revenues during
2016
,
2015
or
2014
. We also have certain customer contracts with billed amounts that decline annually over the terms of the contracts. Differences between the amounts billed and recognized are deferred on the Consolidated Balance Sheets.
Allowance for Funds Used During Construction (AFUDC).
AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of certain new regulated facilities, consists of two components, an equity component and an interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. AFUDC is capitalized as a component of Property, Plant and Equipment - Cost in the Consolidated Balance Sheets, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. The total amount of AFUDC included in the Consolidated Statements of Operations was
$168 million
in
2016
(an equity component of
$121 million
and an interest expense component of
$47 million
),
$95 million
in
2015
(an equity component of
$76 million
and an interest expense component of
$19 million
) and
$42 million
in
2014
(an equity component of
$33 million
and an interest expense component of
$9 million
). The equity component of AFUDC, a non-cash item, is included as a reconciling item to net income within Cash Flows from Operating Activities - Other, Assets in the Consolidated Statements of Cash Flows.
Income Taxes
.
As a result of our MLP structure, we are not subject to federal income tax. Our federal taxable income or loss is reported on the respective income tax returns of our partners. However, we are subject to Canadian income tax and Tennessee and New Hampshire income tax. Spectra Energy Partners is liable to Spectra Energy for Texas income (margin) tax under a tax sharing agreement. As of
December 31, 2016
, the difference between the tax basis and the reported amounts of Spectra Energy Partners’ assets and liabilities is
$15.2 billion
.
We are subject to cost-based regulation and consequently record a regulatory tax asset in connection with the tax gross up of AFUDC equity. The corresponding deferred tax liability is recognized as an Attributed Deferred Tax Benefit in the Consolidated Statements of Equity since we are a pass-through entity.
In the first quarter of 2014, we recorded
$23 million
of income tax expense due to the adjustment to deferred income tax liabilities (eliminated and recorded as an income tax benefit in 2013 in connection with the U.S. Assets Dropdown and resulting changes in tax status of certain entities) as a result of the final purchase price allocation adjustments.
Cash and Cash Equivalents.
Highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents, except for the investments that were pledged as collateral against long-term debt as discussed in Note 13 and any investments that are considered restricted funds.
Inventory.
Inventory consists of natural gas retained from shippers for fuel and also includes materials and supplies. Natural gas is recorded at the lower of cost or market. Materials and supplies are recorded at cost, using the average cost method.
Natural Gas Imbalances.
The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Operations or Consolidated Statements of Cash Flows. Receivables include
$99 million
and
$36 million
as of
December 31, 2016
and
December 31, 2015
, respectively, and Other Current Liabilities include
$74 million
and
$32 million
as of
December 31, 2016
and
December 31, 2015
, respectively, related to all gas imbalances. Most natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
Cash Flow and Fair Value Hedges
.
We have entered into interest rate swaps which were designated as either a hedge of a forecasted transaction (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, we prepare documentation of the hedge in accordance with accounting standards and assess whether the hedge contract is highly effective using regression analysis, both at inception and on a quarterly basis, in offsetting changes in cash flows or fair values of hedged items.
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Comprehensive Income as Other Comprehensive Income (Loss) until earnings are affected by the hedged item. We discontinue hedge accounting prospectively when we have determined that a derivative no longer qualifies as an effective hedge or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market model of accounting prospectively. Gains and losses related to discontinued hedges that were previously accumulated in accumulated other comprehensive income (AOCI) remain in AOCI until the underlying transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.
For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting gain or loss on the hedged item in earnings, to the extent effective, in the current period. In the event the hedge is not effective, there is no offsetting gain or loss recognized in earnings for the hedged item. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. All components of each derivative gain or loss are included in the assessment of hedge effectiveness.
Investments
.
We may actively invest a portion of our available cash and restricted funds balances in various financial instruments, including taxable or tax-exempt debt securities. In addition, we invest in short-term money market securities, some of which are restricted due to debt collateral requirements. Investments in available-for-sale (AFS) securities are carried at fair value and investments in held-to-maturity (HTM) securities are carried at cost. Investments in money market securities are also accounted for at fair value. Realized gains and losses, and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings. The costs of securities sold are determined using the specific identification method. Purchases and sales of AFS and HTM securities are presented on a gross basis within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows. See also Notes 10 and 14 for additional information.
Goodwill
.
We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. No impairments of goodwill were recorded in
2016
,
2015
or
2014
.
We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments.
As permitted under accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine the fair values of those reporting units. Key assumptions in the determination of fair value included the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure projections. If the carrying amount of the reporting unit exceeds its fair value, a comparison of the fair value and carrying value of the goodwill of that reporting unit needs to be performed. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
We had goodwill balances of
$3,234 million
at
December 31, 2016
and
$3,232 million
at
December 31, 2015
. The increase in goodwill in 2016 was the result of foreign currency translation.
Property, Plant and Equipment
.
Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes, administrative and general costs, and the cost of funds used during construction. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The costs of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
When we retire property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire or sell certain non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
Preliminary Project Costs
.
Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the
feasibility of capital expansion projects, are capitalized for rate-regulated enterprises when it is determined that recovery of such costs through regulated revenues of the completed project is probable. Any inception-to-date costs of the projects that were initially expensed are reversed and capitalized as Property, Plant and Equipment.
Long-Lived Asset Impairments.
We evaluate whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used in developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, an impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.
We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes in market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.
We recorded a
$9 million
non-cash impairment charge on Ozark Gas Gathering, L.L.C. in the first quarter of 2015 included in Operating, Maintenance and Other on the Consolidated Statements of Operations.
Asset Retirement Obligations (AROs).
We recognize asset retirement obligations for legal commitments associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
Unamortized Debt Premium, Discount and Expense
.
Premiums, discounts, and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issued. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
Environmental Expenditures
.
We expense environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Undiscounted liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
Segment Reporting.
Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided certain criteria are met. There is no such aggregation within our defined business segments. A description of our reportable segments consistent with how business results are reported internally to management, and the disclosure of segment information is presented in Note 4.
Consolidated Statements of Cash Flows.
Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds. For example, business interruption insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts, if any, are included within financing cash flows.
Distributions from Equity Investments
.
We consider distributions received from equity investments which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classify these amounts as Cash Flows from Operating Activities within the accompanying Consolidated Statements of Cash Flows. Cumulative distributions received in excess of cumulative equity in earnings subsequent to the date of investment are considered to be a return of investment and are classified as Cash Flows from Investing Activities.
New Accounting Pronouncements.
The following new Accounting Standards Updates (ASUs) were adopted during
2016
and the effects of such adoptions, if any, are presented in the accompanying Consolidated Financial Statements:
In June 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-10,
“Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation,”
which amends the consolidation guidance around reporting entities that invest in development stage entities. We adopted the consolidation guidance of this amendment on January 1, 2016 and applied it retrospectively with no material effect on our consolidated results of operations, financial position, or cash flows. This ASU did result in certain of our entities being classified as a variable interest entity (VIE). See Note 8 for discussion of our Variable Interest Entities.
In February 2015, the FASB issued ASU No. 2015-02,
“Consolidation (Topic 810): Amendments to the Consolidation Analysis,”
which makes changes to both the variable interest model and the voting model. These changes required reevaluation of certain entities for consolidation and required us to revise our documentation regarding the consolidation or deconsolidation of such entities. We adopted this standard on January 1, 2016 with no material effect on our consolidated operations, financial position, or cash flows.
In September 2015, the FASB issued ASU No. 2015-16,
“Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
,
”
to simplify accounting for adjustments made to provisional amounts recognized in a business combination and to eliminate the retrospective accounting for those adjustments. We adopted this standard on January 1, 2016 with no material effect on our consolidated operations, financial position, or cash flows.
Pending.
The following new ASUs have been issued but not yet adopted:
In May 2014, the FASB issued ASU No. 2014-09,
“Revenue from Contracts with Customers (Topic 606)
,
”
in an effort to improve revenue recognition practices across entities and industries. The ASU introduces a single, principle-based revenue recognition model which centers on the core principle of an entity recognizing revenue in a manner that depicts the transfer of goods and services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. Since its release, the FASB has issued multiple amendments clarifying and/or amending ASU No. 2014-09. We have substantially completed a review of contracts with customers in relation to the requirements of ASU No. 2014-09. While we have not identified any material difference in the amount or timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete and we have not concluded on the overall impacts of adopting this standard. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support the recognition and disclosure requirements under the new standard. ASU No. 2014-09 is effective for us January 1, 2018 and allows for either full retrospective or modified retrospective adoption.
In July 2015, the FASB issued ASU No. 2015-11,
“Inventory (Topic 330): Simplifying the Measurement of Inventory,”
which simplifies the subsequent measurement of inventory by requiring inventory to be measured at the lower of cost and net realizable value. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position, or cash flows.
In January 2016, the FASB issued ASU No. 2016-01,
“Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
,
”
which amends the classification and measurement of financial instruments. Changes primarily affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This ASU is effective for us on January 1, 2018. Early adoption is not permitted. We are currently evaluating this ASU and its potential impact on us.
In February 2016, the FASB issued ASU No. 2016-02,
“Leases (Topic 842),”
to improve the financial reporting around leasing transactions. The new guidance requires companies to begin recording assets and liabilities arising from those leases classified as operating leases under previous guidance. Furthermore, the new guidance will require significant additional disclosures about the amount, timing and uncertainty of cash flows from leases. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in previous guidance. The result of retaining a distinction between finance leases and operating leases is that under the lessee accounting model in Topic 842, the effect of leases in the statement of comprehensive income and the statement of cash flows is largely unchanged from previous guidance. This ASU is effective for us January 1, 2019. We are currently evaluating this ASU and its potential impact on us.
In March 2016, the FASB issued ASU No. 2016-05,
“Derivatives and Hedging (Topic 815): Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,”
which clarifies the hedge accounting impact when there is a change in one of the counterparties to the derivative contract (i.e. novation). This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In March 2016, the FASB issued ASU No. 2016-06,
“Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments,”
which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flow.
In March 2016, the FASB issued ASU No. 2016-07,
“Investments—Equity Method and Joint Ventures (Topic 323): Simplifying the Transition to the Equity Method of Accounting,”
which eliminates the requirement to apply the equity method of accounting retrospectively when a reporting entity obtains significant influence over a previously held investment. This ASU is effective for us January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In June 2016, the FASB issued ASU No. 2016-13,
“Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
,
”
to replace the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires the consideration of a broader range of reasonable and supportable information to inform credit loss estimates. This ASU is effective for us on January 1, 2020. We are currently evaluating this ASU and its potential impact on us.
In August 2016, the FASB issued ASU No. 2016-15,
“Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,”
to provide guidance on specific cash flow issues with the objective of reducing the existing diversity in practice. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In October 2016, the FASB issued ASU No. 2016-17,
“Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control
,
”
to amend the consolidation guidance on how a reporting entity that is the single decision maker of a VIE should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. This ASU is effective for us on January 1, 2017. This ASU is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In November 2016, the FASB issued ASU No. 2016-18,
“Statement of Cash Flows (Topic 230): Restricted Cash,”
to address the diversity in the classification and presentation of changes in restricted cash and restricted cash equivalents on the statement of cash flows. The update requires that restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In January 2017, the FASB issued ASU No. 2017-01,
“Business Combinations (Topic 805): Clarifying the Definition of a Business,”
which revises the definition of a business. This ASU is effective for us on January 1, 2018. We are currently evaluating this ASU and its potential impact on us.
In January 2017, the FASB issued ASU No. 2017-04,
“Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,”
to simplify the subsequent measurement of goodwill. The guidance eliminates Step 2 from the goodwill impairment test which required computing an implied fair value to measure the amount of the goodwill impairment. A goodwill impairment will now be the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This ASU is effective for us on January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating this ASU and its potential impact on us.
The following ASUs were adopted in
2015
and the effect of such adoptions, if any, are presented in the accompanying Consolidated Financial Statements:
In April 2015, the FASB issued ASU No. 2015-03,
“Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,”
which requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as a deferred charge asset. We adopted the provisions of this ASU as of December 31, 2015. The adoption of this ASU resulted in the presentation of
$21 million
of debt issuance costs as a reduction of Long-term Debt on our December 31, 2015 Consolidated Balance Sheet.
In April 2015, the FASB issued ASU No. 2015-06,
“Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions,”
which applies to master limited partnerships that receive net assets through a dropdown transaction. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. We adopted the provisions of this ASU as of December 31, 2015. The adoption of this ASU had no material effect for the years presented on our consolidated operations, financial position, or cash flows.
There were no significant accounting pronouncements adopted in
2014
that had a material impact on our consolidated results of operations, financial position or cash flows.
2. Acquisitions and Dispositions
U.S. Assets Dropdown.
During 2013, we completed the closing of substantially all of the U.S. Assets Dropdown, excluding a
25.05%
ownership interest in SESH and a
1%
ownership interest in Steckman Ridge. This was the first of three planned transactions.
In November 2014, we completed the second of the three planned transactions related to the U.S. Assets Dropdown. This transaction consisted of acquiring an additional
24.95%
ownership interest in SESH and the remaining
1%
ownership interest in Steckman Ridge from Spectra Energy. Total consideration was approximately
4.3 million
newly issued common units. Also in connection with this transaction, we issued approximately
86,000
general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's
2%
general partner interest.
In November 2015, we acquired the remaining
0.1%
ownership interest in SESH from Spectra Energy. Total consideration was
17,114
newly issued common units. This was the last of three planned transactions related to the U.S. Assets Dropdown. Also in connection with this transaction, we issued
342
general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's
2%
general partner interest.
Disposition.
In October 2015, Spectra Energy acquired our
33.3%
ownership interests in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills). In consideration for this transaction, we retired
21,560,000
of our common units and
440,000
of our general partner units held by Spectra Energy, which will result in the reduction of distributions payable to Spectra Energy for the related units retired. Additional consideration consisted of a reduction in the aggregate quarterly distributions, if any, to Spectra Energy, as holder of incentive distribution rights, by
$4 million
per quarter for a period of 12 consecutive quarters commencing with the quarter ending on December 31, 2015 and ending with the quarter ending on September 30, 2018. The total reduction of distributions to Spectra Energy was
$16 million
for the year ended December 31, 2016. This transfer of assets between entities under common control is included as a non-cash transaction in the Consolidated Statements of Cash Flows.
3. Transactions with Affiliates
In the normal course of business, we provide natural gas transmission, storage and other services to Spectra Energy and its affiliates.
In addition, pursuant to an agreement with Spectra Energy, Spectra Energy and its affiliates perform centralized corporate functions for us, including legal, accounting, compliance, treasury and other areas. We reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes and direct expenses, including operating expenses and certain allocated operating expenses associated with the ownership and operation of the contributed assets. Spectra Energy and its affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures, as compared to Spectra Energy’s other affiliates.
Transactions with affiliates are summarized in the tables below:
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
(in millions)
|
Operating revenues
|
$
|
34
|
|
|
$
|
53
|
|
|
$
|
88
|
|
Operating, maintenance and other expenses
|
310
|
|
|
457
|
|
|
317
|
|
We are party to an agreement with DCP Midstream, LLC (DCP Midstream), an equity investment of Spectra Energy, in which DCP Midstream processes certain of our customers' gas to meet quality specifications in order to be transported on our system. DCP Midstream processes the gas and sells the natural gas liquids that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We recognized revenues of
$31 million
,
$46 million
and
$79 million
in
2016
,
2015
and
2014
, respectively, related to those services, classified as Storage of Natural Gas and Other in our Consolidated Statements of Operations.
We recorded natural gas transmission revenues from DCP Midstream and its affiliates totaling
$1 million
in
2016
,
$4 million
in
2015
and
$7 million
in
2014
, classified as Transportation of Natural Gas in our Consolidated Statements of Operations.
In addition to the above, we recorded other revenues from DCP Midstream and its affiliates totaling
$2 million
in
2016
,
$3 million
in
2015
and
$2 million
in
2014
, classified as Storage of Natural Gas and Other in our Consolidated Statements of Operations.
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(in millions)
|
Receivables
|
$
|
22
|
|
|
$
|
17
|
|
Current assets — other
|
2
|
|
|
3
|
|
Accounts payable
|
27
|
|
|
45
|
|
Current liabilities — other
|
10
|
|
|
152
|
|
Transactions billed from affiliates, included within Property, Plant and Equipment in the Consolidated Balance Sheets, were
$46 million
in
2016
and
$51 million
in
2015
.
Gulfstream
. During the third quarter of 2015, Gulfstream Natural Gas System, LLC (Gulfstream) issued unsecured debt of
$800 million
to fund the repayment of its current debt. Gulfstream distributed
$396 million
, our proportionate share of proceeds, to us, classified as Cash Flows from Investing Activities - Distributions from Equity Investments, of which we contributed
$248 million
back to Gulfstream in the fourth quarter of 2015 and the remaining
$148 million
, classified as Cash Flows from Investing Activities - Distributions to Equity Investment, in the second quarter of 2016.
SESH.
In 2014, SESH issued unsecured debt of
$400 million
to fund the repayment of its current debt. SESH distributed
$99 million
of proceeds to us, classified as Cash Flows from Investing Activities - Distributions from Equity Investments, of which we contributed
$94 million
back to SESH during 2014, classified as Cash Flows from Investing Activities - Investments in and Loans to Unconsolidated Affiliates, as the current debt matured.
See also Notes 1, 7 and 14 for discussion of specific related party transactions.
4. Business Segments
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.
Our chief operating decision maker regularly reviews financial information about both segments in deciding how to allocate resources and evaluate performance. There is no aggregation of segments within our reportable business segments.
The U.S. Transmission segment provides interstate transmission and storage of natural gas. Substantially all of our operations are subject to the Federal Energy Regulatory Commission (FERC) and the Department of Transportation’s (DOT’s) rules and regulations. Our investments in Gulfstream, SESH and Steckman Ridge are included in U.S. Transmission.
The Liquids segment provides transportation of crude oil. The Express-Platte pipeline system (Express-Platte) is a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions. These operations are primarily subject to the rules and regulations of the FERC and the National Energy Board (NEB). We held direct one-third ownership interests in Sand Hills and Southern Hills until October 30, 2015.
Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings before interest, taxes, and depreciation and amortization (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. 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.
Business Segment Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Revenues
|
|
Segment EBITDA/
Consolidated
Earnings Before
Income Taxes
|
|
Depreciation
and
Amortization
|
|
Capital and
Investment
Expenditures
|
|
Assets
|
|
(in millions)
|
2016
|
|
|
|
|
|
|
|
|
|
U.S. Transmission
|
$
|
2,167
|
|
|
$
|
1,639
|
|
|
$
|
285
|
|
|
$
|
2,514
|
|
|
$
|
19,747
|
|
Liquids
|
366
|
|
|
237
|
|
|
29
|
|
|
71
|
|
|
1,841
|
|
Total
|
2,533
|
|
|
1,876
|
|
|
314
|
|
|
2,585
|
|
|
21,588
|
|
Other
|
—
|
|
|
(82
|
)
|
|
—
|
|
|
—
|
|
|
18
|
|
Depreciation and amortization
|
—
|
|
|
314
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest expense
|
—
|
|
|
224
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest income and other
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total consolidated
|
$
|
2,533
|
|
|
$
|
1,257
|
|
|
$
|
314
|
|
|
$
|
2,585
|
|
|
$
|
21,606
|
|
2015
|
|
|
|
|
|
|
|
|
|
U.S. Transmission
|
$
|
2,087
|
|
|
$
|
1,599
|
|
|
$
|
264
|
|
|
$
|
1,952
|
|
|
$
|
17,050
|
|
Liquids
|
368
|
|
|
283
|
|
|
31
|
|
|
55
|
|
|
1,778
|
|
Total
|
2,455
|
|
|
1,882
|
|
|
295
|
|
|
2,007
|
|
|
18,828
|
|
Other
|
—
|
|
|
(66
|
)
|
|
—
|
|
|
—
|
|
|
23
|
|
Depreciation and amortization
|
—
|
|
|
295
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest expense
|
—
|
|
|
239
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest income and other
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total consolidated
|
$
|
2,455
|
|
|
$
|
1,277
|
|
|
$
|
295
|
|
|
$
|
2,007
|
|
|
$
|
18,851
|
|
2014
|
|
|
|
|
|
|
|
|
|
U.S. Transmission
|
$
|
1,939
|
|
|
$
|
1,415
|
|
|
$
|
256
|
|
|
$
|
1,160
|
|
|
$
|
15,174
|
|
Liquids
|
330
|
|
|
240
|
|
|
32
|
|
|
81
|
|
|
2,567
|
|
Total
|
2,269
|
|
|
1,655
|
|
|
288
|
|
|
1,241
|
|
|
17,741
|
|
Other
|
—
|
|
|
(64
|
)
|
|
—
|
|
|
—
|
|
|
37
|
|
Depreciation and amortization
|
—
|
|
|
288
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest expense
|
—
|
|
|
238
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest income and other
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Total consolidated
|
$
|
2,269
|
|
|
$
|
1,062
|
|
|
$
|
288
|
|
|
$
|
1,241
|
|
|
$
|
17,778
|
|
Geographic Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
Canada
|
|
Consolidated
|
|
|
(in millions)
|
2016
|
|
|
|
|
|
|
Consolidated revenues
|
|
$
|
2,456
|
|
|
$
|
77
|
|
|
$
|
2,533
|
|
Consolidated long-lived assets
|
|
19,580
|
|
|
215
|
|
|
19,795
|
|
2015
|
|
|
|
|
|
|
Consolidated revenues
|
|
$
|
2,383
|
|
|
$
|
72
|
|
|
$
|
2,455
|
|
Consolidated long-lived assets
|
|
18,104
|
|
|
203
|
|
|
18,307
|
|
2014
|
|
|
|
|
|
|
Consolidated revenues
|
|
$
|
2,205
|
|
|
$
|
64
|
|
|
$
|
2,269
|
|
Consolidated long-lived assets
|
|
16,987
|
|
|
236
|
|
|
17,223
|
|
5. Regulatory Matters
We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.
The following items are reflected in the consolidated balance sheets. All regulatory assets and liabilities are excluded from rate base unless otherwise noted below.
|
|
|
|
|
|
|
|
|
|
|
|
Recovery/Refund
Period Ends
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
|
(in millions)
|
Regulatory Assets (a)
|
|
|
|
|
|
Regulatory asset related to income taxes (b)
|
Various
|
|
$
|
297
|
|
|
$
|
221
|
|
Vacation accrual
|
Various
|
|
19
|
|
|
19
|
|
Deferred debt expense/premium
|
Various
|
|
18
|
|
|
23
|
|
Asset retirement obligations
|
Various
|
|
17
|
|
|
2
|
|
Under-recovery of fuel costs (c,d)
|
—
|
|
6
|
|
|
41
|
|
Project development costs
|
Through 2036
|
|
9
|
|
|
9
|
|
Other
|
—
|
|
10
|
|
|
11
|
|
Total Regulatory Assets
|
|
|
$
|
376
|
|
|
$
|
326
|
|
Regulatory Liabilities
|
|
|
|
|
|
Over-recovery of fuel costs (d,e)
|
—
|
|
$
|
38
|
|
|
$
|
1
|
|
Pipeline rate credit (f)
|
Life of associated liability
|
|
23
|
|
|
24
|
|
Total Regulatory Liabilities
|
|
|
$
|
61
|
|
|
$
|
25
|
|
________
(a)
Included in Regulatory Assets and Deferred Debits, unless otherwise noted.
(b) Relates to tax gross-up of the AFUDC equity portion. All amounts are expected to be included in future rate filings.
(c) Included in Fuel Tracker.
|
|
(d)
|
Includes amounts settled in cash annually through transportation rates in accordance with FERC gas tariffs.
|
(e) Included in Other Current Liabilities.
(f) Included in Deferred Credits and Other Liabilities.
6. Net Income Per Limited Partner Unit and Cash Distributions
The following table presents our net income per limited partner unit calculations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
(in millions, except per-unit
amounts)
|
Net income—controlling interests
|
$
|
1,161
|
|
|
$
|
1,225
|
|
|
$
|
1,004
|
|
Less:
|
|
|
|
|
|
General partner’s interest in net income—2%
|
23
|
|
|
24
|
|
|
20
|
|
General partner’s interest in net income attributable to incentive distribution rights
|
288
|
|
|
225
|
|
|
167
|
|
Limited partners’ interest in net income
|
$
|
850
|
|
|
$
|
976
|
|
|
$
|
817
|
|
Weighted average limited partner units outstanding—basic and diluted
|
299
|
|
|
296
|
|
|
288
|
|
Net income per limited partner unit—basic and diluted
|
$
|
2.84
|
|
|
$
|
3.30
|
|
|
$
|
2.84
|
|
Our partnership agreement requires that, within
60 days
after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.
Available Cash.
Available Cash, for any quarter, consists of all cash 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 minimum quarterly distributions to the unitholders and to the general partner for any one or more of the next four quarters,
|
|
|
•
|
plus, if the general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter.
|
Incentive Distribution Rights.
The general partner holds incentive distribution rights beyond the first target distribution in accordance with the partnership agreement as follows:
|
|
|
|
|
|
|
|
|
|
Total Quarterly Distribution
|
|
Marginal Percentage
Interest in Distributions
|
|
Target Per-Unit Amount
|
|
Common
Unitholders
|
|
General
Partner
|
Minimum Quarterly Distribution
|
$0.30
|
|
98
|
%
|
|
2
|
%
|
First Target Distribution
|
up to $0.345
|
|
98
|
%
|
|
2
|
%
|
Second Target Distribution
|
above $0.345 up to $0.375
|
|
85
|
%
|
|
15
|
%
|
Third Target Distribution
|
above $0.375 up to $0.45
|
|
75
|
%
|
|
25
|
%
|
Thereafter
|
above $0.45
|
|
50
|
%
|
|
50
|
%
|
To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common units. A cash distribution of
$0.68875
per limited partner unit was declared on
February 7, 2017
and is payable on
February 28, 2017
to unitholders of record at the close of business on
February 17, 2017
.
As a result of the sale of our interests in Sand Hills and Southern Hills to Spectra Energy, there is a reduction in the aggregate quarterly distributions, if any, to Spectra Energy, (as holder of incentive distribution rights), by
$4 million
per quarter for a period of 12 consecutive quarters ending on September 30, 2018. See Note 2 for more information.
7. Investments in and Loans to Unconsolidated Affiliates
Investments in affiliates for which we are not the primary beneficiary, but over which we have significant influence, are accounted for using the equity method. As of
December 31, 2016
and
2015
, the carrying amounts of investments in affiliates approximated the amounts of underlying equity in net assets. We received distributions from our equity investments of
$160 million
in
2016
,
$610 million
in
2015
and
$294 million
in
2014
. Cumulative undistributed earnings from equity investments totaled
$15 million
in
2016
and
$5 million
in
2015
. There were
no
cumulative undistributed earnings from equity investments in
2014
.
U.S. Transmission.
Investments are comprised of a
50%
interest in Gulfstream, a
50%
interest in SESH and a
50%
interest in Steckman Ridge.
We have a loan outstanding to Steckman Ridge in connection with the construction of its storage facilities. The loan carries market-based interest rates and is due the earlier of October 1, 2023 or coincident with the closing of any long-term financings by Steckman Ridge. The loan receivable from Steckman Ridge, including accrued interest, totaled
$71 million
at both
December 31, 2016
and
2015
.
Liquids.
Investments were comprised of
33.3%
interests in Sand Hills and Southern Hills. The Sand Hills and Southern Hills pipelines were placed in service in the second quarter of 2013 and acquired by Spectra Energy in the fourth quarter of 2015.
Earnings from Equity Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
(in millions)
|
U.S. Transmission
|
$
|
127
|
|
|
$
|
112
|
|
|
$
|
90
|
|
Liquids
|
—
|
|
|
55
|
|
|
43
|
|
Total
|
$
|
127
|
|
|
$
|
167
|
|
|
$
|
133
|
|
Summarized Combined Financial Information of Unconsolidated Affiliates (Presented at 100%)
Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
(in millions)
|
Operating revenues
|
$
|
430
|
|
|
$
|
702
|
|
|
$
|
648
|
|
Operating expenses
|
118
|
|
|
229
|
|
|
227
|
|
Operating income
|
312
|
|
|
473
|
|
|
421
|
|
Net income
|
253
|
|
|
380
|
|
|
328
|
|
Balance Sheets
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2016
|
|
2015
|
|
(in millions)
|
Current assets
|
$
|
154
|
|
|
$
|
434
|
|
Non-current assets
|
3,665
|
|
|
3,038
|
|
Current liabilities
|
112
|
|
|
345
|
|
Non-current liabilities
|
1,678
|
|
|
1,677
|
|
Equity
|
$
|
2,029
|
|
|
$
|
1,450
|
|
8. Variable Interest Entities
Sabal Trail.
On April 1, 2016, NextEra Energy, Inc. (NextEra) purchased a
9.5%
interest in Sabal Trail Transmission, LLC (Sabal Trail) from us. Consideration for this transaction consisted of approximately
$110 million
cash,
$102 million
of which is classified as Cash Flows from Financing Activities — Contributions from Noncontrolling Interests. See Note 9 for additional information related to this transaction. As of December 31, 2016, we owned a
50%
interest in Sabal Trail, a joint venture that is constructing a natural gas pipeline to transport natural gas to Florida. Sabal Trail is a variable interest entity (VIE) due to insufficient equity at risk to finance its activities. We determined that we are the primary beneficiary because we direct the activities of Sabal Trail that most significantly impact its economic performance and we consolidate Sabal Trail in our financial statements. The current estimate of the total remaining construction cost is approximately
$1.2 billion
.
The following summarizes assets and liabilities for Sabal Trail as of December 31, 2016 and December 31, 2015, respectively:
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheets
|
December 31,
|
|
2016
|
|
2015
|
|
(in millions)
|
Assets
|
|
|
|
Current assets
|
$
|
165
|
|
|
$
|
118
|
|
Net property, plant and equipment
|
1,942
|
|
|
773
|
|
Regulatory assets and deferred debits
|
79
|
|
|
25
|
|
Total Assets
|
$
|
2,186
|
|
|
$
|
916
|
|
Liabilities and Equity
|
|
|
|
Current liabilities
|
$
|
239
|
|
|
$
|
84
|
|
Equity
|
1,947
|
|
|
832
|
|
Total Liabilities and Equity
|
$
|
2,186
|
|
|
$
|
916
|
|
Nexus.
We own a
50%
interest in Nexus Gas Transmission, LLC (Nexus), a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. 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
$1.0 billion
. We have an investment in Nexus of
$356 million
and
$90 million
as of December 31, 2016 and December 31, 2015, respectively, classified as Investments in and Loans to Unconsolidated Affiliates on our Consolidated Balance Sheets.
On December 29, 2016, we issued performance guarantees to a third party and an affiliate on behalf of Nexus. See Note 17 for further discussion of the guarantee arrangement.
9. Intangible Asset
During the first quarter of 2016 we entered into a project coordination agreement (PCA) with NextEra, Duke Energy Corporation and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in the Sabal Trail project, as certain milestones of the project are met. During the first quarter of 2016, the first milestone was achieved and paid, consisting of
$48 million
.
On April 1, 2016, NextEra purchased an additional
9.5%
interest in Sabal Trail, reducing our ownership interest in Sabal Trail to
50%
. Upon purchase of the additional ownership interest, NextEra reimbursed us
$8 million
for NextEra’s proportional share of the first milestone payment, which reduced our total milestone payments to
$40 million
as of June 30, 2016.
During the third quarter of 2016, the second milestone was achieved and paid, consisting of an additional payment of
$40 million
, for total milestone payments of
$80 million
as of December 31, 2016. Both payments are classified as Cash Flows from Investing Activities — Purchase of Intangible, Net. This PCA is an intangible asset and is classified as Investments and Other Assets — Other on our Condensed Consolidated Balance Sheet. The intangible asset will be amortized over a period of
25
years beginning at the time of in-service of Sabal Trail, which is expected to occur during the first half of 2017.
10. 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 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 HTM marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Consolidated Statements of Cash Flows.
AFS Securities.
We had
$10 million
and
$11 million
of AFS securities classified as Investments and Other Assets — Other on Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015, respectively. As December 31, 2016, these investments include
$9 million
of restricted funds related to certain construction projects and
$1 million
are restricted funds held and collected from customers for Canadian pipeline abandonment in accordance with the NEB's regulatory requirements. The balance as of December 31, 2015 is all related to certain construction projects.
At December 31, 2016, 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 December 31, 2016 or December 31, 2015.
HTM Securities.
All of our HTM securities are restricted funds. We had
$3 million
of money market securities classified as Current Assets — Other on the Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015. These securities are restricted pursuant to certain Express-Platte debt agreements.
At December 31, 2016, 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 December 31, 2016 or December 31, 2015.
Interest income.
We had interest income of
$2 million
in 2016 and
$1 million
in 2015, which is included in Other Income and Expenses, Net on the Consolidated Statements of Operations. We had
no
interest income in 2014.
Other Restricted Funds.
In addition to the AFS and HTM securities that were restricted funds as described above, we had other restricted funds totaling
$5 million
and
$14 million
classified as Investments and Other Assets — Other on the Consolidated Balance Sheets at December 31, 2016 and December 31, 2015, respectively. These restricted funds are related to certain construction projects.
Changes in restricted balances are presented within Cash Flows from Investing Activities on our Consolidated Statements of Cash Flows.
11. Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Useful Life
|
|
December 31,
|
|
2016
|
|
2015
|
|
(years)
|
|
(in millions)
|
Plant
|
|
|
|
|
|
Natural gas transmission
|
2-100
|
|
|
$
|
13,702
|
|
|
$
|
12,424
|
|
Natural gas storage
|
17-122
|
|
|
1,638
|
|
|
1,617
|
|
Gathering and processing facilities
|
10-40
|
|
|
3
|
|
|
3
|
|
Crude oil transportation and storage
|
5-75
|
|
|
1,321
|
|
|
1,206
|
|
Land rights and rights of way
|
10-122
|
|
|
510
|
|
|
474
|
|
Other buildings and improvements
|
5-75
|
|
|
37
|
|
|
37
|
|
Equipment
|
3-75
|
|
|
81
|
|
|
80
|
|
Vehicles
|
3-15
|
|
|
12
|
|
|
12
|
|
Land
|
—
|
|
|
75
|
|
|
71
|
|
Construction in process
|
—
|
|
|
2,494
|
|
|
1,484
|
|
Software
|
5-15
|
|
|
11
|
|
|
12
|
|
Other
|
15-82
|
|
|
74
|
|
|
71
|
|
Total property, plant and equipment
|
|
|
19,958
|
|
|
17,491
|
|
Total accumulated depreciation
|
|
|
(3,741
|
)
|
|
(3,533
|
)
|
Total accumulated amortization
|
|
|
(125
|
)
|
|
(121
|
)
|
Total net property, plant and equipment
|
|
|
$
|
16,092
|
|
|
$
|
13,837
|
|
We had
no
capital leases at
December 31, 2016
or
December 31, 2015
.
Approximately
86%
of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. Composite weighted-average depreciation rates were
2%
for
2016
,
2015
and
2014
.
Amortization expense of intangible assets totaled
$9 million
in
2016
and
$10 million
in both
2015
and
2014
. Estimated amortization expense for the next five years follows:
|
|
|
|
|
|
Estimated Amortization Expense
|
|
|
(in millions)
|
2017
|
$
|
11
|
|
2018
|
|
11
|
|
2019
|
|
11
|
|
2020
|
|
10
|
|
2021
|
|
8
|
|
12. Asset Retirement Obligations
Our AROs relate mostly to the retirement of offshore pipelines and certain onshore assets, obligations related to right-of-way agreements and contractual leases for land use. However, we have determined that a significant portion of our assets have an indeterminate life, and as such, the fair values of those associated retirement obligations are not reasonably estimable. These assets include onshore and some offshore pipelines, and certain storage facilities, whose retirement dates will depend mostly on the various natural gas supply sources that connect to our systems and the ongoing demand for natural gas usage in the markets we serve. We expect these supply sources and market demands to continue for the foreseeable future, therefore we are unable to estimate retirement dates that would result in asset retirement obligations.
AROs are adjusted each period for liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. 2015 revisions mainly include a reduction in the remaining estimated life of certain Texas Eastern Transmission, LP (Texas Eastern) offshore facilities, and resulted in a net increase to ARO liabilities of
$27 million
.
Reconciliation of Changes in Asset Retirement Obligation Liabilities
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
(in millions)
|
Balance at Beginning of year
|
$
|
48
|
|
|
$
|
20
|
|
Accretion expense
|
2
|
|
|
1
|
|
Revisions in estimated cash flows
|
(4
|
)
|
|
27
|
|
Balance at the end of the year (a)
|
$
|
46
|
|
|
$
|
48
|
|
_________
|
|
(a)
|
Amounts included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.
|
13. Debt and Credit Facility
Summary of Debt and Related Terms
|
|
|
|
|
|
|
|
|
|
December 31,
|
2016
|
|
2015
|
|
(in millions)
|
Spectra Energy Partners, LP 2.95% senior unsecured notes due June 2016
|
$
|
—
|
|
|
$
|
250
|
|
Spectra Energy Partners, LP 2.95% senior unsecured notes due September 2018
|
500
|
|
|
500
|
|
Spectra Energy Partners, LP variable-rate senior unsecured term loan due November 2018
|
400
|
|
|
400
|
|
Spectra Energy Partners, LP 4.60% senior unsecured notes due June 2021
|
250
|
|
|
250
|
|
Spectra Energy Partners, LP 4.75% senior unsecured notes due March 2024
|
1,000
|
|
|
1,000
|
|
Spectra Energy Partners, LP 3.50% senior unsecured notes due March 2025
|
500
|
|
|
500
|
|
Spectra Energy Partners, LP 3.375% senior unsecured notes due October 2026
|
600
|
|
|
—
|
|
Spectra Energy Partners, LP 5.95% senior unsecured notes due September 2043
|
400
|
|
|
400
|
|
Spectra Energy Partners, LP 4.50% senior unsecured notes due March 2045
|
700
|
|
|
500
|
|
Texas Eastern 6.00% senior unsecured notes due September 2017
|
400
|
|
|
400
|
|
Texas Eastern 4.125% senior unsecured notes due December 2020
|
300
|
|
|
300
|
|
Texas Eastern 2.80% senior unsecured notes due October 2022
|
500
|
|
|
500
|
|
Texas Eastern 7.00% senior unsecured notes due July 2032
|
450
|
|
|
450
|
|
Algonquin Gas Transmission 3.51% senior unsecured notes due July 2024
|
350
|
|
|
350
|
|
East Tennessee Natural Gas, LLC 3.10% senior unsecured notes due December 2024
|
200
|
|
|
200
|
|
Express-Platte 6.09% senior secured notes due January 2020
|
110
|
|
|
110
|
|
Express-Platte 7.39% subordinated secured notes due 2017 to 2019
|
12
|
|
|
42
|
|
Long-term debt principal (including current maturities)
|
6,672
|
|
|
6,152
|
|
Change in fair value of debt hedged
|
4
|
|
|
9
|
|
Unamortized debt discount, net
|
(11
|
)
|
|
(12
|
)
|
Unamortized debt expenses
|
(26
|
)
|
|
(21
|
)
|
Commercial paper (a)
|
574
|
|
|
476
|
|
Total debt
|
7,213
|
|
|
6,604
|
|
Current maturities of long-term debt
|
(416
|
)
|
|
(283
|
)
|
Commercial paper (b)
|
(574
|
)
|
|
(476
|
)
|
Total long-term debt
|
$
|
6,223
|
|
|
$
|
5,845
|
|
_________
(a)
The weighted-average days to maturity were
17 days
as of December 31, 2016 and
13 days
as of December 31, 2015.
|
|
(b)
|
Weighted-average rates outstanding on commercial paper were
1.12%
as of December 31, 2016 and
0.96%
as of December 31, 2015.
|
Secured Debt.
Secured debt, totaling
$122 million
as of December 31, 2016, includes project financings for Express-Platte. The notes are secured by the assignment of the Express-Platte transportation receivables and by the Express Canada assets.
Floating Rate Debt.
Debt included approximately
$974 million
of floating-rate debt as of December 31, 2016 and
$876 million
as of December 31, 2015. The weighted average interest rate of borrowings outstanding that contained floating rates was
1.44%
at December 31, 2016 and
1.22%
at December 31, 2015.
Annual Maturities
|
|
|
|
|
|
December 31, 2016
|
|
(in millions)
|
2017
|
$
|
412
|
|
2018
|
900
|
|
2019
|
—
|
|
2020
|
410
|
|
2021
|
250
|
|
Thereafter
|
4,700
|
|
Total long-term debt, including current maturities (a)
|
$
|
6,672
|
|
_________
(a)
Excludes commercial paper of
$574 million
.
We have the ability under certain debt facilities to repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.
Credit Facility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
Date
|
|
Total
Credit Facility
Capacity
|
|
Commercial
Paper Outstanding at
December 31,
2016
|
|
Available
Credit Facility
Capacity
|
|
|
|
(in millions)
|
Spectra Energy Partners, LP
|
2021
|
|
$
|
2,500
|
|
|
$
|
574
|
|
|
$
|
1,926
|
|
On April 29, 2016, we amended our credit agreement. The total capacity was increased to
$2.5 billion
and the expiration date was extended to April 2021.
The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of
December 31, 2016
, there were no letters of credit issued or revolving borrowings outstanding under the credit facility.
Our credit agreements contain various covenants, including the maintenance of a consolidated leverage ratio, as defined in the agreements. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of
December 31, 2016
, we were in compliance with those covenants. In addition, our credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of our other significant indebtedness or other significant indebtedness of some of our subsidiaries. Our credit agreements do not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
As noted above, the terms of our credit agreements require us to maintain a ratio of total Consolidated Indebtedness-to-Consolidated EBITDA, as defined in the agreements, of
5.0
to 1 or less. As of
December 31, 2016
, this ratio was
3.8
to 1.
14. Fair Value Measurements
The following presents, for each of the fair value hierarchy levels, assets that are measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheet Caption
|
December 31, 2016
|
Description
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(in millions)
|
Corporate debt securities
|
Cash and cash equivalents
|
$
|
145
|
|
|
$
|
—
|
|
|
$
|
145
|
|
|
$
|
—
|
|
Corporate debt securities
|
Investments and other assets — other
|
9
|
|
|
—
|
|
|
9
|
|
|
—
|
|
Canadian equity securities
|
Investments and other assets — other
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
Interest rate swaps
|
Investments and other assets — other
|
9
|
|
|
—
|
|
|
9
|
|
|
—
|
|
Total Assets
|
$
|
164
|
|
|
$
|
1
|
|
|
$
|
163
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Balance Sheet Caption
|
December 31, 2015
|
Description
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(in millions)
|
Corporate debt securities
|
Cash and cash equivalents
|
$
|
112
|
|
|
$
|
—
|
|
|
$
|
112
|
|
|
$
|
—
|
|
Corporate debt securities
|
Investments and other assets — other
|
11
|
|
|
—
|
|
|
11
|
|
|
—
|
|
Interest rate swaps
|
Investments and other assets — other
|
14
|
|
|
—
|
|
|
14
|
|
|
—
|
|
Total Assets
|
$
|
137
|
|
|
$
|
—
|
|
|
$
|
137
|
|
|
$
|
—
|
|
Level 1
Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Level 2 Valuation Techniques
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 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 Valuation Techniques
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
Consolidated Balance Sheet Caption
|
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)
|
6,672
|
|
|
6,855
|
|
|
6,152
|
|
|
5,906
|
|
________
(a)
Included within Investments in and Loans to Unconsolidated Affiliates.
(b)
Excludes unamortized items and fair value hedge carrying value adjustments.
The fair value of long-term debt is determined based on market-based prices as described in the Level 2 valuation technique described above and are classified as Level 2.
The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, note receivable-noncurrent, accounts payable, commercial paper and short-term money market securities are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
During the
2016
and
2015
periods, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.
15. Risk Management and Hedging Activities
Interest Rate Swaps
. Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure. For interest rate derivative instruments that 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 Consolidated Statements of Operations. There were
no
significant amounts of gains or losses recognized in net income in 2016, 2015 or 2014.
At
December 31, 2016
, 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 debt that arise as a result of changes in market interest rates. These interest rate swaps expire in
2018
and thereafter. These swaps also allow us to transform a portion of the underlying interest payments related to our long-term fixed-rate debt securities into variable-rate interest payments in order to achieve our desired mix of fixed and variable-rate debt.
Information about our interest rate swaps that had netting or rights of offset arrangements are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
Gross Amounts
Presented in
the Consolidated
Balance Sheets
|
|
Amounts Not
Offset in the
Consolidated Balance Sheets
|
|
Net
Amount
|
|
Gross Amounts
Presented in
the Consolidated
Balance Sheets
|
|
Amounts Not
Offset in the
Consolidated Balance Sheets
|
|
Net
Amount
|
Description
|
(in millions)
|
Assets
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Our floating-to-fixed interest rate swaps expired or were terminated in 2011 in conjunction with the pay down of our credit facility and were designated and qualified as cash flow hedges. The reclassifications from Other Comprehensive Income into income on derivatives are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
Consolidated Statements of Operations Caption
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
(in millions)
|
Interest rate swaps
|
|
Interest expense
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
Foreign Currency Risk
. We are exposed to minimal foreign currency risk from our Express Canada operations.
Credit Risk.
Our principal customers for natural gas transmission and storage services are local distribution companies, industrial end-users, and natural gas marketers located throughout the United States and Canada. Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the United States. Other customers include oil producers and marketing entities. We have concentrations of receivables from these sectors throughout these regions. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits, or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract.
16. Commitments and Contingencies
General Insurance
We are insured through Spectra Energy’s master insurance program for insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes: (1) commercial general and excess liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) directors and officers liability insurance; and (5) onshore replacement value property insurance, including machinery breakdown, business interruption and extra expense. All coverages are subject to certain deductibles, terms, exclusions, and conditions common for companies with similar types of operations.
Environmental
We are subject to various federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.
Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliated operations.
Litigation
Litigation and Legal Proceedings.
We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contract and payment claims, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.
Legal costs related to the defense of loss contingencies are expensed as incurred. We had no material reserves for legal matters recorded as of
December 31, 2016
or
2015
related to litigation.
Operating Lease Commitments
We lease assets in various areas of our operations. Consolidated rental expense for operating leases classified in Net Income was
$22 million
in
2016
,
$23 million
in
2015
and
$21 million
in
2014
, which is included in Operating, Maintenance and Other on the Consolidated Statements of Operations. The following is a summary of future minimum lease payments under operating leases which at inception had noncancellable terms of more than one year. We had no capital lease commitments at
December 31, 2016
.
|
|
|
|
|
|
Long-term Operating Leases
|
|
(in millions)
|
2017
|
$
|
17
|
|
2018
|
20
|
|
2019
|
19
|
|
2020
|
18
|
|
2021
|
16
|
|
Thereafter
|
122
|
|
Total future minimum lease payments
|
$
|
212
|
|
17. 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 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.
On December 29, 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
December 31, 2016
was
$50 million
. These performance guarantees expire in 2032.
As of
December 31, 2016
, the amounts recorded for the guarantees described above are not material, both individually and in the aggregate.
18. Issuances of Common Units
In April 2016, we issued
10.4 million
common units and
0.2 million
general partner units to Spectra Energy in a private placement transaction. Total net proceeds were
$489 million
, including
$10 million
for general partner units in order to maintain Spectra Energy's
2%
general partner interest. We used the proceeds from this purchase for general partnership purposes, including the funding of our current expansion capital plan.
In November 2015, we issued
17,114
common units in connection with the U.S. Assets Dropdown, valued at
$1 million
. In addition, we issued
342
general partner units to Spectra Energy in exchange for the same amount of common units in order to maintain Spectra Energy's
2%
general partner interest.
In November 2014, we issued
4.3 million
common units and
86,000
general partner units to Spectra Energy in connection with the U.S. Assets Dropdown, valued at
$186 million
. See Note 2 for further discussion of this transaction.
We have entered into equity distribution agreements for our at-the-market offering program, pursuant to which we may offer and sell, through sales agents, common units representing limited partner interests at prices we deem appropriate having aggregate offering prices ranging from
$400 million
to up to
$1 billion
. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the New York Stock Exchange (NYSE), in block transactions, or as otherwise agreed to between the sales agent and us. We intend to use the net proceeds from sales under the program for general partnership purposes, which may include debt repayment, future acquisitions and capital expenditures.
During the year ended December 31, 2016, we issued
12.8 million
common units to the public under this program, and approximately
262,000
general partner units to Spectra Energy. Total net proceeds were
$591 million
, including approximately
$12 million
of proceeds from Spectra Energy.
During the year ended December 31, 2015, we issued
12.0 million
common units to the public under this program, and
245,000
general partner units to Spectra Energy. Total net proceeds were
$557 million
, including
$11 million
of proceeds from Spectra Energy.
During the year ended December 31, 2014, we issued
6.4 million
common units to the public under this program, and
132,000
general partner units to Spectra Energy. Total net proceeds were
$334 million
, including
$7 million
of proceeds from Spectra Energy.
19. Equity-Based Compensation
Phantom units are granted under a Long-Term Incentive Plan to certain employees of Spectra Energy and vest over
three
years. We did not award phantom units in
2016
, 2015 or 2014. The remaining
7,500
units vested in
2015
. There were no units vested in 2014.
We account for the phantom units as liability awards. Compensation expense for these awards was not significant in
2016
,
2015
or
2014
.
20. Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
|
Total
|
|
(in millions, except per-unit amounts)
|
2016
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
624
|
|
|
$
|
618
|
|
|
$
|
628
|
|
|
$
|
663
|
|
|
$
|
2,533
|
|
Operating income
|
324
|
|
|
305
|
|
|
280
|
|
|
319
|
|
|
1,228
|
|
Net income
|
311
|
|
|
305
|
|
|
296
|
|
|
327
|
|
|
1,239
|
|
Net income—controlling interests
|
298
|
|
|
287
|
|
|
275
|
|
|
301
|
|
|
1,161
|
|
Net income per limited partner unit (a)
|
0.80
|
|
|
0.71
|
|
|
0.64
|
|
|
0.70
|
|
|
2.84
|
|
2015
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
606
|
|
|
$
|
603
|
|
|
$
|
612
|
|
|
$
|
634
|
|
|
$
|
2,455
|
|
Operating income
|
311
|
|
|
322
|
|
|
319
|
|
|
321
|
|
|
1,273
|
|
Net income
|
301
|
|
|
316
|
|
|
331
|
|
|
317
|
|
|
1,265
|
|
Net income—controlling interests
|
293
|
|
|
307
|
|
|
321
|
|
|
304
|
|
|
1,225
|
|
Net income per limited partner unit (a)
|
0.80
|
|
|
0.83
|
|
|
0.85
|
|
|
0.82
|
|
|
3.30
|
|
|
|
(a)
|
Quarterly net income per limited partner unit amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding and changes in outstanding units.
|